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 June 30, 2008

¨	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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
		(Do not check if a smaller reporting company)

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

At June 30, 2008, 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
	Glossary of Terms	3

PART I. Financial Information

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income – Three and Six Months Ended June 30, 2008 and 2007	4

	Consolidated Balance Sheets – June 30, 2008 and December 31, 2007	5

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2008 and 2007	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	30

PART II. Other Information

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

Item 4.	Submission of Matters to a Vote of Security Holders	31

Item 6.	Exhibits	32

PAGE 2

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:


Abbreviation or Acronym		Definition
AOCI		Accumulated other comprehensive income (loss)
affiliates		Other Dominion subsidiaries
CEO		Chief Executive Officer
CFO		Chief Financial Officer
Dominion		Dominion Resources, Inc.
DRS		Dominion Resources Services, Inc., a subsidiary of Dominion
DVP		Dominion Virginia Power operating segment
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation No.
FSP		FASB Staff Position
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
kWh		Kilowatt-hour
Ladysmith		Ladysmith power station
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Mw		Megawatt
mwhrs		Megawatt hours
North Anna		North Anna power station
Norfolk Southern		Norfolk Southern Railway Company
North Carolina Commission		North Carolina Utilities Commission
NRC		Nuclear Regulatory Commission
ODEC		Old Dominion Electric Cooperative
PJM		PJM Interconnection, LLC
RTO		Regional transmission organization
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
U.S.		United States of America
VIEs		Variable interest entities
Virginia City Hybrid Energy Center		A 585 Mw (nominal) coal-fired electric generation facility to be located in Wise County, Virginia
Virginia Commission		Virginia State Corporation Commission

PAGE 3

VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
	2008		2007			2008		2007
(millions)
Operating Revenue	$	1,546	$	1,424		$	3,070	$	2,867

Operating Expenses
Electric fuel and energy purchases		557		661			1,080		1,336
Purchased electric capacity		97		107			203		223
Other energy-related commodity purchases		3		8			7		16
Other operations and maintenance:
Affiliated suppliers		90		78			176		156
Other		214		196			403		402
Depreciation and amortization		150		140			299		274
Other taxes		45		43			94		88

Total operating expenses		1,156		1,233			2,262		2,495

Income from operations		390		191			808		372

Other income		9		17			18		40
Interest and related charges:
Interest expense		74		75			145		129
Interest expense—junior subordinated notes payable to affiliated trust		4		7			12		15

Total interest and related charges		78		82			157		144

Income before income tax expense		321		126			669		268
Income tax expense		121		47			247		100

Income before extraordinary item		200		79			422		168
Extraordinary item⁽¹⁾		—		(158	)		—		(158	)

Net Income (Loss)		200		(79	)		422		10
Preferred dividends		4		4			8		8

Balance available for common stock	$	196	$	(83	)	$	414	$	2

⁽¹⁾	Reflects a $259 million ($158 million after-tax) extraordinary charge in connection with the reapplication of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to the Virginia jurisdiction of our generation operations.

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

PAGE 4

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2008			December 31, 2007⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	50		$	49
Customer accounts receivable (less allowance for doubtful accounts of $8 at both dates)		793			763
Affiliated receivables		1			53
Other receivables (less allowance for doubtful accounts of $7 and $9)		35			58
Inventories (average cost method)		513			520
Prepayments		155			165
Derivative assets		259			33
Other		59			59

Total current assets		1,865			1,700

Investments
Nuclear decommissioning trust funds		1,241			1,339
Other		3			16

Total investments		1,244			1,355

Property, Plant and Equipment
Property, plant and equipment		22,660			21,838
Accumulated depreciation and amortization		(8,907	)		(8,702	)

Total property, plant and equipment, net		13,753			13,136

Deferred Charges and Other Assets
Regulatory assets		987			564
Other		344			308

Total deferred charges and other assets		1,331			872

Total assets	$	18,193		$	17,063

⁽¹⁾

The Consolidated Balance Sheet at December 31, 2007 has been derived from the audited Consolidated Financial Statements at that date, and includes the impact of adopting FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts, as discussed in Note 3.

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

PAGE 5

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	June 30, 2008		December 31, 2007⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	256	$	286
Short-term debt		690		257
Accounts payable		544		573
Payables to affiliates		118		80
Affiliated current borrowings		—		114
Other		477		473

Total current liabilities		2,085		1,783

Long-Term Debt
Long-term debt		5,524		4,904
Junior subordinated notes payable to affiliated trust		—		412

Total long-term debt		5,524		5,316

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,461		2,237
Regulatory liabilities		1,131		1,009
Other		985		920

Total deferred credits and other liabilities		4,577		4,166

Total liabilities		12,186		11,265

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		1,109		1,109
Retained earnings		1,231		1,015
Accumulated other comprehensive income		22		29

Total common shareholder’s equity		5,750		5,541

Total liabilities and shareholder’s equity	$	18,193	$	17,063

⁽¹⁾	The Consolidated Balance Sheet at December 31, 2007 has been derived from the audited Consolidated Financial Statements at that date, and includes the impact of adopting FSP No. FIN 39-1, as discussed in Note 3.

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

PAGE 6

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2008			2007
(millions)
Operating Activities
Net income	$	422		$	10
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		346			317
Deferred income taxes and investment tax credits, net		223			(2	)
Extraordinary item, net of income taxes		—			158
Other		(35	)		(23	)
Changes in:
Accounts receivable		(7	)		(99	)
Affiliated accounts receivable and payable		91			1
Inventories		8			48
Prepayments		10			76
Deferred fuel expenses, net		(382	)		69
Accounts payable		(24	)		61
Accrued interest, payroll and taxes		(10	)		(18	)
Other operating assets and liabilities		(55	)		79

Net cash provided by operating activities		587			677

Investing Activities
Plant construction and other property additions		(848	)		(460	)
Purchases of nuclear fuel		(66	)		(66	)
Purchases of securities		(243	)		(279	)
Proceeds from sales of securities		209			263
Other		67			9

Net cash used in investing activities		(881	)		(533	)

Financing Activities
Issuance of short-term debt, net		433			296
Repayment of affiliated current borrowings, net		(114	)		(140	)
Repayment of affiliated notes payable		(412	)		—
Issuance of long-term debt		630			600
Repayment of long-term debt		(39	)		(726	)
Common dividend payments		(198	)		(142	)
Preferred dividend payments		(8	)		(8	)
Other		3			(17	)

Net cash provided by (used in) financing activities		295			(137	)

Increase in cash and cash equivalents		1			7
Cash and cash equivalents at beginning of period		49			18

Cash and cash equivalents at end of period	$	50		$	25

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

PAGE 7

VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

The Company is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of June 30, 2008, 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, a regional transmission organization (RTO), and our electric transmission facilities are integrated into the PJM wholesale electricity markets. All of our common stock is owned by our parent company, Dominion.

We manage our daily operations through two primary operating segments: Dominion Virginia Power (DVP) and Generation. In addition, we also report a Corporate and Other segment that primarily includes specific items attributable to our operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. Our assets remain wholly owned by us and our legal subsidiaries.

The terms “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 or more of its 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 SEC, 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 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, 2007 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008.

In our opinion, our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of June 30, 2008, our results of operations for the three and six months ended June 30, 2008 and 2007, and our cash flows for the six months ended June 30, 2008 and 2007.

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.

In accordance with GAAP, we report certain contracts and instruments at fair value. Observable market prices 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 6 for further information on fair value measurements in accordance with SFAS No. 157, Fair Value Measurements.

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 2007 Consolidated Financial Statements and Notes have been recast to conform to the 2008 presentation. See Note 3 for discussion of certain 2007 amounts that have been recast due to the adoption of FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

PAGE 8

Note 3. Newly Adopted Accounting Standards

SFAS No. 157

We adopted the provisions of SFAS No. 157, effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.

Generally, the provisions of this statement are 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. Retrospective application did not result in a cumulative effect of accounting change in retained earnings as of January 1, 2008.

In February 2008, the FASB issued FSP FAS No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13, which excludes leasing transactions from the scope of SFAS No. 157. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of SFAS No. 157.

In February 2008, the FASB issued FSP FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). For the Company, this delays the effective date of SFAS No. 157 primarily for intangibles, property, plant and equipment and asset retirement obligations.

In January 2008, the FASB proposed FSP FAS No. 157-c, Measuring Liabilities under FASB Statement No. 157, which if issued, would clarify the principles in SFAS No. 157 for fair value measurements of liabilities. Specifically, this FSP would require an entity to measure liabilities first based on a quoted price in an active market for an identical liability, however in the absence of such information, an entity would be allowed to measure the fair value of the liability at the amount it would receive as proceeds if it were to issue that liability at the measurement date.

See Note 6 for further information on fair value measurements in accordance with SFAS No. 157.

SFAS No. 159

The provisions of SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, became effective for us beginning January 1, 2008. 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. As of June 30, 2008, we had not elected the fair value option for any eligible items. Therefore, the provisions of SFAS No. 159 have not impacted our results of operations or financial condition.

FSP FIN 39-1

The provisions of FSP FIN 39-1 became effective for us beginning January 1, 2008. 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. Upon our adoption of FSP FIN 39-1, we revised our accounting policy to no longer offset fair value amounts recognized for certain derivative instruments and recast our prior year Consolidated Balance Sheet in order to retrospectively apply the standard. The adoption of FSP FIN 39-1 resulted in a $6 million increase in both Derivative assets and Other current liabilities as of December 31, 2007. The adoption of FSP FIN 39-1 had no impact on our results of operations or cash flows.

PAGE 9

Note 4. Recently Issued Accounting Standards

SFAS No. 141R

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. SFAS No. 141R also requires disclosure of information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, SFAS No. 141R requires that acquisition-related costs be expensed as incurred. The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. SFAS No. 141R further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties and acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances. For acquisitions completed before June 30, 2008, we do not expect these SFAS No. 141R provisions to have a material impact on our future results of operations or financial condition.

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS No. 161 requires enhancements to disclosures regarding derivative instruments and hedging activities accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The enhancements include additional disclosures regarding the reasons derivative instruments are used, how they are used, how these instruments and their related hedged items are accounted for under SFAS No. 133, as well as the impact of these derivative instruments on an entity’s results of operations, financial condition and cash flows. In addition, SFAS No. 161 requires the disclosure of the fair values of derivative instruments, gains and losses in a tabular format and derivative features that are credit-risk related. The provisions of SFAS No. 161 will become effective for us beginning January 1, 2009, and will have no impact on our results of operations or financial condition.

Note 5. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
(millions)
Net income (loss)	$	200		$	(79	)	$	422		$	10
Other comprehensive 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⁽¹⁾		—			(19	)		1			(12	)
Other, net of tax⁽²⁾		(3	)		(115	)		(8	)		(117	)

Other comprehensive loss		(3	)		(134	)		(7	)		(129	)

Total comprehensive income (loss)	$	197		$	(213	)	$	415		$	(119	)

⁽¹⁾

2007 amounts reflect the impact of the reclassification of derivative-related amounts previously recorded in AOCI to regulatory liabilities, as a result of the reapplication of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to the Virginia jurisdiction of our generation operations.

⁽²⁾

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

PAGE 10

Note 6. Fair Value Measurements

As described in Note 3, we adopted SFAS No. 157 effective January 1, 2008. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, SFAS No. 157 permits the use of a mid-market pricing convention (the mid-point between bid and ask prices). SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. SFAS No. 157 also requires fair value measurements to assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). We apply fair value measurements to certain assets and liabilities, including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments in accordance with the requirements described above.

In accordance with SFAS No. 157, we maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect our market assumptions.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. We use other option models under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

We also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:

•

Level 1 – Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, listed equities and Treasury securities.

•

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps, interest rate swaps, and municipal bonds held in nuclear decommissioning trust funds.

•

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 include long-dated and modeled commodity derivatives and financial transmission rights (FTRs).

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

PAGE 11

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3. The following table presents, for each hierarchy level, our assets and liabilities including both current and noncurrent portions, measured at fair value on a recurring basis as of June 30, 2008:


	Level 1		Level 2		Level 3		Total
(millions)
Assets:
Derivatives	$	—	$	75	$	219	$	294
Investments		298		837		—		1,135

Total	$	298	$	912	$	219	$	1,429

Liabilities:
Derivatives	$	—	$	3	$	9	$	12

The following table presents the changes in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the six months ended June 30, 2008:


	Derivatives ⁽¹⁾
(millions)
Balance at January 1, 2008	$	(4	)
Total realized and unrealized gains or (losses):
Included in earnings		89
Included in other comprehensive income (loss)		—
Included in regulatory and other assets/liabilities		200
Purchases, issuances and settlements		(75	)
Transfers out of Level 3		—

Balance at June 30, 2008	$	210

The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date	$	15

⁽¹⁾ Derivative assets and liabilities are presented on a net basis.

The following table presents gains and losses included in earnings in the Level 3 fair value category for the three and six months ended June 30, 2008:


	Electric Fuel and Energy Purchases		Other Operations and Maintenance		Total
(millions)
Three Months Ended June 30, 2008
Total gains or (losses) included in earnings	$	34	$	36	$	70
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date		—		15		15
Six Months Ended June 30, 2008
Total gains or (losses) included in earnings		42		47		89
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date		—		15		15

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Note 7. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products, 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 2 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, for certain 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 related transactions impact earnings.

For the three and six months ended June 30, 2008 and 2007, gains or losses on hedging instruments excluded from the measurement of effectiveness or determined to be ineffective were not material.

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 June 30, 2008:


	AOCI After Tax		Amounts Expected to be Reclassified to Earnings during the next 12 Months After Tax		Maximum Term
(millions)
Electric capacity	$	7	$	4	47 months
Other		1		1	119 months

Total	$	8	$	5

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

As discussed in Note 14 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, 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.

We have long-term power and capacity contracts with four variable interest entities (VIEs), which contain certain variable pricing mechanisms to the counterparty in the form of partial fuel reimbursement. We have concluded we are not the primary beneficiary of any of these VIEs. The contracts expire at various dates ranging from 2015 to 2021. We are not subject to any risk of loss from these VIEs other than our remaining purchase commitments which totaled $2 billion as of June 30, 2008. We paid $50 million and $54 million for electric capacity and $45 million and $36 million for electric energy to these entities for the three months ended June 30, 2008 and 2007, respectively. We paid $102 million and $109 million for electric capacity and $92 million and $77 million for electric energy to these entities for the six months ended June 30, 2008 and 2007, respectively.

We purchased shared services from Dominion Resources Services, Inc. (DRS), an affiliated VIE of which we are not the primary beneficiary, of approximately $90 million and $78 million during the three months ended June 30, 2008 and 2007, respectively, and $176 million and $156 million during the six months ended June 30, 2008 and 2007, respectively.

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 with Dominion dated February 2006, 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.

PAGE 13

At June 30, 2008, total outstanding commercial paper supported by the joint credit facility was $1.1 billion, of which our borrowings were $690 million, and the total amount of letter of credit issuances was $733 million, of which $13 million were issued on our behalf.

At June 30, 2008, capacity available under the joint credit facility was $1.1 billion.

Long-Term Debt

In November 2007, we borrowed $14 million in connection with the Economic Development Authority of the County of Chesterfield’s issuance of its Solid Waste and Sewage Disposal Revenue Bonds, Series 2007 A, which mature in 2031 and bear a coupon rate of 5.6%. The bonds were issued pursuant to a trust agreement whereby funds are withdrawn from the trust as improvements are made at our Chesterfield power station. We have withdrawn $6 million from the trust as of June 30, 2008.

In January 2008, we borrowed $30 million in connection with the Economic Development Authority of the City of Chesapeake Pollution Control Refunding Revenue Bonds, Series 2008 A, which mature in 2032 and bear an initial coupon rate of 3.6% for the first five years, after which they will bear interest at a market rate to be determined at that time. The proceeds were used to refund the principal amount of the Industrial Development Authority of the City of Chesapeake Money Market Municipals Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in February 2008.

In April 2008, we issued $600 million of 5.4% senior notes that mature in 2018. The proceeds were used for general corporate purposes, including the repayment of short-term debt and the redemption of all 16 million units of the $400 million 7.375% Virginia Power Capital Trust II preferred securities (including the related $412 million 7.375% unsecured Junior Subordinated Notes) due July 30, 2042. These securities were called for redemption in April 2008 and redeemed in May 2008 at a price of $25 per preferred security plus accrued and unpaid distributions.

Including the amounts discussed above, we repaid $451 million of long-term debt and notes payable during the six months ended June 30, 2008.

Note 10. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding commitments and contingencies as disclosed in Note 21 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, or Note 11 to the Consolidated Financial Statements in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, nor have any significant new matters arisen during the three months ended June 30, 2008.

Litigation

We are co-owners with Old Dominion Electric Cooperative (ODEC) of the Clover power station. In 1989, we entered into a coal transportation agreement with Norfolk Southern for the delivery of coal to the facility. The agreement provides for a base-rate price adjustment based upon a published index. Norfolk Southern claimed in October 2003 that an incorrect reference index was used to adjust the base transportation rate. In November 2003, we and ODEC filed suit against Norfolk Southern seeking to clarify the price escalation provisions of the transportation agreement. The trial court has ruled in Norfolk Southern’s favor by concluding that the agreement specifies the higher rate adjustment factor which Norfolk Southern claims should have been applied in the past to adjust the base rate and which will be applied in the future. On September 1, 2006, the court entered an order directing us and ODEC to correct invoices from December 1, 2003 to the present by calculating rates under the higher rate adjustment factor as if it had been applied from the inception of the agreement, to tender the difference to Norfolk Southern with interest at the rate provided by the agreement and to pay future invoices using the higher rate adjustment factor as if it had been applied from the inception of the agreement. We and ODEC filed a notice of appeal to the Virginia Supreme Court and posted security to suspend execution of the judgment during the appeal. The Virginia Supreme Court ruled the order was not final and therefore such order could not be appealed. The surety bond that was posted as security was released by the Circuit Court of Halifax County, Virginia.

In April 2008, issues regarding the amount of Norfolk Southern’s claimed damages were tried, and the trial court issued a Final Order and Decree. The court assessed damages of approximately $77.7 million for the contract period from December 1, 2003 through November 30, 2007, and imposed prejudgment interest of approximately $8.5 million, of which our share would be one-half. The court also ordered the two defendants to pay Norfolk Southern the higher rate adjustment factor for the remaining term of the agreement. Interest will be assessed on any difference between the amounts which we and ODEC pay to Norfolk Southern and the amounts which the court ordered to be

PAGE 14

paid. We believe the court’s interpretation of the transportation agreement and its ruling on other issues in the case are legally incorrect. In July 2008, we and ODEC filed a petition of appeal of the trial court’s order to the Supreme Court of Virginia. No liability has been recorded in our Consolidated Financial Statements related to this matter.

Guarantees and Surety Bonds

As of June 30, 2008, we had issued $17 million of guarantees primarily to support tax exempt debt issued through various state and local authorities. We had also purchased $105 million of surety bonds for various purposes, including providing workers’ compensation coverage. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, we have entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by our contracts with the DOE. In January 2004, we filed a lawsuit in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. Trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. A decision is expected in 2008. We will continue to manage our spent fuel until it is accepted by the DOE.

Note 11. Credit Risk

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our June 30, 2008 provision for credit losses, that it is unlikely 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. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At June 30, 2008, our gross credit exposure totaled $104 million. After the application of collateral, our credit exposure is reduced to $81 million. Of this amount, 32% related to a single counterparty; however, 99% of the balance is with investment grade entities, including those internally rated.

Note 12. Related Party Transactions

We engage in related-party transactions primarily with 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. We also enter into certain commodity derivative contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with purchases of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

DRS 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 15

Presented below are significant transactions with DRS and other affiliates:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
(millions)
Commodity purchases from affiliates	$	121	$	78	$	186	$	127
Services provided by affiliates		90		78		176		156

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At December 31, 2007, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $114 million. There were no money pool borrowings at June 30, 2008. Net interest charges incurred by us related to these borrowings were not material.

Note 13. Operating Segments

We are organized primarily on the basis of the products and services we sell. 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 DVP and Generation segments. We manage our daily operations through the following segments:

DVP includes our electric transmission, distribution and customer service operations.

Generation includes our generation and energy supply operations.

Corporate and Other primarily includes specific items attributable to our operating segments. 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 are not included in profit measures evaluated by executive management, either in assessing the segment’s performance or in allocating resources among the segments, and are instead reported in the Corporate and Other segment. There were no specific items attributable to our operating segments included in the Corporate and Other segment in the six months ended June 30, 2008. For the six months ended June 30, 2007, the Corporate and Other segment included $164 million of after-tax expenses attributable to our Generation segment reflecting:

•

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

•

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

•

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

The following table presents segment information pertaining to our operations:


	DVP		Generation			Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2008
Operating revenue	$	357	$	1,186		$	3		$	1,546
Net income (loss)		64		139			(3	)		200

Three Months Ended June 30, 2007
Operating revenue	$	359	$	1,064		$	1		$	1,424
Extraordinary item, net of tax		—		—			(158	)		(158	)
Net income (loss)		90		(6	)		(163	)		(79	)

Six Months Ended June 30, 2008
Operating revenue	$	718	$	2,346		$	6		$	3,070
Net income (loss)		143		282			(3	)		422

Six Months Ended June 30, 2007
Operating revenue	$	722	$	2,142		$	3		$	2,867
Extraordinary item, net of tax		—		—			(158	)		(158	)
Net income (loss)		187		(8	)		(169	)		10

PAGE 16

VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses our results of operations and general financial condition. 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 or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. All of our common stock is owned by our parent company, 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,” “target” 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 severe 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, greenhouse gases, and other emissions 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 securities held as investments in nuclear decommissioning trusts;

•

Fluctuations in interest rates;

•

Changes in federal and state tax laws and regulations;

•

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 to regulated electric rates collected by the Company and the timing of such collection as it relates to fuel costs;

•

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

•

The inability to complete planned construction or expansion projects within the terms and time frames initially anticipated;

•

Changes in rules for the RTO in which we participate, including changes in rate designs and capacity models;

•

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

•

Adverse outcomes in litigation matters.

PAGE 17

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, and in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2008, 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, 2007. 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 quarter and year-to-date periods ended June 30, 2008 and 2007:


	Second Quarter							Year-To-Date
	2008		2007			$ Change		2008		2007		$ Change
(millions)
Net income (loss)	$	200	$	(79	)	$	279	$	422	$	10	$	412

Overview

Second Quarter and Year-To-Date 2008 vs. 2007

Our net income for the three months and six months ended June 30, 2008, was significantly higher than the comparable prior year periods primarily due to the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of our generation operations effective July 1, 2007, with deferred fuel accounting for over- or under-recoveries of fuel costs, and the absence of an extraordinary charge incurred in 2007 in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

Analysis of Consolidated Operations

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


	Second Quarter								Year-To-Date
	2008		2007			$ Change			2008		2007			$ Change
(millions)
Operating Revenue	$	1,546	$	1,424		$	122		$	3,070	$	2,867		$	203
Operating Expenses
Electric fuel and energy purchases		557		661			(104	)		1,080		1,336			(256	)
Purchased electric capacity		97		107			(10	)		203		223			(20	)
Other energy-related commodity purchases		3		8			(5	)		7		16			(9	)
Other operations and maintenance		304		274			30			579		558			21
Depreciation and amortization		150		140			10			299		274			25
Other taxes		45		43			2			94		88			6
Other income		9		17			(8	)		18		40			(22	)
Interest and related charges		78		82			(4	)		157		144			13
Income tax expense		121		47			74			247		100			147
Extraordinary item, net of tax		—		(158	)		158			—		(158	)		158

PAGE 18

An analysis of our results of operations for the second quarter and year-to-date periods of 2008 compared to the second quarter and year-to-date periods of 2007 follows:

Second Quarter 2008 vs. 2007

Operating Revenue increased 9% to $1.5 billion, reflecting the combined effects of:

•

An $83 million increase in fuel revenue primarily due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

A $19 million increase associated with sales to wholesale customers; and

•

A $14 million increase in new customer connections primarily in our residential and commercial customer classes.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 16% to $557 million, primarily due to the deferral of fuel expenses that were in excess of fuel rate recovery ($277 million). The underlying fuel costs, including those subject to deferral accounting, increased $173 million as a result of higher commodity prices, including purchased power.

Purchased electric capacity expense decreased 9% to $97 million, primarily due to reductions of capacity expense under certain long-term power purchase contracts.

Other operations and maintenance expense increased 11% to $304 million, primarily reflecting:

•

A $24 million increase resulting from higher salaries, wages and other benefits expenses and other general and administrative costs;

•

An $18 million increase due to higher outage costs reflecting an increase in scheduled outages, and an increase in routine maintenance at certain of our electric generating facilities; and

•

A $12 million increase related to storm damage and service restoration costs associated with our distribution operations; partially offset by

•

A $15 million increase in gains from the sale of emissions allowances held for consumption.

Income tax expense increased 157% to $121 million, reflecting higher pre-tax income in 2008.

Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

Year-To-Date 2008 vs. 2007

Operating Revenue increased 7% to $3.1 billion, reflecting the combined effects of:

•

A $157 million increase in fuel revenue primarily due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

A $58 million increase in sales to retail customers attributable to variations in rates resulting from changes in sales mix and other factors ($29 million) and new customer connections ($29 million) primarily in our residential and commercial customer classes; and

•

A $33 million increase associated with sales to wholesale customers; partially offset by

•

A $48 million decrease in sales to retail customers due to fewer heating degree days (HDDs), primarily in the first quarter of 2008.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 19% to $1.1 billion, primarily due to the deferral of fuel expenses that were in excess of fuel rate recovery ($447 million). The underlying fuel costs, including those subject to deferral accounting, increased $191 million as a result of higher commodity prices, including purchased power, partially offset by lower volumes due to fewer HDDs.

Purchased electric capacity expense decreased 9% to $203 million, primarily due to reductions of capacity expense under certain long-term power purchase contracts.

Other operations and maintenance expense increased 4% to $579 million, primarily reflecting:

•

A $45 million increase resulting from higher salaries, wages and other benefits expenses and other general and administrative costs;

•

A $19 million increase related to storm damage and service restoration costs associated with our distribution operations; and

PAGE 19

•

A $12 million increase in routine maintenance at certain of our electric generating facilities; partially offset by

•

A $29 million increase in gains from the sale of emissions allowances held for consumption; and

•

A $16 million decrease in outage costs resulting from a reduction in scheduled outages at certain of our electric generating facilities.

Depreciation and amortization expense increased 9% to $299 million, primarily due to an increase in depreciation rates for our generation assets and property additions.

Other income decreased 55% to $18 million, resulting primarily from the deferral in 2008 of decommissioning trust earnings due to the reapplication of SFAS No. 71, in April 2007, to the Virginia jurisdiction of our generation operations.

Interest and related charges increased 9% to $157 million, primarily due to interest on additional borrowings.

Income tax expense increased 147% to $247 million, reflecting higher pre-tax income in 2008.

Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 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 (loss) for the quarter and year-to-date periods ended June 30, 2008 and 2007:


	Second Quarter									Year-To-Date
	2008			2007			$ Change			2008			2007			$ Change
(millions)
DVP	$	64		$	90		$	(26	)	$	143		$	187		$	(44	)
Generation		139			(6	)		145			282			(8	)		290

Primary operating segments		203			84			119			425			179			246
Corporate and Other		(3	)		(163	)		160			(3	)		(169	)		166

Consolidated	$	200		$	(79	)	$	279		$	422		$	10		$	412

DVP

Presented below are operating statistics related to our DVP operations:


	Second Quarter				Year-To-Date
	2008	2007	% Change		2008	2007	% Change
Electricity delivered (million mwhrs)⁽¹⁾	20.0	20.0	—	%	40.8	41.0	—	%
Degree days:
Cooling⁽²⁾	501	481	4		504	493	2
Heating⁽³⁾	263	367	(28	)	2,072	2,360	(12	)
Average electric distribution customer accounts⁽⁴⁾	2,382	2,356	1		2,381	2,354	1

mwhrs = megawatt hours

(1)	Includes electricity delivered through the retail choice program for our Virginia jurisdictional electric customers.

(2)	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.

(3)	HDDs are units measuring the extent to which the average temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature and 65 degrees.

(4)	Period average, in thousands.

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


	Second Quarter 2008 vs. 2007 Increase (Decrease)			Year-To-Date 2008 vs. 2007 Increase (Decrease)
(millions)
Operations and maintenance⁽¹⁾	$	(8	)	$	(17	)
Storm damage and service restoration – distribution operations		(7	)		(11	)
Regulated electric sales:
Weather		1			(8	)
Customer growth		2			5
Other		(3	)		2
Interest expense⁽²⁾		(3	)		(9	)
Other		(8	)		(6	)

Change in net income contribution	$	(26	)	$	(44	)

(1)	Primarily due to increases in salaries, wages and benefits, outside contractor services and general administrative costs.

(2)	Primarily due to interest on additional borrowings.

PAGE 21

Generation

Presented below are operating statistics related to our Generation operations:


	Second Quarter				Year-To-Date
	2008	2007	% Change		2008	2007	% Change
Electricity supplied (million mwhrs)	20.0	20.0	—	%	40.8	41.0	—	%
Degree days:
Cooling	501	481	4		504	493	2
Heating	263	367	(28	)	2,072	2,360	(12	)

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


	Second Quarter 2008 vs. 2007 Increase (Decrease)			Year-To-Date 2008 vs. 2007 Increase (Decrease)
(millions)
Virginia fuel expenses⁽¹⁾	$	118		$	243
Sale of emissions allowances		9			18
Regulated electric sales:
Customer growth		4			8
Weather		3			(13	)
Other		9			30
Outage costs		(6	)		10
Depreciation expense⁽²⁾		(7	)		(17	)
Other		15			11

Change in net income contribution	$	145		$	290

(1)	Primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007, for the Virginia jurisdiction of our generation operations.

(2)	Primarily due to an increase in depreciation rates.

Corporate and Other

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


	Second Quarter								Year-To-Date
	2008			2007			$ Change		2008			2007			$ Change
(millions)
Specific items attributable to operating segments	$	—		$	(158	)	$	158	$	—		$	(164	)	$	164
Other corporate operations		(3	)		(5	)		2		(3	)		(5	)		2

Total net expense	$	(3	)	$	(163	)	$	160	$	(3	)	$	(169	)	$	166

Specific Items Attributable to Operating Segments

Corporate and Other includes specific items attributable to our primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources between the segments. See Note 13 to our Consolidated Financial Statements for a discussion of these items.

PAGE 22

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 issuances of debt and/or equity from Dominion.

At June 30, 2008, we had $1.1 billion of unused capacity under our joint credit facility.

A summary of our cash flows for the six months ended June 30, 2008 and 2007 is presented below:


	2008			2007
(millions)
Cash and cash equivalents at January 1,	$	49		$	18
Cash flows provided by (used in)
Operating activities		587			677
Investing activities		(881	)		(533	)
Financing activities		295			(137	)

Net increase in cash and cash equivalents		1			7

Cash and cash equivalents at June 30,	$	50		$	25

Operating Cash Flows

For the six months ended June 30, 2008, net cash provided by operating activities decreased by $90 million as compared to the six months ended June 30, 2007. The decrease is primarily due to higher commodity prices and the timing delay in recovery of fuel costs through Virginia jurisdiction fuel rates. We believe that our operations provide a stable source of cash flow 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, which are discussed in Item 1A. Risk Factors in this report, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, and in our Annual Report on Form 10-K for the year ended December 31, 2007.

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross exposure as of June 30, 2008, 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		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	67	$	22	$	45
Non-investment grade		1		—		1
No external ratings:
Internally rated—investment grade⁽²⁾		36		1		35
Internally rated—non-investment grade		—		—		—

Total	$	104	$	23	$	81

(1)	Designations as investment grade are based on minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 45% of the total net credit exposure.

(2)	The four counterparty exposures, combined, for this category represented approximately 43% of the total net credit exposure.

Investing Cash Flows

For the six months ended June 30, 2008, net cash used in investing activities increased by $348 million as compared to 2007. This primarily reflects an increase in capital expenditures.

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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 registration with the SEC and approval from the Virginia Commission.

For the six months ended June 30, 2008, net cash provided by financing activities was $295 million as compared to net cash used in financing activities of $137 million in 2007. This change is due to lower repayments of long-term debt and higher issuance of short-term debt, partially offset by the repayment of affiliated notes payable.

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, 2007, we discussed the use of capital markets and the impact of credit ratings on the accessibility and costs of using these markets, as well as various covenants present in the enabling agreements underlying our debt. As of June 30, 2008, there have been no changes in our credit ratings, other than the matters discussed in MD&A in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, nor have there been any changes to or events of default under our debt covenants.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of June 30, 2008, there have been no material changes outside the ordinary course of business to our contractual obligations nor any material changes to our planned capital expenditures disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2007.

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 our Annual Report on Form 10-K for the year ended December 31, 2007 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008.

Virginia Fuel Expenses

In May 2008, we filed an application to revise our fuel factor with the Virginia Commission that would have resulted in an annual increase from 2.232 cents per kWh to 4.245 cents per kWh, effective July 1, 2008. This revised factor included $231 million of prior year under-recovered fuel expense out of a total estimated prior year under-recovered balance of $697 million with the remaining deferred fuel balance expected to be recovered over the next two fuel rate years beginning July 1, 2009. As part of the application, we proposed adoption of a rule that would limit the fuel factor to 3.893 cents per kWh for the current fuel period of July 1, 2008 through June 30, 2009. In order to achieve this lower fuel factor increase, the proposal would have delayed recovery of the prior year under-recovered fuel balance of $697 million to be collected over a three-year period beginning July 1, 2009.

Upon approval of a Stipulation and Recommendation proposed by the Company and other parties, the Virginia Commission ordered an increase of our fuel factor effective July 1, 2008 as follows:

we will place into effect a fuel tariff of 3.893 cents per kWh for the collection of the current period and partial recovery of the prior year under-recovered fuel balance;

ii)

we will recover $231 million of the approximately $697 million prior year under-recovered fuel balance, with the balance to be recovered in subsequent fuel periods as provided by Virginia law;

iii)

the fuel tariff of 3.893 cents per kWh is estimated to result in an under- recovery of $231 million of projected fuel expenses during the current period; and

iv)

we will not propose to recover a return or interest or any other form of carrying costs on the balance of uncollected fuel expenses described in subsection (ii) above, including the estimated $231 million under-recovery of current period expenses described in subsection (iii), provided that the total amount on which we will not propose to recover interest or any other form of carrying costs is limited to $697 million.

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The resulting increase in the typical 1,000 kWh Virginia jurisdictional residential customer’s monthly bill is approximately 18.3 percent for the 2008 through 2009 fuel period.

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 capacity over the next ten years. We have announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in our core market in Virginia. Our Annual Report on Form 10-K for the year ended December 31, 2007 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 provide a description of these projects, which are in various stages of development. The following is a discussion of certain significant developments related to such projects.

In June 2008, two 150 Mw natural gas-fired electric generating units (Units 3 and 4), previously approved by the Virginia Commission, commenced commercial operations at Ladysmith. In March 2008, the Virginia Commission approved our application to construct a fifth combustion turbine (Unit 5) at Ladysmith, at an estimated cost of $79 million, and granted a certificate to construct and operate the proposed generating unit. In July 2008, the air emissions permit allowing construction of Unit 5 was issued by the Virginia Department of Environmental Quality (VDEQ). Construction has since commenced.

After an evidentiary hearing in February 2008, the Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the proposed Virginia City Hybrid Energy Center and approving a rate adjustment clause as specified in the Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point premium that Virginia law provides for new conventional coal generation facilities. The Virginia Commission also authorized us to apply for an additional 100 basis point premium upon a demonstration that the plant is carbon-capture compatible. The enhanced return will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life. In July 2008, the Southern Environmental Law Center (SELC), on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia.

An application for a permit to construct and operate the Virginia City Hybrid Energy Center, in compliance with federal and state air pollution laws, was filed in July 2006 with the VDEQ and an application for another air permit for hazardous emissions was filed in February 2008. In June 2008, the Virginia Air Pollution Control Board (the Air Board), which assumed consideration of the applications, voted to approve, and issued both permits. The Air Board approved lower emissions limits than had been requested, including limits for sulfur dioxide and mercury. The Air Board also adopted our proposal to convert our Bremo power station from coal to natural gas within two years of the Virginia City Hybrid Energy Center going into service. The Bremo conversion project is part of our overall effort to reduce air emissions and is contingent upon the Virginia City Hybrid Energy Center entering service and Bremo receiving all necessary approvals, including approval from the Virginia Commission. Construction of the Virginia City Hybrid Energy Center has commenced and the facility is expected to be in operation by 2012 at an estimated cost of approximately $1.8 billion, excluding financing costs. In July 2008, the SELC, on behalf of four environmental groups, filed Notices of Appeal in Richmond Circuit Court challenging the approval of both of the air permits.

We are considering the construction of a third nuclear unit at a site located at North Anna, which we own along with ODEC. In November 2007, the Nuclear Regulatory Commission (NRC) issued an Early Site Permit (ESP) to our affiliate, Dominion Nuclear North Anna, LLC (DNNA), for a site located at North Anna. Also in November 2007, we along with ODEC, filed an application with the NRC for a Combined Construction Permit and Operating License (COL), which would allow us to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted our application for the COL and deemed it complete. Dominion has a cooperative agreement with the DOE to share equally the cost of the COL. In April 2008, Dominion filed applications with the Virginia Commission and the North Carolina Utilities Commission (North Carolina Commission) requesting authority to merge DNNA into the Company. The Virginia Commission approved such merger in July 2008. Our request for approval of the merger is pending before the North Carolina Commission. In April 2008, Dominion filed an application with the NRC requesting authority to transfer the ESP to the Company and ODEC. We have not yet committed to building a new nuclear unit.

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In June 2008, the DOE issued a solicitation announcement inviting the submission of applications for loan guarantees from the DOE under its Loan Guarantee Program in support of debt financing for nuclear power facility projects in the U.S. (the Solicitation). The Solicitation is specifically designed to provide loan guarantees to support those projects that employ new or significantly improved nuclear power facility technologies. Any loan guarantee which may be issued by the DOE pursuant to the Solicitation would be backed by the full faith and credit of the U.S. federal government, and would provide credit enhancement for all or a portion of the debt financing an applicant would incur with respect to such a project. We intend to submit to the DOE, during the third quarter of 2008, Part I of the application, which would include a high-level description of the proposed nuclear unit, project eligibility, financing strategy and progress to date related to critical path schedules.

Conservation Plan

In June 2008, we announced an energy conservation plan that, if implemented, is expected to produce long-term environmental benefits while providing customers with cost savings. The conservation plan is part of our “Powering Virginia” strategy to meet the future needs of customers. We hope to begin implementing the plan in 2009, subject to approval by the Virginia Commission and the North Carolina Commission, as applicable.

A key component of the plan is the installation of “smart grid” technologies that are designed to enhance our electric distribution system by allowing energy to be delivered more efficiently. We expect to invest about $600 million and replace all of our existing meters with Advanced Metering Infrastructure (AMI). The technology is expected to lead to improvements in service reliability and the ability of customers to monitor and control their energy use. Along with installing the AMI technology, programs in the conservation plan include:

•

Incentives for construction of energy-efficient homes that meet the federal government’s Energy Star^® standards;

•

Incentives for residential and commercial customers to install energy-efficient lighting;

•

Energy audits and improvements for homes of low-income customers;

•

Incentives for residential customers who voluntarily enroll to allow the Company to cycle their air-conditioners and heat pumps during periods of peak demand;

•

Power cost monitors that display the amount and cost of electricity customers are using; and

•

Incentives for residential and commercial customers to improve the energy efficiency of their heating and/or cooling units.

Application for Enhanced ROE for Electric Transmission Projects

In July 2008, we filed an application with FERC requesting a revision to our cost of service to reflect an additional return on equity (ROE) for eleven electric transmission enhancement projects. Under the proposal our cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). We proposed an incentive of 150 basis points or 1.5% for four of the projects and an incentive of 125 basis points or 1.25% for the other seven projects. We expect that FERC will issue an order in early September 2008 either accepting our proposal or setting the matter for hearing. Several parties have intervened in the case. We cannot predict the outcome of these proceedings, but do not expect a material impact on our results of operations.

PJM Capacity Auction Complaint

In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Public Utility Commission, New Jersey Board of Public Utilities, the American Forest & Paper Association, the Portland Cement Association and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers request that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. We cannot predict the outcome of this complaint at FERC, but do not expect a material adverse effect on our financial position, liquidity or results of operations.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

PAGE 26

To the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission during the period ending December 31, 2008, in excess of the level currently included in Virginia jurisdictional rates, our results of operations could decrease. After that date, we are allowed to seek recovery through rates.

Clean Air Act Compliance

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a ruling that vacates the Clean Air Mercury Rule (CAMR) as promulgated by the EPA. In May 2008, the EPA’s appeal of this decision with the U.S. Court of Appeals for the District of Columbia was denied. At this time we cannot determine if this ruling will be subject to further appeals. We also cannot predict how the EPA and the states that adopted CAMR-based mercury emissions reduction rules may alter their approach to reducing mercury emissions. Given this regulatory uncertainty, we cannot estimate at this time the impact of the ruling on our future capital and operational expenditures.

In July 2008, the U.S. Court of Appeals for the District of Columbia issued a ruling that vacates the Clean Air Interstate Rule (CAIR) as promulgated by the EPA. The ruling will be deferred during the 45-day period allowed for the filing of any petitions for rehearing. At this time we cannot determine if this ruling will be appealed. The primary effects of the Court’s decision are the elimination of the CAIR requirement to surrender sulfur dioxide (SO₂) allowances under the Acid Rain Program at a 2:1 ratio starting in 2010 and a 2.86:1 ratio starting in 2015, and the emission reduction targets and timetables for nitrogen oxides (NO_X) that were beyond those reductions already required under the Clean Air Act’s Acid Rain Program. The CAIR annual NO_X emissions allowance cap and trade program is also eliminated. Remaining in effect is the EPA NO_X State Implementation Plan Call regulation applicable to summertime NO_X emissions under a cap and trade program and the Acid Rain Program for SO₂ reductions.

At this time we cannot predict how the EPA and the states may alter their approach to reducing SO₂ and NO_X emissions in the absence of CAIR. We are currently evaluating the ruling to determine what impacts it may have on our compliance planning in regards to future SO₂ and NO_X emission reduction requirements; however because of this regulatory uncertainty we cannot estimate at this time the impact on our future capital and operational expenditures. It is anticipated that, in the short-term, the CAIR invalidation will not have a material adverse impact on expenditures related to compliance with state and federal rules regulating SO₂ and NO_X emissions. Expenditures could potentially increase in the long-term in the event that a new federal program is reinstituted and does not provide for the use of emissions allowances to satisfy emission reduction requirements. Despite the CAIR ruling, we are still subject to SO₂ and NO_X emission restrictions under federal and state rules unaffected by the ruling and under our 2003 agreement with the EPA and five other states in which we committed to a 12 year program to significantly reduce air emissions across our coal-fired generating fleet in Virginia and West Virginia.

We do not expect to recognize any loss in connection with the elimination of the annual NO_X program as all of our annual NO_X allowances were allocated to us and were not assigned a cost value. The Court’s decision has resulted in a decline in the market value of SO₂ allowances which may impact our ability to monetize the value of these allowances in the future. We are currently evaluating whether an impairment adjustment is required for SO₂ allowances currently held by us, or a portion thereof, as a result of this decline in market value; however such impairment, if any, is not expected to have a material impact on our results of operations, cash flows or financial position.

Regulation of Greenhouse Gas Emissions

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions. In July 2008, the EPA released an Advanced Notice of Proposed Rulemaking to solicit comment on potential issues related to the regulation of greenhouse gases under the Clean Air Act, which could result in further EPA regulatory action. The outcome in terms of specific requirements and timing is uncertain. The cost of compliance with future greenhouse gas reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future greenhouse gas reduction programs on our operations or our customers at this time.

Clean Water Act Compliance

In July 2004, the EPA published regulations under the Clean Water Act Section 316b that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. The EPA’s

PAGE 27

rule presented several compliance options. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. In July 2007, the EPA suspended the regulations pending further rulemaking, consistent with the decision issued by the U.S. Court of Appeals for the Second Circuit. In November 2007, a number of industries appealed the lower court decision to the U.S. Supreme Court. In April 2008, the U.S. Supreme Court granted the industry request to review the question of whether Section 316b of the Clean Water Act authorizes EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. We have eight facilities that are likely to be subject to these regulations. We cannot predict the outcome of the judicial or EPA regulatory processes, nor can we determine with any certainty what specific controls may be required.

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VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A 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 and equity security prices. Commodity price risk is due to our exposure to market shifts for prices paid for electricity, natural gas, and other commodities. 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 and interest rates.

Commodity Price Risk

To manage price risk, we hold commodity-based financial derivative instruments for non-trading purposes associated with purchases of electricity, natural gas and other energy-related products. 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, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices 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 observable market prices.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $23 million and $27 million in the fair value of our non-trading commodity-based financial derivatives as of June 30, 2008 and December 31, 2007, 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.

Interest Rate Risk

Our interest rate risk exposure at June 30, 2008 has not changed materially as compared with December 31, 2007.

PAGE 29

Investment Price Risk

We are subject to investment price risk due to securities held as investments in decommissioning trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in our Consolidated Balance Sheets at fair value.

Following the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations in April 2007, gains or losses on those decommissioning trust investments are recorded to regulatory liabilities.

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $9 million for the six months ended June 30, 2008, and net realized gains (including investment income) of $35 million and $28 million for the six months ended June 30, 2007 and for the year ended December 31, 2007, respectively. For the six months ended June 30, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $91 million. For the six months ended June 30, 2007, we recorded, in AOCI and regulatory liabilities, $20 million in unrealized gains on these investments. For the year ended December 31, 2007, we recorded, in AOCI and regulatory liabilities, unrealized gains on these investments of $13 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 provide to Dominion, representing our share of employee benefit plan contributions.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including our CEO and CFO, 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 CEO and CFO 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 30

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, 2007 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, which 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 Annual Report on Form 10-K for the year ended December 31, 2007 or our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008. 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.

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

On April 25, 2008, 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 N. Chewning, Thomas F. Farrell, II and Steven A. Rogers.

PAGE 31

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		Virginia Electric and Power Company agrees to furnish to the SEC 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 CEO 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 SEC by Registrant’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

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

PAGE 32

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

July 31, 2008		/s/ Thomas P. Wohlfarth
		Thomas P. Wohlfarth Senior Vice President and Chief Accounting Officer

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