Edgar Filing: VIRGINIA ELECTRIC & POWER CO

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Amendment No.1 to Form 10-Q dated 3/31/2009

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(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

¨	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 (§232.405 of this chapter) 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.

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.

EXPLANATORY NOTE

Virginia Electric and Power Company is filing this Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, as filed with the Securities and Exchange Commission on April 30, 2009, in order to revise the Chief Executive Officer and Chief Financial Officer certifications filed as Exhibits 31.1 and 31.2 to the original Form 10-Q, which inadvertently omitted certain language regarding internal control over financial reporting required to be included in paragraph 4. This Form 10-Q/A is limited in scope to the foregoing, and should be read in conjunction with the original Form 10-Q and our other filings with the Securities and Exchange Commission.

The Financial Statements contained in Part I. Item 1 of the original Form 10-Q as well as the Controls and Procedures contained in Part I. Item 4 of the original Form 10-Q are reproduced in this amendment, but this amendment does not reflect events occurring after the filing of the original Form 10-Q or modify or update those disclosures affected by subsequent events. Except as described above, we have not modified or updated the disclosures or information presented in the original Form 10-Q.

TABLE OF CONTENTS


Part I.	Financial Information

	Item 1.	Consolidated Financial Statements

		Consolidated Statements of Income – Three Months Ended March 31, 2009 and 2008		1

		Consolidated Balance Sheets – March 31, 2009 and December 31, 2008		2

		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008		4

		Notes to Consolidated Financial Statements		5

	Item 4.	Controls and Procedures		15

Part II.	Other Information

	Item 6.	Exhibits		15

		31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

		31.2	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

		32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002

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.

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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.

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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.

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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.

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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.

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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

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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.

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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.

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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.

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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

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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

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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.

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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:

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.

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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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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.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

(a)

Exhibits:

31.1

Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

31.2

Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith)

Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith)

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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

By:		/s/ Ashwini Sawhney
		Ashwini Sawhney
		Vice President – Accounting
		(Chief Accounting Officer)

Date: October 13, 2009

EXHIBIT INDEX



31.1		Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company