Edgar Filing: VIRGINIA ELECTRIC & POWER CO

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 September 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 Nine Months Ended September 30, 2008 and 2007	4

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

	Consolidated Statements of Cash Flows – Nine Months Ended September 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	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28

Item 4.	Controls and Procedures	29

	PART II. Other Information

Item 1.	Legal Proceedings	30

Item 1A.	Risk Factors	30

Item 6.	Exhibits	31

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
DOE		Department of Energy
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
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
mwhrs		Megawatt hours
North Anna		North Anna power station
North Carolina Commission		North Carolina Utilities Commission
NRC		Nuclear Regulatory Commission
ODEC		Old Dominion Electric Cooperative
Pennsylvania Commission		Pennsylvania Public Utility Commission
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 Commission		Virginia State Corporation Commission
West Virginia Commission		Public Service Commission of West Virginia

PAGE 3

VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
(millions)
Operating Revenue	$	2,177	$	1,833	$	5,247	$	4,700

Operating Expenses
Electric fuel and energy purchases		982		609		2,062		1,945
Purchased electric capacity		102		107		305		330
Other energy-related commodity purchases		4		8		11		24
Other operations and maintenance:
Affiliated suppliers		98		83		274		239
Other		230		255		633		657
Depreciation and amortization		154		146		453		420
Other taxes		46		43		140		131

Total operating expenses		1,616		1,251		3,878		3,746

Income from operations		561		582		1,369		954

Other income		6		18		24		58
Interest and related charges:
Interest expense		82		77		227		206
Interest expense—junior subordinated notes payable to affiliated trust		—		8		12		23

Total interest and related charges		82		85		239		229

Income before income tax expense		485		515		1,154		783
Income tax expense		182		193		429		293

Income before extraordinary item		303		322		725		490
Extraordinary item⁽¹⁾		—		—		—		(158	)

Net Income		303		322		725		332
Preferred dividends		4		4		12		12

Balance available for common stock	$	299	$	318	$	713	$	320

(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 our Consolidated Financial Statements.

PAGE 4

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2008			December 31, 2007⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	27		$	49
Customer accounts receivable (less allowance for doubtful accounts of $8 at both dates)		928			763
Affiliated receivables		1			53
Other receivables (less allowance for doubtful accounts of $7 and $9)		52			58
Inventories (average cost method)		559			520
Prepayments		27			165
Other		154			92

Total current assets		1,748			1,700

Investments
Nuclear decommissioning trust funds		1,187			1,339
Other		3			16

Total investments		1,190			1,355

Property, Plant and Equipment
Property, plant and equipment		23,056			21,838
Accumulated depreciation and amortization		(8,973	)		(8,702	)

Total property, plant and equipment, net		14,083			13,136

Deferred Charges and Other Assets
Regulatory assets		1,194			564
Other		357			308

Total deferred charges and other assets		1,551			872

Total assets	$	18,572		$	17,063

(1)

Our 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 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 our Consolidated Financial Statements.

PAGE 5

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2008		December 31, 2007⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	307	$	286
Short-term debt		664		257
Accounts payable		477		573
Payables to affiliates		89		80
Affiliated current borrowings		340		114
Accrued interest, payroll and taxes		301		234
Other		349		239

Total current liabilities		2,527		1,783

Long-Term Debt
Long-term debt		5,452		4,904
Junior subordinated notes payable to affiliated trust		—		412

Total long-term debt		5,452		5,316

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,540		2,237
Regulatory liabilities		894		1,009
Asset retirement obligations		705		678
Other		316		242

Total deferred credits and other liabilities		4,455		4,166

Total liabilities		12,434		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		1,110		1,109
Retained earnings		1,367		1,015
Accumulated other comprehensive income		16		29

Total common shareholder’s equity		5,881		5,541

Total liabilities and shareholder’s equity	$	18,572	$	17,063

(1)	Our 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 FIN 39-1, as discussed in Note 3.

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

PAGE 6

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
(millions)
Operating Activities
Net income	$	725		$	332
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		524			485
Deferred income taxes and investment tax credits, net		305			99
Extraordinary item, net of income taxes		—			158
Other adjustments to income, net		(37	)		(31	)
Changes in:
Accounts receivable		(173	)		(178	)
Affiliated accounts receivable and payable		61			46
Inventories		(38	)		21
Deferred fuel expenses, net		(514	)		(152	)
Accounts payable		(84	)		(9	)
Accrued interest, payroll and taxes		66			5
Prepayments		138			89
Other operating assets and liabilities		(28	)		93

Net cash provided by operating activities		945			958

Investing Activities
Plant construction and other property additions		(1,330	)		(680	)
Purchases of nuclear fuel		(88	)		(88	)
Purchases of securities		(345	)		(427	)
Proceeds from sales of securities		303			391
Other		84			29

Net cash used in investing activities		(1,376	)		(775	)

Financing Activities
Issuance (repayment) of short-term debt, net		407			(618	)
Issuance of affiliated current borrowings, net		226			914
Repayment of affiliated notes payable		(412	)		—
Issuance of long-term debt		630			1,200
Repayment of long-term debt		(62	)		(1,313	)
Common dividend payments		(361	)		(338	)
Preferred dividend payments		(12	)		(12	)
Other		(7	)		(13	)

Net cash provided by (used in) financing activities		409			(180	)

Increase (decrease) in cash and cash equivalents		(22	)		3
Cash and cash equivalents at beginning of period		49			18

Cash and cash equivalents at end of period	$	27		$	21

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

PAGE 7

VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Virginia Electric and Power Company is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of September 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 Resources, Inc. (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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of September 30, 2008, our results of operations for the three and nine months ended September 30, 2008 and 2007, and our cash flows for the nine months ended September 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. See Note 6 for further information on fair value measurements in accordance with SFAS No. 157, Fair Value Measurements.

The results of operations for 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 FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

PAGE 8

Reapplication of SFAS No. 71

The reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations in April 2007 resulted in a $259 million ($158 million after-tax) extraordinary charge and the reclassification of $195 million ($119 million after-tax) of unrealized gains from AOCI, related to nuclear decommissioning trust funds. This established a $454 million long-term regulatory liability for amounts previously collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of our nuclear generation stations, in excess of amounts recorded pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations.

Income Taxes

We are currently engaged in settlement negotiations with tax authorities regarding certain income tax adjustments proposed during the examination of tax years 2002, 2003 and 2004. We believe that it is reasonably possible, based on settlement negotiations and risks of litigation, that unrecognized tax benefits could decrease by up to $85 million over the next twelve months with no material impact on our results of operations.

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 October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, which clarifies the application of SFAS No. 157 to financial assets in a market that is not active. This FSP was effective for the third quarter of 2008 and confirms that SFAS No. 157 allows for the use of unobservable inputs in determining the fair value of a financial asset when relevant observable inputs do not exist or when observable inputs require significant adjustment based on unobservable data. This may be the case, for example, in an inactive or distressed market. This FSP did not have an impact on our results of operations or financial condition.

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

PAGE 9

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 September 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 Other current 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.

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 September 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, and associated gains and losses in a tabular format and information about 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.

PAGE 10

Note 5. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
(millions)
Net income	$	303		$	322		$	725		$	332
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		(2	)		6			(1	)		(6	)
Other, net of tax		(4	)		(8	)		(12	)		(125	)⁽¹⁾

Other comprehensive loss		(6	)		(2	)		(13	)		(131	)

Total comprehensive income	$	297		$	320		$	712		$	201

(1)

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, Accounting for the Effects of Certain Types of Regulation, those amounts, previously recorded in AOCI, are now recorded in regulatory liabilities.

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. We apply credit adjustments to our derivative fair values in accordance with the requirements described above. These credit adjustments are not material to the derivative fair values.

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, or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis that reflects 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 may 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.

PAGE 11

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, foreign currency forwards and options, 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 consist of long-dated commodity derivatives, financial transmission rights (FTRs), and other modeled commodity derivatives.

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.

Fair value measurements are categorized as Level 3 when a significant amount of price and other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are based on unobservable inputs due to the length of time to settlement and are therefore categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from PJM auctions, which is accurate for day-one valuation, but generally is not considered to be representative of the ultimate settlement values. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets.

As of September 30, 2008, our net balance of commodity derivatives categorized as Level 3 fair value measurements was a liability of $59 million. A hypothetical 10% increase in commodity prices would decrease the liability by $6 million, while a hypothetical 10% decrease in commodity prices would increase the liability by $5 million.

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 our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions, as of September 30, 2008:


(millions)	Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	—	$	73	$	30	$	103
Investments		279		793		—		1,072

Total assets	$	279	$	866	$	30	$	1,175
Liabilities:
Derivatives	$	—	$	24	$	89	$	113

PAGE 12

The following table presents the net change in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the three and nine months ended September 30, 2008:


(millions)	Derivatives ⁽¹⁾
Three Months Ended September 30, 2008
Balance at July 1, 2008	$	210
Total realized and unrealized gains or (losses):
Included in earnings		17
Included in other comprehensive income (loss)		—
Included in regulatory and other assets/liabilities		(249	)
Purchases, issuances and settlements		(37	)
Transfers out of Level 3		—

Balance at September 30, 2008	$	(59	)

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	$	(19	)

Nine Months Ended September 30, 2008
Balance at January 1, 2008	$	(4	)
Total realized and unrealized gains or (losses):
Included in earnings		106
Included in other comprehensive income (loss)		—
Included in regulatory and other assets/liabilities		(49	)
Purchases, issuances and settlements		(112	)
Transfers out of Level 3		—

Balance at September 30, 2008	$	(59	)

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	$	(4	)

(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 nine months ended September 30, 2008:


(millions)	Electric Fuel and Energy Purchases		Other Operations and Maintenance			Total
Three Months Ended September 30, 2008
Total gains or (losses) included in earnings	$	13	$	4		$	17
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		—		(19	)		(19	)
Nine Months Ended September 30, 2008
Total gains or (losses) included in earnings	$	54	$	52		$	106
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		—		(4	)		(4	)

PAGE 13

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 foreign 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 nine months ended September 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 September 30, 2008:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Electric capacity	$	6		$	3		44 months
Natural gas		(2	)		(2	)	6 months
Other		2			1		363 months

Total	$	6		$	2

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 our 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 variable interests in the counterparties in accordance with FIN 46 (revised December 2003), Consolidation of Variable Interest Entities.

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 that 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 September 30, 2008. We paid $50 million and $51 million for electric capacity and $60 million and $50 million for electric energy to these entities for the three months ended September 30, 2008 and 2007, respectively. We paid $152 million and $160 million for electric capacity and $153 million and $128 million for electric energy to these entities for the nine months ended September 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 $98 million and $82 million during the three months ended September 30, 2008 and 2007, respectively, and $273 million and $238 million during the nine months ended September 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 for other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.

PAGE 14

In addition to the credit facility commitments of $3.0 billion disclosed above, we also have a $200 million five-year credit facility that supports certain of our tax-exempt financings. Our aggregate credit facility commitments of $3.2 billion are with a large consortium of banks, including Lehman Brothers Holdings, Inc. (Lehman). In September 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the United States Bankruptcy Court in the Southern District of New York. As of September 30, 2008, Lehman’s total commitment to these credit facilities was less than six percent of the aggregate commitment from the consortium of banks. We do not believe that the potential reduction in available capacity under these credit facilities that could result from Lehman’s bankruptcy will have a significant impact on our liquidity.

At September 30, 2008, total outstanding commercial paper supported by the joint credit facility was $664 million, of which our borrowings were $664 million, and the total amount of letter of credit issuances was $239 million, of which $67 million were issued on our behalf.

At September 30, 2008, capacity available under the joint credit facility was $2.1 billion.

Long-Term Debt

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 $474 million of long-term debt and notes payable during the nine months ended September 30, 2008.

Note 10. Commitments and Contingencies

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

Guarantees and Surety Bonds

As of September 30, 2008, we had issued $16 million of guarantees primarily to support tax exempt debt issued through various state and local authorities. We had also purchased $106 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. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for the Company in the amount of approximately $112 million for its spent-fuel related costs through June 30, 2006. The DOE has 60 days from the entry of judgment to file an appeal, and is expected to appeal the decision. We cannot predict the outcome of this matter, however, in the event that we recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on our results of operations. We will continue to manage our spent fuel until it is accepted by the DOE.

PAGE 15

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 September 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 September 30, 2008, our gross credit exposure totaled $102 million. After the application of collateral, our credit exposure is reduced to $83 million. Of this amount, 33% related to a single counterparty; however, 84% 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 other Dominion subsidiaries (affiliates). Our receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

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

At September 30, 2008, our Consolidated Balance Sheet includes derivative liabilities with affiliates of $13 million. Derivative liabilities with affiliates at December 31, 2007 were not material. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that have been designated as cash flow hedges, are included in AOCI on our Consolidated Balance Sheets.

Presented below are significant transactions with DRS and other affiliates:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
(millions)
Commodity purchases from affiliates	$	255	$	154	$	441	$	281
Services provided by affiliates		98		83		274		239

In September 2008, we purchased a gas-fired turbine from an affiliate for $36 million as part of an expansion project at our Ladysmith power station (Unit 5) to supply electricity during periods of peak demand.

We have borrowed funds from Dominion under short-term borrowing arrangements. At September 30, 2008 and December 31, 2007, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $253 million and $114 million, respectively. Our short-term demand note borrowings from Dominion were $87 million at September 30, 2008. There were no short-term demand note borrowings at December 31, 2007. Net interest charges incurred by us related to our borrowings from Dominion were $1 million and $12 million for the three months ended September 30, 2008 and 2007, respectively, and $2 million and $16 million for the nine months ended September 30, 2008 and 2007, respectively. As compared to the prior year, this reflects a decrease in average intercompany borrowings.

PAGE 16

Lehman Brothers Inc. (LBI), a Lehman subsidiary, formerly acted as a remarketing agent for $153 million of our variable rate tax-exempt pollution control bonds. Due to several unsuccessful remarketing auctions of our variable rate tax-exempt pollution control bonds following the Lehman bankruptcy, Dominion repurchased $14 million of these bonds in September 2008. We also repurchased $20 million of these bonds. These variable rate tax-exempt financings are supported by a stand-alone $200 million five-year credit facility that terminates in February 2011; however, we chose to repurchase the bonds rather than utilize this facility. In late September, Barclays Capital, Inc. became the successor remarketing agent for these series of bonds, and there have been no unsuccessful remarketing auctions since September 30, 2008.

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. In the nine months ended September 30, 2008 and 2007, our Corporate and Other segment included $7 million and $166 million, respectively, of after-tax expenses attributable to our Generation segment. The net expenses in 2007 largely resulted from 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.

The following table presents segment information pertaining to our operations:


	DVP		Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2008
Operating revenue	$	374	$	1,797	$	6		$	2,177
Net income (loss)		83		227		(7	)		303

Three Months Ended September 30, 2007
Operating revenue	$	389	$	1,443	$	1		$	1,833
Net income		96		226		—			322

Nine Months Ended September 30, 2008
Operating revenue	$	1,092	$	4,143	$	12		$	5,247
Net income (loss)		226		509		(10	)		725

Nine Months Ended September 30, 2007
Operating revenue	$	1,111	$	3,585	$	4		$	4,700
Extraordinary item, net of tax		—		—		(158	)		(158	)
Net income (loss)		283		218		(169	)		332

PAGE 17

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 “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 the availability of credit and our ability to obtain financing on reasonable terms;

•

Risks associated with our membership and participation in PJM related to obligations created by the default of other participants;

•

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 their 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;

PAGE 18

•

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.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report, in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 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 September 30, 2008, there have been no significant changes with regard to the critical accounting policies and estimates 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 regulated operations, asset retirement obligations, 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. See Note 6 to our Consolidated Financial Statements for information on our fair value measurements.

Results of Operations

Presented below is a summary of our consolidated results for the quarter and year-to-date periods ended September 30, 2008 and 2007:


	Third Quarter							Year-To-Date
	2008		2007		$ Change			2008		2007		$ Change
(millions)
Net income	$	303	$	322	$	(19	)	$	725	$	332	$	393

Overview

Year-To-Date 2008 vs. 2007

Net income was higher than the prior year 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.

PAGE 19

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2008		2007		$ Change			2008		2007			$ Change
(millions)
Operating Revenue	$	2,177	$	1,833	$	344		$	5,247	$	4,700		$	547
Operating Expenses
Electric fuel and energy purchases		982		609		373			2,062		1,945			117
Purchased electric capacity		102		107		(5	)		305		330			(25	)
Other energy-related commodity purchases		4		8		(4	)		11		24			(13	)
Other operations and maintenance		328		338		(10	)		907		896			11
Depreciation and amortization		154		146		8			453		420			33
Other taxes		46		43		3			140		131			9
Other income		6		18		(12	)		24		58			(34	)
Interest and related charges		82		85		(3	)		239		229			10
Income tax expense		182		193		(11	)		429		293			136
Extraordinary item, net of tax		—		—		—			—		(158	)		158

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

Third Quarter 2008 vs. 2007

Operating Revenue increased 19% to $2.2 billion, reflecting the combined effects of:

•

A $349 million increase in fuel revenue primarily due to the impact of a comparatively higher fuel rate in certain customer jurisdictions that was offset by a corresponding increase in Electric fuel and energy purchases expense; and

•

A $47 million increase associated with sales to wholesale customers; partially offset by

•

A $52 million decrease in sales to retail customers due to a 6% decrease in cooling degree days.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 61% to $982 million, primarily reflecting a comparatively higher fuel rate in certain customer jurisdictions, as discussed in Operating Revenue.

Income tax expense decreased 6% to $182 million, reflecting lower pre-tax income in 2008.

Year-To-Date 2008 vs. 2007

Operating Revenue increased 12% to $5.2 billion, reflecting the combined effects of:

•

A $506 million increase in fuel revenue primarily due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

An $80 million increase associated with sales to wholesale customers; and

•

A $45 million increase in new retail customer connections primarily in our residential and commercial customer classes; partially offset by

•

A $100 million decrease in sales to retail customers due to a 9% decrease in heating and cooling degree days.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 6% to $2.1 billion, largely due to a $470 million increase in fuel costs, primarily as a result of higher commodity prices, including purchased power. The increase in fuel cost was partially offset by a $361 million deferral of fuel expenses that were in excess of the current period fuel rate recovery.

Purchased electric capacity expense decreased 8% to $305 million, primarily due to reductions of capacity expense under certain long-term power purchase contracts.

PAGE 20

Other operations and maintenance expense increased 1% to $907 million, primarily reflecting:

•

A $60 million increase resulting from higher salaries, wages and other benefits expenses and other general and administrative costs; and

•

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

•

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

•

A $19 million decrease in outage costs resulting from a reduction in scheduled outages at certain of our electric generating facilities;

•

A $12 million decrease in administrative charges related to PJM; and

•

A $10 million decrease primarily reflecting an increase in net benefit from higher FTR settlements.

Depreciation and amortization expense increased 8% to $453 million, primarily due to an increase in depreciation rates for our generation assets ($27 million), and property additions ($17 million), partially offset by an $11 million decrease in amortization expense primarily associated with lower consumption of emissions allowances.

Other income decreased 59% to $24 million, resulting primarily from the deferral in 2008 of nuclear decommissioning trust earnings due to the reapplication of SFAS No. 71, in April 2007, to the Virginia jurisdiction of our generation operations ($17 million), and a decrease in interest income ($6 million).

Income tax expense increased 46% to $429 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.

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income for the quarter and year-to-date periods ended September 30, 2008 and 2007:


	Third Quarter								Year-To-Date
	2008			2007		$ Change			2008			2007			$ Change
(millions)
DVP	$	83		$	96	$	(13	)	$	226		$	283		$	(57	)
Generation		227			226		1			509			218			291

Primary operating segments		310			322		(12	)		735			501			234
Corporate and Other		(7	)		—		(7	)		(10	)		(169	)		159

Consolidated	$	303		$	322	$	(19	)	$	725		$	332		$	393

DVP

Presented below are operating statistics related to our DVP operations:


	Third Quarter				Year-To-Date
	2008	2007	% Change		2008	2007	% Change
Electricity delivered (million mwhrs)⁽¹⁾	23.4	23.7	(1	)%	64.2	64.7	(1	)%
Degree days:
Cooling⁽²⁾	1,083	1,150	(6	)	1,587	1,643	(3	)
Heating⁽³⁾	2	5	(60	)	2,074	2,365	(12	)
Average electric distribution customer accounts⁽⁴⁾	2,387	2,364	1		2,383	2,357	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)	Heating degree days (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 for each day and 65 degrees.

(4)	Period average, in thousands.

PAGE 21

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


	Third Quarter 2008 vs. 2007 Increase (Decrease)			Year-To-Date 2008 vs. 2007 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(7	)	$	(15	)
Customer growth		2			7
Other		(3	)		(1	)
Storm damage and service restoration – distribution operations		—			(11	)
Interest expense⁽¹⁾		(1	)		(9	)
Operations and maintenance		4			(17	)
Depreciation expense		(2	)		(5	)
Other		(6	)		(6	)

Change in net income contribution	$	(13	)	$	(57	)

(1)	Primarily due to additional borrowings.

Generation

Presented below are operating statistics related to our Generation operations:


	Third Quarter				Year-To-Date
	2008	2007	% Change		2008	2007	% Change
Electricity supplied (million mwhrs)	23.4	23.7	(1	)%	64.2	64.7	(1	)%
Degree days:
Cooling	1,083	1,150	(6	)	1,587	1,643	(3	)
Heating	2	5	(60	)	2,074	2,365	(12	)

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


	Third Quarter 2008 vs. 2007 Increase (Decrease)			Year-To-Date 2008 vs. 2007 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(16	)	$	(29	)
Customer growth		5			13
Other		4			34
Outage costs		2			12
Virginia fuel expenses⁽¹⁾		—			243
Sale of emissions allowances		—			18
Depreciation expense		(6	)		(23	)
Other		12			23

Change in net income contribution	$	1		$	291

(1)	For the year-to-date period, primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007, for the Virginia jurisdiction of our generation operations.

PAGE 22

Corporate and Other

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


	Third Quarter									Year-To-Date
	2008			2007			$ Change			2008			2007			$ Change
(millions)
Specific items attributable to operating segments	$	(7	)	$	(2	)	$	(5	)	$	(7	)	$	(166	)	$	159
Other corporate operations		—			2			(2	)		(3	)		(3	)		—

Total net expense	$	(7	)	$	—		$	(7	)	$	(10	)	$	(169	)	$	159

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.

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.

Impact of Recent Credit Market Events

Despite recent disruptions in the credit markets, we have sufficient access to liquidity for our daily operations through our credit facilities discussed in Note 9 to our Consolidated Financial Statements. We expect our operations to provide sufficient cash flow to fund maintenance capital expenditures and maintain or grow our dividend to Dominion; however, we expect to access the capital markets to fund growth capital expenditures. If necessary, we have the flexibility to mitigate the need for future debt financings and equity issuances, by postponing or cancelling certain planned capital expenditures.

At September 30, 2008, we had $2.1 billion of unused capacity under our joint credit facility.

A summary of our cash flows for the nine months ended September 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		945			958
Investing activities		(1,376	)		(775	)
Financing activities		409			(180	)

Net increase (decrease) in cash and cash equivalents		(22	)		3

Cash and cash equivalents at September 30,	$	27		$	21

Operating Cash Flows

For the nine months ended September 30, 2008, net cash provided by operating activities decreased by $13 million as compared to the nine months ended September 30, 2007. The decrease is primarily due to the negative impact of milder weather on retail sales and unfavorable changes in working capital, partially offset by lower income tax payments. 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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008, and in our Annual Report on Form 10-K for the year ended December 31, 2007.

PAGE 23

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross credit exposure as of September 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⁾	$	50	$	19	$	31
Non-investment grade⁽²⁾		14		—		14
No external ratings:
Internally rated—investment grade⁽³⁾		38		—		38
Internally rated—non-investment grade		—		—		—

Total	$	102	$	19	$	83

(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 33% of the total net credit exposure.

(2)	The only counterparty exposure for this category represented 16% of the total net credit exposure.

(3)	The only two counterparty exposures, combined, for this category represented 46% of the total net credit exposure.

Investing Cash Flows

For the nine months ended September 30, 2008, net cash used in investing activities increased by $601 million as compared to 2007, primarily reflecting an increase in capital expenditures for construction projects related to our Generation segment.

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 nine months ended September 30, 2008, net cash provided by financing activities was $409 million as compared to net cash used in financing activities of $180 million in 2007. This change is due to net issuances of short-term and long-term debt in 2008 versus net repayments in 2007, partially offset by the repayment of affiliated notes payable and lower issuance of affiliated current borrowings.

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 September 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 September 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.

PAGE 24

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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

Generation Expansion

Based on available generation capacity and current estimates of growth in customer demand in our utility service area, we will need additional generation 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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 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.

We are considering the construction of a third nuclear unit at a site located at North Anna, which we own along with Old Dominion Electric Cooperative (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. The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing Board of the NRC granted a request for a hearing on one of eight contentions filed by the Blue Ridge Environmental Defense League. The mandatory NRC hearing will be uncontested with respect to other issues. We have not yet committed to building a new nuclear unit.

In April 2008, Dominion filed applications with the Virginia Commission and the North Carolina Commission, seeking approval to merge DNNA into the Company. The Virginia application was approved in July 2008, and the North Carolina application was approved in September 2008. Also in April 2008, Dominion filed an application with the NRC to transfer the ESP from DNNA to us and ODEC. This application remains under consideration with the NRC, and we expect a decision in the fourth quarter of 2008.

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. 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. In August 2008, we submitted to the DOE Part I of the application, including a high-level description of the proposed nuclear unit, project eligibility, financing strategy and progress to date related to critical path schedules. We expect to submit to the DOE a Part II application by the required filing date of December 19, 2008.

North Carolina Fuel Factor

In September 2008, we filed an application to revise our fuel factor with the North Carolina Commission, requesting an annual increase in our North Carolina fuel factor from 2.221 cents per kWh to 3.825 cents per kWh to be effective January 1, 2009. The proposal would result in an annual increase in fuel revenue of approximately $69 million for the North Carolina jurisdiction. An evidentiary hearing is scheduled for November 14, 2008.

Regional Transmission Expansion Plan

In June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects, which are designed to improve the reliability of service to our customers and the region, and are subject to applicable state and federal permits and approvals.

The first project is an approximately 270-mile 500-kilovolt (kV) transmission line that begins in southwestern Pennsylvania, crosses West Virginia, and terminates in northern Virginia, of which we will construct approximately 65 miles in Virginia (the Meadow Brook-to-Loudoun line) and a subsidiary of Allegheny Energy, Inc. (Trans-

PAGE 25

Allegheny Interstate Line Company) will construct the remainder. In April 2007, we, along with Trans-Allegheny Interstate Line Company (Trans-Allegheny), filed an application with the Virginia Commission requesting approval of the proposed construction of the 65-mile transmission line in northern Virginia. In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route we proposed for the line which is adjacent to, or within, existing transmission line right-of-ways.

The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line is conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission approved Trans-Allegheny’s application in August 2008. Trans-Allegheny’s application remains pending before the Pennsylvania Commission. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.

The second project is an approximately 60-mile 500-kV transmission line that we will construct in southeastern Virginia (Carson-to-Suffolk line). This project is estimated to cost $224 million and is expected to be completed in June 2011. In May 2007, we filed an application with the Virginia Commission requesting approval of the proposed construction of the Carson-to-Suffolk line. Evidentiary hearings on the application commenced in February 2008. In May 2008, the hearing examiner filed a report finding need for and recommending approval of the line.

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 (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 125 basis points or 1.25% for the other seven projects. In August 2008, FERC approved our proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012.

PJM Capacity Auction Complaint

In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania 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 requested 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. In September 2008, FERC dismissed the complaint.

RTO Start-up Costs and Administrative Fees

In September 2008, we filed a Deferral Recovery Charge (DRC) request with FERC to recover approximately $153 million of RTO costs that we have been unable to recover due to a statutory rate cap established under Virginia law. The RTO costs include:

(i)

costs incurred in development of Alliance RTO on and after this rate cap became effective on July 1, 1999;

(ii)

costs incurred to start up our participation in PJM; and

(iii)

PJM administrative fees billed by PJM from the date that we joined PJM as a transmission owner.

If the DRC is approved by FERC, then recovery of RTO costs through the DRC will not commence until the date established by the Virginia Commission permitting us to implement such recovery.

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. 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.

PAGE 26

Clean Air Act Compliance

In February 2008, the U.S. Court of Appeals for the District of Columbia (D.C. Appeals Court) 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 D.C. Appeals Court was denied. In September 2008, the Utility Air Regulatory Group filed a petition requesting that the U.S. Supreme Court overturn the D.C. Appeals Court decision to vacate the EPA rules. In October 2008, the Solicitor General, on behalf of the EPA, also filed a petition with the U.S. Supreme Court. We 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 D.C. Appeals Court issued a ruling that vacates the Clean Air Interstate Rule (CAIR) as promulgated by the EPA. 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. A number of parties, including the EPA, filed petitions for a D.C. Appeals Court rehearing of the decision. The CAIR ruling remains deferred until the D.C. Appeals Court rules on the petitions for rehearing.

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 tested our SO₂ allowances for impairment and concluded that no impairment adjustment was required for SO₂ allowances during the third quarter of 2008, as a result of this decline in market value.

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 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. Oral arguments before the U.S. Supreme Court are scheduled for December 2, 2008 with a decision expected in 2009. 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.

PAGE 27

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 $35 million and $27 million in the fair value of our non-trading commodity-based financial derivatives as of September 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 purchased power, when combined with the settlement of commodity derivative instruments used for hedging purposes, will generally result in a range of prices for those purchases contemplated by the risk management strategy.

Interest Rate Risk

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

Investment Price Risk

We are subject to investment price risk due to securities held as investments in nuclear 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 nuclear decommissioning trust investments are recorded to regulatory liabilities.

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $27 million for the nine months ended September 30, 2008, and net realized gains (including investment income) of $24 million and $28 million for the nine months ended September 30, 2007 and for the year ended December 31, 2007, respectively. For the nine months ended September 30, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $129 million. For the nine months ended September 30, 2007, we recorded, in AOCI and regulatory liabilities, an increase in unrealized gains on these investments of $41 million. For the year ended December 31, 2007, we recorded, in AOCI and regulatory liabilities, an increase in unrealized gains on these investments of $13 million.

PAGE 28

Dominion sponsors employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. Declines in the values of investments held in these trusts, such as those experienced during 2008, will result in future increases in the periodic cost recognized for 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 29

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. We believe 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 other 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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 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 Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 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.

PAGE 30

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.

10.1		New Executive Supplemental Retirement Plan, as amended and restated, effective January 1, 2009 (filed herewith).

10.2		New Retirement Benefit Restoration Plan, as amended and restated, effective January 1, 2009 (filed herewith).

10.3		Form of Advancement of Expenses for certain directors and officers of Dominion, approved by the Dominion Board of Directors on October 24, 2008 (filed herewith).

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 31

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

October 30, 2008		/s/ Thomas P. Wohlfarth
		Thomas P. Wohlfarth
		Senior Vice President and Chief Accounting Officer

PAGE 32

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents