10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended March 31, 2009

or

¨ 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    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  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

At March 31, 2009, the latest practicable date for determination, 209,833 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 Months Ended March 31, 2009 and 2008	4
	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008	5
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008	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	25
Item 4.	Controls and Procedures	26
PART II. Other Information
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 4.	Submission of Matters to a Vote of Security Holders	27
Item 6.	Exhibits	28

PAGE 2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
affiliates	Other Dominion subsidiaries
AOCI	Accumulated other comprehensive income (loss)
bcf	Billion cubic feet
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
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation No.
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
kWh	Kilowatt-hour
Lehman	Lehman Brothers Holdings, Inc.
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s	Moody’s Investors Service
Mw	Megawatt
mwhrs	Megawatt hours
North Anna	North Anna power station
NRC	Nuclear Regulatory Commission
Pennsylvania Commission	Pennsylvania Public Utility Commission
PJM	PJM Interconnection, LLC
ROE	Return on Equity
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
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 March 31,
	2009		2008
(millions)
Operating Revenue	$	1,859	$	1,524
Operating Expenses
Electric fuel and other energy-related purchases		794		497
Purchased electric capacity		108		106
Other operations and maintenance:
Affiliated suppliers		101		86
Other		246		219
Depreciation and amortization		157		149
Other taxes		51		49
Total operating expenses		1,457		1,106
Income from operations		402		418
Other income		9		9
Interest and related charges(1)		87		79
Income before income tax expense		324		348
Income tax expense		120		126
Net Income		204		222
Preferred dividends		4		4
Balance available for common stock	$	200	$	218

(1) Includes $8 million incurred with affiliated trusts for the three months ended March 31, 2008.

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

PAGE 4

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2009			December 31, 2008(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	27		$	27
Customer accounts receivable (less allowance for doubtful accounts of $9 and $8)		888			940
Other receivables (less allowance for doubtful accounts of $5 and $7)		53			82
Inventories (average cost method)		516			547
Regulatory assets		145			212
Other		75			103
Total current assets		1,704			1,911
Investments
Nuclear decommissioning trust funds		1,007			1,053
Other		3			3
Total investments		1,010			1,056
Property, Plant and Equipment
Property, plant and equipment		24,020			23,476
Accumulated depreciation and amortization		(9,049	)		(8,915	)
Total property, plant and equipment, net		14,971			14,561
Deferred Charges and Other Assets
Regulatory assets		869			921
Other		352			353
Total deferred charges and other assets		1,221			1,274
Total assets	$	18,906		$	18,802

(1) Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 5

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	March 31, 2009		December 31, 2008(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	125	$	125
Short-term debt		536		297
Accounts payable		451		436
Payables to affiliates		63		132
Affiliated current borrowings		209		417
Accrued interest, payroll and taxes		301		236
Other		340		386
Total current liabilities		2,025		2,029
Long-Term Debt		5,997		6,000
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,496		2,485
Asset retirement obligations		725		715
Regulatory liabilities		715		760
Other		315		282
Total deferred credits and other liabilities		4,251		4,242
Total liabilities		12,273		12,271
Commitments and Contingencies (see Note 8)
Preferred Stock Not Subject to Mandatory Redemption		257		257
Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; 209,833 shares outstanding		3,738		3,738
Other paid-in capital		1,110		1,110
Retained earnings		1,520		1,421
Accumulated other comprehensive income		8		5
Total common shareholder’s equity		6,376		6,274
Total liabilities and shareholder’s equity	$	18,906	$	18,802

(1) Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 6

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2009			2008
(millions)
Operating Activities
Net income	$	204		$	222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		184			173
Deferred income taxes and investment tax credits		(5	)		84
Other adjustments		1			(18	)
Changes in:
Accounts receivable		75			122
Affiliated accounts receivable and payable		(17	)		19
Inventories		31			13
Deferred fuel expenses		104			(145	)
Accounts payable		9			(161	)
Accrued interest, payroll and taxes		65			(29	)
Prepayments		(2	)		116
Other operating assets and liabilities		35			11
Net cash provided by operating activities		684			407
Investing Activities
Plant construction and other property additions		(515	)		(380	)
Purchases of nuclear fuel		(40	)		(19	)
Purchases of securities		(140	)		(125	)
Proceeds from sales of securities		137			121
Other		(50	)		19
Net cash used in investing activities		(608	)		(384	)
Financing Activities
Issuance of short-term debt, net		240			115
Repayment of affiliated current borrowings, net		(208	)		(10	)
Issuance of long-term debt		—			30
Repayment of long-term debt		(2	)		(33	)
Common dividend payments		(101	)		(115	)
Preferred dividend payments		(4	)		(4	)
Other		(1	)		(2	)
Net cash used in financing activities		(76	)		(19	)
Increase in cash and cash equivalents		—			4
Cash and cash equivalents at beginning of period		27			49
Cash and cash equivalents at end of period	$	27		$	53
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	128		$	8

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

PAGE 7

VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Virginia Electric and Power Company (Virginia Power) is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of March 31, 2009, 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.

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 Power, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power, 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 the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2008.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly our financial position as of March 31, 2009 and our results of operations and cash flows for the three months ended March 31, 2009 and 2008. Such adjustments are normal and recurring in nature unless otherwise noted.

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 4 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 other energy-related purchases and other factors.

PAGE 8

Note 3. Comprehensive Income

The following table presents total comprehensive income:

	Three Months Ended March 31,
	2009		2008
(millions)
Net income	$	204	$	222
Other comprehensive income (loss):
Net other comprehensive income associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		—		1
Other, net of tax		3		(5	)
Other comprehensive income (loss)		3		(4	)
Total comprehensive income	$	207	$	218

Note 4. Fair Value Measurements

Our fair value measurements are made in accordance with the policies discussed in Note 6 to our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 5 for further information about our derivatives and hedge accounting activities.

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:

	Level 1		Level 2		Level 3		Total
(millions)
As of March 31, 2009
Assets
Derivatives	$	—	$	50	$	2	$	52
Investments		211		680		—		891
Total assets		211		730		2		943
Liabilities
Derivatives	$	—	$	24	$	43	$	67
As of December 31, 2008
Assets
Derivatives	$	—	$	60	$	7	$	67
Investments		225		714		—		939
Total assets		225		774		7		1,006
Liabilities
Derivatives	$	—	$	23	$	76	$	99

PAGE 9

The following table presents the net changes in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

	Three Months Ended March 31,
	2009			2008
(millions)
Balance at January 1,	$	(69	)	$	(4	)
Total realized and unrealized gains or (losses):
Included in earnings		(51	)		19
Included in other comprehensive income (loss)		—			3
Included in regulatory assets/liabilities		23			33
Purchases, issuances and settlements		54			(16	)
Transfers out of Level 3		2			—
Balance at March 31,	$	(41	)	$	35
The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date	$	3		$	3

The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in our Consolidated Statement of Income for the three months ended March 31, 2009 and 2008.

As of March 31, 2009, our net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $41 million. A hypothetical 10% increase or decrease in commodity prices would not have a significant impact on the net liability.

Note 5. Derivatives and Hedge Accounting Activities

Our accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to our Annual Report on Form 10-K for the year ended December 31, 2008.

The following table presents the volume of our derivative activity as of March 31, 2009. These volumes are based on open derivative positions and represent the combined volume of our long and short positions on an absolute basis, except in the case of offsetting deals, for which we present the net volume of our long and short positions on an absolute basis. A substantial portion of our derivatives is designated under hedge accounting or is subject to regulatory accounting treatment.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price		13.6		—
Basis		6.8		—
Electricity (mwhrs):
Fixed price(1)		888,298		704,082
Financial transmission rights		17,964,826		1,171
Interest rate	$	610,000,000	$	550,000,000
Foreign currency (euros)		12,521,770		4,000,000

(1) Includes capacity derivatives.

PAGE 10

For the three months ended March 31, 2009 and 2008, gains or losses on hedging instruments determined to be ineffective and excluded from the measurement of ineffectiveness were not material. Amounts excluded from the measurement of ineffectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

At March 31, 2009, gains and losses included in AOCI and related amounts expected to be reclassified to earnings during the next twelve months were not material.

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives as of March 31, 2009 and where they are recorded on our Consolidated Balance Sheet:

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	19	$	2	$	21
Interest rate		5		—		5
Total current derivative assets(1)		24		2		26
Noncurrent Assets
Commodity		23		—		23
Interest rate		3		—		3
Total noncurrent derivative assets(2)		26		—		26
Total derivative assets		50		2		52
LIABILITIES
Current Liabilities
Commodity		9		43		52
Interest rate		8		—		8
Total current derivative liabilities(3)		17		43		60
Noncurrent Liabilities
Commodity		2		—		2
Interest rate		5		—		5
Total noncurrent derivative liabilities(4)		7		—		7
Total derivative liabilities	$	24	$	43	$	67

(1) Current derivative assets are recorded in other current assets on our Consolidated Balance Sheet.

(2) Noncurrent derivative assets are recorded in other deferred charges and other assets on our Consolidated Balance Sheet.

(3) Current derivative liabilities are recorded in other current liabilities on our Consolidated Balance Sheet.

(4) Noncurrent derivative liabilities are recorded in other deferred credits and other liabilities on our Consolidated Balance Sheet.

PAGE 11

The following tables present the gains and losses on our derivatives for the period ended March 31, 2009, as well as where the associated activity is presented on our Consolidated Balance Sheet and Statement of Income:

Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income			Amount of Gain (Loss) on Derivatives Subject to Regulatory Treatment(2)
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(5	)
Purchased electric capacity					2
Total commodity	$	(1	)		(3	)	$	(11	)
Interest rate(3)		(2	)		—			(11	)
Foreign currency(4)		—			—			2
Total	$	(3	)	$	(3	)	$	(20	)

(1) Amounts deferred into AOCI have no associated effect in our Consolidated Statement of Income.

(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in our Consolidated Statement of Income.

(3) Amounts recorded in our Consolidated Statement of Income are classified in interest expense.

(4) Amounts recorded in our Consolidated Statement of Income are classified in electric fuel and other energy-related purchases.

Derivatives not designated as hedging instruments under SFAS No. 133	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
(millions)
Derivative Type and Location of Gains (Losses)	$	(51	)
Commodity(2)
Total	$	(51	)

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect on our Consolidated Statement of Income.

(2) Amounts are recorded in electric fuel and other energy-related purchases in our Consolidated Statement of Income.

For the period, no significant gains or losses were recorded related to fair value hedging relationships.

See Note 4 for further information about fair value measurements and associated valuation methods for derivatives under SFAS No. 157.

Note 6. Variable Interest Entities

As discussed in Note 13 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, 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 46R, Consolidation of Variable Interest Entities.

We have long-term power and capacity contracts with four non-utility generators with an aggregate generation capacity of approximately 940 Mw. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that we consider to be variable interests. After an evaluation of the information provided to us by these entities, we were unable to determine whether they were variable interest entities (VIEs). However, the information they provided, as well as our knowledge of generation facilities in Virginia, enabled us to conclude that, if they were VIEs, we would not be the primary beneficiary. This conclusion was based primarily on a qualitative assessment of our variable interests as compared to the operations, commodity price and other risks retained by the equity and debt holders during the remaining terms of our contracts and for the years the entities are expected to operate after our contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. We are not subject to any risk of loss from these potential VIEs other than our remaining purchase commitments which totaled $1.9 billion as of March 31, 2009. We paid $53 million and $52 million for electric capacity and $41 million and $47 million for electric energy to these entities for the three months ended March 31, 2009 and 2008, respectively.

PAGE 12

We purchased shared services from Dominion Resources Services, Inc. (DRS), an affiliated VIE, of approximately $100 million and $86 million for the three months ended March 31, 2009 and 2008, respectively. We determined that we are not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including us. We have no obligation to absorb more than our allocated share of DRS costs.

Note 7. 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.

Our credit facility commitments are with a large consortium of banks, which included 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. In February 2009, we assigned $35 million of Lehman’s commitment to another bank. In March 2009, we executed a consent agreement with the bank syndicates to reduce Lehman’s remaining commitment to zero in each of our credit facilities in which it had participated.

Our short-term financing is supported by a $2.9 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.

At March 31, 2009, total outstanding commercial paper supported by the joint credit facility was $536 million, all of which were our borrowings, and the total outstanding letters of credit supported by the joint credit facility were $249 million, of which $180 million were issued on our behalf.

At March 31, 2009, capacity available under the joint credit facility was $2.1 billion.

In addition to the credit facility commitments of $2.9 billion disclosed above, we also have a $182 million five-year credit facility that supports certain Virginia Power tax-exempt financings.

Long-Term Debt

We repaid $2 million of long-term debt during the three months ended March 31, 2009.

Note 8. Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies as disclosed in Note 20 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, nor have any significant new matters arisen during the three months ended March 31, 2009.

Electric Regulation in Virginia

2007 Virginia Regulation Act

Pursuant to the Virginia Electric Utility Restructuring Act (the Regulation Act), the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. Possible outcomes of the 2009 rate review, according to the Regulation Act, include a rate increase, a rate decrease, or a partial refund of 2008 earnings more than 50 basis points above the authorized return on equity (ROE).

In March 2009, we submitted our base rate filing and accompanying schedules to the Virginia Commission. Our filing proposed to increase our Virginia jurisdictional base rates by approximately $298 million annually. We also proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on our generating plant performance, customer service and operating efficiency, resulting in a total ROE request of 13.5%. In April 2009, we submitted a revised filing that corrected certain plant balances. The corrected plant balances and related adjustments reduced our annual revenue requirement by

PAGE 13

approximately $9 million, to approximately $289 million. We proposed that the base rate increase become effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission. The proposed rate increase would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $6.10 per month.

In March 2009, we filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also includes a portion of costs discussed further in the RTO Start-up Costs and Administrative Fees section. If approved by the Virginia Commission, the rate adjustment clause would become effective September 1, 2009, and is expected to increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.26 per month.

In March 2009, we also filed with the Virginia Commission a revised notice of intent to file a petition for approval of a portfolio of thirteen demand side management (DSM) programs and a related rate adjustment clause on or after July 1, 2009. Our notice stated that, based on current projections and program assumptions, the revenue requirement for the DSM programs for the period January 1, 2010 through December 31, 2010 would be between $20 million and $30 million. If we file for the programs on or about July 1, 2009, by statute the Virginia Commission would have until March 1, 2010 to approve or disapprove of the rate adjustment clause for such programs.

We are unable to predict the outcome of the Virginia Commission’s future rate actions, including actions relating to our 2009 rate review, our recovery of Virginia fuel expenses and our additional rate adjustment clause filings discussed under Generation Expansion below; however, an unfavorable outcome could adversely affect our results of operations, financial condition and cash flows.

Virginia Fuel Expenses

In March 2009, we filed our Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh. The revised fuel factor includes recovery of approximately $505 million of our previous deferral balance that is eligible for recovery during the 2009 through 2010 fuel factor period pursuant to the fuel factor statute, as amended in 2007. This leaves approximately $23 million of the deferral balance to be collected during the 2010 through 2011 fuel factor period beginning July 1, 2010. If approved by the Virginia Commission, the revised fuel factor would become effective on July 1, 2009 and would decrease the typical 1,000 kWh Virginia jurisdictional residential customer’s average monthly bill by approximately $3.64, for the 2009 through 2010 fuel factor period.

Generation Expansion

The Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the proposed Virginia City Hybrid Energy Center, a 585 Mw (nominal) carbon-capture compatible, clean-coal powered electric generation facility located in Wise County, Virginia. In July 2008, the Southern Environmental Law Center, on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. In April 2009, the Virginia Supreme Court affirmed the Virginia Commission’s Final Order.

In March 2009, we filed with the Virginia Commission our first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Virginia City Hybrid Energy Center rate adjustment clause, plus the 100 basis point enhancement for construction of a new coal-fired generation facility as previously authorized by the Virginia Commission pursuant to the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the revised rate adjustment clause has been requested to become effective on January 1, 2010 and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by $1.78 per month.

In March 2009, the Virginia Commission authorized construction and operation of our proposed Bear Garden facility, a 580 Mw (nominal) natural gas- and oil-fired combined-cycle electric generating facility and associated transmission interconnection facilities in Buckingham County, Virginia, estimated to cost $619 million, excluding financing costs. In March 2009, we also filed a petition with the Virginia Commission for the initiation of a rate adjustment clause for recovery of approximately $77 million in financing costs related to construction of the Bear Garden facility to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a

PAGE 14

100 basis point enhancement for construction of a combined-cycle facility, as authorized in the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the rate adjustment clause has been requested to become effective January 1, 2010 and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by $1.40 per month.

Regional Transmission Expansion Plan

In June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011, one of which is an approximately 270-mile 500-kilovolt 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 (Meadow Brook-to-Loudoun line) and a subsidiary of Allegheny Energy, Inc. (Trans-Allegheny Interstate Line Company) will construct the remainder. 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 was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. As required by Virginia law, the Virginia Supreme Court issued orders in April 2009, accepting the appeals for rehearing. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and is expected to be completed in June 2011.

RTO Start-up Costs and Administrative Fees

In December 2008, FERC approved our Deferral Recovery Charge (DRC) request to become effective January 1, 2009, which would allow recovery of approximately $153 million of RTO costs ($140 million of our costs and $13 million of Dominion’s costs) that are being deferred due to a statutory base rate cap established under Virginia law. However, recovery of RTO costs through the DRC will not commence until the date established by the Virginia Commission that permits us to implement such recovery. In January 2009, requests for rehearing of the FERC order were filed and rehearing is pending. We cannot predict the outcome of the rehearing.

Spent Nuclear Fuel

As discussed in Note 20 to the Consolidated Financial Statements in our Annual Report on Form 10-K, we filed a lawsuit in the U.S. Court of Federal Claims against the Department of Energy (DOE) requesting damages in connection with its failure to commence accepting spent nuclear fuel. In October 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, and judgment was entered by the Court. In December 2008, the government appealed the judgment to the U.S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending spent fuel appeals. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. 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.

Guarantees and Surety Bonds

As of March 31, 2009, we had issued $16 million of guarantees primarily to support tax-exempt debt issued through conduits. We had also purchased $105 million of surety bonds for various purposes, including providing workers’ compensation coverage. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Note 9. Credit Risk

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2009 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.

PAGE 15

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

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At March 31, 2009, our gross credit exposure totaled $48 million. After the application of collateral, our credit exposure is reduced to $35 million. Of this amount, investment grade counterparties, including those internally rated, represented 71%, and no single counterparty exceeded 29%.

The majority of our derivative instruments contain credit-related contingent provisions. These provisions require us to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of March 31, 2009, we would be required to post an additional $3 million of collateral to our counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. As of March 31, 2009 we have not posted any collateral related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of March 31, 2009 is $2 million and does not include the impact of any offsetting asset positions. See Note 5 for further information about our derivative instruments.

Note 10. 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.

We receive a variety of services from DRS and other affiliates, primarily for accounting, legal, finance and certain administrative and technical services to us. In addition, we provide certain services to affiliates, including charges for facilities and equipment usage.

Presented below are significant transactions with DRS and other affiliates:

	Three Months Ended March 31,
	2009		2008
(millions)
Commodity purchases from affiliates	$	99	$	65
Services provided by affiliates		101		86

We have borrowed funds from Dominion under short-term borrowing arrangements. At March 31, 2009 and December 31, 2008, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $89 million and $198 million, respectively. Our short-term demand note borrowings from Dominion were $120 million and $219 million at March 31, 2009 and December 31, 2008, respectively. We incurred interest charges related to our borrowings from Dominion of $2 million and $1 million in the three months ended March 31, 2009 and 2008, respectively.

PAGE 16

Note 11. 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 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 three months ended March 31, 2009, our Corporate and Other segment included $12 million ($7 million after-tax) of expenses attributable to the Generation segment, reflecting net losses on investments in our nuclear decommissioning trusts. There were no expenses attributable to our operating segments included in the Corporate and Other segment in the three months ended March 31, 2008.

The following table presents segment information pertaining to our operations:

	DVP		Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended March 31,
2009
Operating revenue	$	380	$	1,479	$	—		$	1,859
Net income (loss)		90		121		(7	)		204
2008
Operating revenue	$	361	$	1,160	$	3		$	1,524
Net income		79		143		—			222

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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 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 gas emissions 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 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, including the outcome of our 2009 rate filings and the timing of our fuel cost recoveries;

• 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 factors that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results.

We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Accounting Matters

Critical Accounting Policies and Estimates

As of March 31, 2009, 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, 2008. The policies disclosed included the accounting for derivative contracts at fair value, regulated operations, asset retirement obligations, unbilled revenue and income taxes.

Results of Operations

Presented below is a summary of our consolidated results for the quarters ended March 31, 2009 and 2008:

	2009		2008		$ Change
(millions)
First Quarter
Net income	$	204	$	222	$	(18	)

Overview

Net income decreased 8% to $204 million, primarily resulting from an increase in scheduled outages in 2009 at certain of our generating facilities, higher salaries, wages and other benefits expenses and other general and administrative costs, higher interest and related charges and lower gains from sales of emissions allowances, partially offset by an increase in sales primarily due to an increase in heating degree days.

Analysis of Consolidated Operations

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

	First Quarter
	2009		2008		$ Change
(millions)
Operating Revenue	$	1,859	$	1,524	$	335
Operating Expenses
Electric fuel and other energy-related purchases		794		497		297
Purchased electric capacity		108		106		2
Other operations and maintenance		347		305		42
Depreciation and amortization		157		149		8
Other taxes		51		49		2
Other income		9		9		—
Interest and related charges		87		79		8
Income tax expense		120		126		(6	)

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An analysis of our results of operations for the first quarter of 2009 as compared to 2008 follows:

Operating Revenue increased 22% to $1.9 billion, primarily reflecting the combined effects of:

• A $288 million increase in fuel revenue primarily due to the impact of a comparatively higher fuel rate, including the recovery of previously deferred fuel costs, in certain customer jurisdictions;

• A $101 million increase in sales to retail customers due to a 20% increase in heating degree days; and

• A $22 million increase due to the impact of a rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center; partially offset by

• A $52 million decrease reflecting the impact of unfavorable economic conditions on customer usage and other factors; and

• A $27 million decrease in sales to wholesale customers due to decreased volumes ($19 million) and lower prices ($8 million).

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense increased 60% to $794 million, primarily reflecting a $294 million increase due to a comparatively higher fuel rate, including amortization of previously deferred fuel costs, in certain customer jurisdictions ($246 million) and higher volumes due to an increase in heating degree days ($91 million), partially offset by a decrease as a result of lower commodity prices, including purchased power ($43 million).

Other operations and maintenance expense increased 14% to $347 million, primarily reflecting:

• A $21 million increase in outage costs primarily related to the timing of scheduled nuclear refueling outages;

• An $18 million increase resulting from higher salaries, wages and other benefits expenses and other general and administrative costs; and

• An $11 million decrease in gains from the sale of emissions allowances held for consumption.

Interest and related charges increased 10% to $87 million, largely due to the impact of additional borrowings.

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income for the quarters ended March 31, 2009 and 2008:

	First Quarter
	2009			2008		$ Change
(millions)
DVP	$	90		$	79	$	11
Generation		121			143		(22	)
Primary operating segments		211			222		(11	)
Corporate and Other		(7	)		—		(7	)
Consolidated	$	204		$	222	$	(18	)

DVP

Presented below are operating statistics related to our DVP operations:

	First Quarter
	2009	2008	% Change
Electricity delivered (million mwhrs)	21.3	20.8	2	%
Degree days (electric service area):
Cooling(1)	4	3	33
Heating(2)	2,163	1,810	20
Average retail customer accounts (thousands)(3)	2,400	2,380	1

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

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

(3) Period average.

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

	First Quarter 2009 vs. 2008 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	16
Customer growth		2
Other(1)		(7	)
Change in net income contribution	$	11

(1) Decrease primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.

Generation

Presented below are operating statistics related to our Generation operations:

	First Quarter
	2009	2008	% Change
Electricity supplied (million mwhrs)	21.3	20.8	2	%
Degree days (electric service area):
Cooling	4	3	33
Heating	2,163	1,810	20

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

	First Quarter 2009 vs. 2008 Increase (Decrease)
(millions)
Outage costs	$	(13	)
Sales of emissions allowances		(7	)
Depreciation and amortization expense		(4	)
Ancillary service revenue		(4	)
Regulated electric sales:
Weather		28
Rate adjustment clause(1)		14
Customer growth		3
Other(2)		(27	)
Other		(12	)
Change in net income contribution	$	(22	)

(1) Reflects the impact of a new rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center.

(2) Decrease reflects the impact of unfavorable economic conditions on customer usage and other factors, as well as lower sales to wholesale customers.

PAGE 21

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 securities.

At March 31, 2009, we had $2.1 billion of unused capacity under our joint credit facility.

A summary of our cash flows for the three months ended March 31, 2009 and 2008 is presented below:

	2009			2008
(millions)
Cash and cash equivalents at January 1,	$	27		$	49
Cash flows provided by (used in)
Operating activities		684			407
Investing activities		(608	)		(384	)
Financing activities		(76	)		(19	)
Net increase in cash and cash equivalents		—			4
Cash and cash equivalents at March 31,	$	27		$	53

Operating Cash Flows

For the three months ended March 31, 2009, net cash provided by operating activities increased by $277 million as compared to the three months ended March 31, 2008. The increase is primarily due to a positive impact from deferred fuel cost recoveries in our Virginia jurisdiction and higher sales due to an increase in heating degree days. 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 our Annual Report on Form 10-K for the year ended December 31, 2008.

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 March 31, 2009, 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)	$	35	$	13	$	22
Non-investment grade(2)		10		—		10
No external ratings:
Internally rated—investment grade(3)		3		—		3
Internally rated—non-investment grade		—		—		—
Total	$	48	$	13	$	35

(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 58% of the total net credit exposure.

(2) The only counterparty exposure for this category represented approximately 29% of the total net credit exposure.

(3) The four largest counterparty exposures, combined, for this category represented approximately 8% of the total net credit exposure.

Investing Cash Flows

For the three months ended March 31, 2009, net cash used in investing activities increased by $224 million as compared to the three months ended March 31, 2008, primarily reflecting an increase in capital expenditures for generation and transmission construction projects, including our Virginia City Hybrid Energy Center.

PAGE 22

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 three months ended March 31, 2009, net cash used in financing activities increased by $57 million as compared to the three months ended March 31, 2008, primarily due to higher repayments of affiliated current borrowings, partially offset by higher net issuances of short-term debt.

See Note 7 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions. Also, see Note 10 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, 2008, 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 March 31, 2009, there have been no changes in our credit ratings, nor have there been any changes to or events of default under our debt covenants. In April 2009, Moody’s revised its credit ratings outlook for the Company to positive from stable.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of March 31, 2009, 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, 2008.

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 Item 1. Business and Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 8 to our Consolidated Financial Statements and Part II, Item 1. Legal Proceedings for additional information on various environmental, regulatory, legal and other matters that may impact our future results of operations and/or financial condition, including a discussion of electric regulation in Virginia.

North Anna Power Station

In January 2008, the Nuclear Regulatory Commission (NRC) accepted and deemed our application complete for a Combined Construction Permit and Operating License (COL) that references a specific reactor design and which would allow us to build and operate a new nuclear unit at North Anna power station (North Anna). In December 2008, we terminated a long-lead agreement with our vendor with respect to the reactor design identified in our COL application and certain related equipment. In March 2009, we commenced a competitive process to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to us. If, as a result of this process, we choose a different reactor design, we will amend our COL application, as necessary. We have not yet committed to building a new nuclear unit.

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.

Clean Water Act Compliance

In April 2008, the U.S. Supreme Court granted an industry request to review the question of whether Section 316b of the Clean Water Act authorizes the Environmental Protection Agency (EPA) to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting best technology available for

PAGE 23

reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in their ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. We have eight facilities that are likely to be subject to these regulations. We cannot predict the outcome of the EPA and state regulatory processes, nor can we determine with any certainty what specific controls may be required.

In October 2007, the Virginia State Water Control Board (Water Board) issued a renewed water discharge (VPDES) permit for North Anna. The Blue Ridge Environmental Defense League, and other persons, appealed the Water Board’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court remanded the permit to the Water Board for further review on a single issue regarding regulation of the thermal discharge from the North Anna into the waste heat treatment facility. Once the court signs the final order, unless a stay of the order is issued, the North Anna would operate pursuant to the previous VPDES permit until the Water Board reissues the permit or the court of appeals reverses the circuit court’s decision. We intend to appeal the court’s decision and ask for a stay of the court’s order. As a first step, we filed a motion for reconsideration with the court in February 2009 because one of the federal court cases the judge relied upon was recently overturned by the Fourth Circuit U.S. Court of Appeals. That motion is still pending. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

Global Climate Change

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions, which could result in future EPA action. In April 2009, the EPA issued a proposed finding for new motor vehicles and motor vehicle engines that greenhouse gases may endanger public health or welfare. The proposed finding, which now moves to a public comment period, identified six greenhouse gases that pose a potential threat. The EPA has stated that the proposed finding, as well as any final finding that is made in the future, would not itself impose any requirements on industry or other entities. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future greenhouse gas emission reduction programs on our operations or our customers at this time.

PAGE 24

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 and Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008 for discussion of various risks and uncertainties that may impact the Company.

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 as described below. Commodity price risk is due to our exposure to market shifts for prices paid for commodities. Interest rate risk is generally related to our outstanding debt. In addition, we are exposed to investment price risk through various portfolios of debt and 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 $19 million and $23 million in the fair value of our non-trading commodity-based financial derivatives as of March 31, 2009 and December 31, 2008, respectively.

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

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We may also enter into interest-rate swaps when deemed appropriate to adjust our exposure based upon market conditions. At March 31, 2009 and December 31, 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $1 million and $2 million, respectively.

Additionally, we may use forward-starting interest-rate swaps and treasury rate locks as anticipatory hedges of future financings. At March 31, 2009, we had $975 million in aggregate notional amounts of these interest-rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $25 million in the fair value of these interest-rate derivatives at March 31, 2009. We did not have a significant amount of these interest-rate derivatives outstanding at December 31, 2008.

The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net losses from interest-rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.

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Investment Price Risk

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

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $72 million, $7 million and $57 million for the three months ended March 31, 2009 and 2008 and for the year ended December 31, 2008, respectively. Net realized losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. For the three months ended March 31, 2009, we recorded, in AOCI and regulatory liabilities, an increase in unrealized gains on these investments of $23 million. For the three months ended March 31, 2008 and for the year ended December 31, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $59 million and $233 million, respectively.

Dominion sponsors employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. Investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that we will provide to Dominion for 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 26

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 and Note 8 to our Consolidated Financial Statements for discussions on various environmental, rate matters 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, 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, 2008. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

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

On April 24, 2009, by consent in lieu of the annual meeting, Dominion Resources, Inc., the sole holder of all the voting common stock of the Company, elected the following persons to serve as Directors: Thomas F. Farrell, II, Chairman of the Board, Thomas N. Chewning and Steven A. Rogers.

PAGE 27

ITEM 6. EXHIBITS

(a) Exhibits:

3.1	Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).
3.2	Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10-Q for the quarter ended March 31, 2000, File No. 1-2255, incorporated by reference).
4.1	Virginia Electric and Power Company agrees to furnish to the SEC upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.
12.1	Ratio of earnings to fixed charges (filed herewith).
12.2	Ratio of earnings to fixed charges and preferred dividends (filed herewith).
31.1	Certification by Registrant’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification by Registrant’s Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32	Certification to the SEC by Registrant’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99	Condensed consolidated earnings statements (unaudited) (filed herewith).

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
April 30, 2009	/s/ Thomas P. Wohlfarth
	Thomas P. Wohlfarth
	Senior Vice President and Chief Accounting Officer

PAGE 29

EX-12.1

Exhibit 12.1

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

					Years Ended December 31,
	Three Months Ended March 31, 2009		Twelve Months Ended March 31, 2009		2008		2007		2006		2005		2004
Earnings, as defined:
Earnings from continuing operations before income taxes and minority interests in consolidated subsidiaries	$	324	$	1,341	$	1,364	$	977	$	762	$	754	$	929
Fixed charges included in the determination of net income		98		353		343		328		313		333		258
Total earnings, as defined	$	422	$	1,694	$	1,707	$	1,305	$	1,075	$	1,087	$	1,187
Fixed charges, as defined:
Interest charges	$	93	$	340	$	330	$	320	$	311	$	329	$	256
Rental interest factor		4		14		13		12		11		10		9
Total fixed charges, as defined	$	97	$	354	$	343	$	332	$	322	$	339	$	265
Ratio of Earnings to Fixed Charges		4.35		4.79		4.98		3.93		3.34		3.21		4.48

EX-12.2

Exhibit 12.2

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends

(millions of dollars)

					Years Ended December 31,
	Three Months Ended March 31, 2009		Twelve Months Ended March 31, 2009		2008		2007		2006		2005		2004
Earnings, as defined:
Earnings from continuing operations before income taxes and minority interests in consolidated subsidiaries	$	324	$	1,341	$	1,364	$	977	$	762	$	754	$	929
Fixed charges included in the determination of net income		98		353		343		328		313		333		258
Total earnings, as defined	$	422	$	1,694	$	1,707	$	1,305	$	1,075	$	1,087	$	1,187
Fixed charges, as defined:
Interest charges	$	93	$	340	$	330	$	320	$	311	$	329	$	256
Preference security dividend requirements of consolidated subsidiaries		7		26		26		25		25		25		25
Rental interest factor		4		14		13		12		11		10		9
Total fixed charges, as defined	$	104	$	380	$	369	$	357	$	347	$	364	$	290
Ratio of Earnings to Fixed Charges and Preferred Dividends		4.06		4.46		4.63		3.66		3.10		2.99		4.09

EX-31.1

Exhibit 31.1

I, Thomas F. Farrell, II, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 30, 2009	/s/ Thomas F. Farrell, II
	Thomas F. Farrell, II
	Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Thomas N. Chewning, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 30, 2009	/s/ Thomas N. Chewning
	Thomas N. Chewning
	Executive Vice President and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 (the “Report”) of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2009 and for the period then ended.

/s/ Thomas F. Farrell, II

Thomas F. Farrell, II

Chief Executive Officer

April 30, 2009

/s/ Thomas N. Chewning

Thomas N. Chewning

Executive Vice President and Chief Financial Officer

April 30, 2009

EX-99

Exhibit 99

VIRGINIA ELECTRIC AND POWER COMPANY

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended March 31, 2009
(millions)
Operating Revenue	$	7,269
Operating Expenses		5,664
Income from operations		1,605
Other income		52
Interest and related charges		317
Income before income tax expense		1,340
Income tax expense		495
Net Income		845
Preferred dividends		16
Balance available for common stock	$	829