Edgar Filing: VIRGINIA ELECTRIC & POWER CO

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Amendment No. 1 to Form 10-Q dated 3/31/2008

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, 2008

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

For the transition period from to

Commission File Number 001-02255

VIRGINIA ELECTRIC AND POWER COMPANY

(Exact name of registrant as specified in its charter)


VIRGINIA		54-0418825
(State or other jurisdiction of inc orporation 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.



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, 2008, the latest practicable date for determination, 198,047 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, 2008, as filed with the Securities and Exchange Commission on May 1, 2008, 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.

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Part I.	Financial Information
	Item 1.	Consolidated Financial Statements
		Consolidated Statements of Income – Three Months Ended March 31, 2008 and 2007	1
		Consolidated Balance Sheets – March 31, 2008 and December 31, 2007	2
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2008 and 2007	4
		Notes to Consolidated Financial Statements	5

	Item 4.	Controls and Procedures	14

Part II.	Other Information

	Item 6.	Exhibits	14
		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

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VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,
	2008		2007
(millions)
Operating Revenue	$	1,524	$	1,443

Operating Expenses
Electric fuel and energy purchases		523		675
Purchased electric capacity		106		116
Other energy-related commodity purchases		4		8
Other operations and maintenance:
Affiliated suppliers		86		78
Other		189		206
Depreciation and amortization		149		134
Other taxes		49		45

Total operating expenses		1,106		1,262

Income from operations		418		181

Other income		9		23

Interest and related charges:
Interest expense		71		54
Interest expense—junior subordinated notes payable to affiliated trust		8		8

Total interest and related charges		79		62

Income before income tax expense		348		142
Income tax expense		126		53

Net Income		222		89
Preferred dividends		4		4

Balance available for common stock	$	218	$	85

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

PAGE 1

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2008			December 31, 2007⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	53		$	49
Customer accounts receivable (less allowance for doubtful accounts of $8 at both dates)		662			763
Affiliated receivables		1			53
Other receivables (less allowance for doubtful accounts of $8 and $9)		37			58
Inventories (average cost method)		507			520
Prepayments		49			165
Other		104			92

Total current assets		1,413			1,700

Investments
Nuclear decommissioning trust funds		1,274			1,339
Other		16			16

Total investments		1,290			1,355

Property, Plant and Equipment
Property, plant and equipment		22,195			21,838
Accumulated depreciation and amortization		(8,815	)		(8,702	)

Total property, plant and equipment, net		13,380			13,136

Deferred Charges and Other Assets
Regulatory assets		720			564
Other		346			308

Total deferred charges and other assets		1,066			872

Total assets	$	17,149		$	17,063

(1)

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

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

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	March 31, 2008		December 31, 2007⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	257	$	286
Short-term debt		372		257
Accounts payable		411		573
Payables to affiliates		47		80
Affiliated current borrowings		104		114
Other		453		473

Total current liabilities		1,644		1,783

Long-Term Debt
Long-term debt		4,932		4,904
Junior subordinated notes payable to affiliated trust		412		412

Total long-term debt		5,344		5,316

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,317		2,237
Regulatory liabilities		999		1,009
Other		948		920

Total deferred credits and other liabilities		4,264		4,166

Total liabilities		11,252		11,265

Commitments and Contingencies (see Note 11)
Preferred Stock Not Subject to Mandatory Redemption		257		257

Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; 198,047 shares outstanding		3,388		3,388
Other paid-in capital		1,109		1,109
Retained earnings		1,118		1,015
Accumulated other comprehensive income		25		29

Total common shareholder’s equity		5,640		5,541

Total liabilities and shareholder’s equity	$	17,149	$	17,063

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

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

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2008			2007
(millions)
Operating Activities
Net income	$	222		$	89
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		173			156
Deferred income taxes and investment tax credits, net		84			29
Other adjustments		(18	)		(19	)
Changes in:
Accounts receivable		122			20
Affiliated accounts receivable and payable		19			(20	)
Inventories		13			52
Deferred fuel expenses, net		(145	)		28
Accounts payable		(161	)		39
Accrued interest, payroll and taxes		(29	)		(32	)
Prepayments		116			79
Other operating assets and liabilities		11			88

Net cash provided by operating activities		407			509

Investing Activities
Plant construction and other property additions		(380	)		(220	)
Purchases of nuclear fuel		(19	)		(37	)
Purchases of securities		(125	)		(137	)
Proceeds from sales of securities		121			115
Other		19			(3	)

Net cash used in investing activities		(384	)		(282	)

Financing Activities
Issuance of short-term debt, net		115			722
Repayment of affiliated current borrowings, net		(10	)		(117	)
Issuance of long-term debt		30			—
Repayment of long-term debt		(33	)		(718	)
Common dividend payments		(115	)		(77	)
Preferred dividend payments		(4	)		(4	)
Other		(2	)		—

Net cash used in financing activities		(19	)		(194	)

Increase in cash and cash equivalents		4			33
Cash and cash equivalents at beginning of period		49			18

Cash and cash equivalents at end of period	$	53		$	51

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

The Company, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of March 31, 2008, we served approximately 2.4 million retail customer accounts, including governmental agencies, and wholesale customers such as rural electric cooperatives and municipalities. We are a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and our electric transmission facilities are integrated into the PJM wholesale electricity markets. 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 includes our corporate and other functions. Corporate and Other also includes specific items attributable to our operating segments that are not included in profit measures evaluated by executive management, in assessing the segments’ performance or allocating resources among the segments. Our assets remain wholly owned by us and our legal subsidiaries.

The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and our consolidated subsidiaries.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (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 U.S. generally accepted accounting principles (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2007.

In our opinion, our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of March 31, 2008, and our results of operations and cash flows for the three months ended March 31, 2008 and 2007.

We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries.

In accordance with GAAP, we report certain contracts and instruments at fair value. Observable market prices are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 7 for further information on fair value measurements in accordance with Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements.

The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, electric fuel and energy purchases and other factors.

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

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Note 3. Newly Adopted Accounting Standards

SFAS No. 157

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

Generally, the provisions of this statement are applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. Retrospective application did not result in a cumulative effect of accounting change in retained earnings as of January 1, 2008.

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

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

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

See Note 7 for further information on fair value measurements in accordance with SFAS No. 157.

SFAS No. 159

The provisions of SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, became effective for us beginning January 1, 2008. SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. As of March 31, 2008, we had not elected the fair value option for any eligible items. Therefore, the provisions of SFAS No. 159 have not impacted our results of operations or financial condition.

FSP FIN 39-1

FSP FIN 39-1 became effective for us beginning January 1, 2008. FSP FIN 39-1 amends FIN 39 to permit the offsetting of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset. Upon our adoption of FSP FIN 39-1, we revised our accounting policy to no longer offset fair value amounts recognized for certain derivative instruments and recast our prior year Consolidated Balance Sheet in order to retrospectively apply the standard. The adoption of FSP FIN 39-1 resulted in a $6 million increase in both Other current assets and Other current liabilities as of December 31, 2007. The provisions of FSP FIN 39-1 did not have an impact on our results of operations or cash flows.

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Note 4. Recently Issued Accounting Standards

SFAS No. 141R

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. SFAS No. 141R also requires disclosure of information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, SFAS No. 141R requires that acquisition-related costs be expensed as incurred. The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. SFAS No. 141R further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.

SFAS No. 161

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

Note 5. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended March 31,
	2008		2007
(millions)
Regulated electric sales	$	1,496	$	1,411
Other		28		32

Total operating revenue	$	1,524	$	1,443

Note 6. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended March 31,
	2008			2007
(millions)
Net income	$	222		$	89
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			7
Other, net of tax		(5	)		(2	)

Other comprehensive income (loss)		(4	)		5

Total comprehensive income	$	218		$	94

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Note 7. Fair Value Measurements

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

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

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

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

•

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

•

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

•

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

PAGE 8

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

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3. The following table presents, for each hierarchy level the Company’s assets and liabilities including both current and noncurrent portions, measured at fair value on a recurring basis as of March 31, 2008:


	Level 1		Level 2		Level 3		Total
(millions)
Assets:
Derivatives	$	—	$	62	$	37	$	99
Investments		317		835		—		1,152

Total		317		897		37		1,251

Liabilities:
Derivatives	$	—	$	3	$	2	$	5

The following table presents the changes in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended March 31, 2008:


(millions)	Derivatives ⁽¹⁾
Balance at January 1, 2008	$	(4	)
Total realized and unrealized gains or (losses):
Included in earnings		19
Included in other comprehensive income (loss)		3
Included in regulatory assets/liabilities		33
Purchases, issuances and settlements		(16	)

Balance at March 31, 2008	$	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

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

The following table presents gains and losses included in earnings in the Level 3 fair value category for the three months ended March 31, 2008:


(millions)	Electric Fuel and Energy Purchases		Other Operations and Maintenance		Total
Total gains or (losses) included in earnings	$	8	$	11	$	19
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

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Note 8. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products, as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to manage our exposure to these risks and designate derivative instruments as cash flow or fair value hedges for accounting purposes as allowed by SFAS No. 133. As discussed in Note 2 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, for certain jurisdictions subject to cost-based regulation, changes in the fair value of derivatives designated as hedges are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings.

For the three months ended March 31, 2008 and 2007, gains or losses on hedging instruments excluded from the measurement of effectiveness or determined to be ineffective were not material.

The following table presents selected information, for jurisdictions that are not subject to cost-based regulation, related to cash flow hedges included in accumulated other comprehensive income (AOCI) in our Consolidated Balance Sheet at March 31, 2008:


	AOCI After Tax		Portion Expected to be Reclassified to Earnings During the Next 12 Months After Tax		Maximum Term
(millions)
Electric capacity	$	8	$	3	38 months
Other		1		1	122 months

Total	$	9	$	4

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates.

Note 9. Variable Interest Entities

As discussed in Note 14 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered potential variable interests in the counterparties.

We have long-term power and capacity contracts with four potential variable interest entities (VIEs), which contain certain variable pricing mechanisms to the counterparty in the form of partial fuel reimbursement. We have concluded we are not the primary beneficiary of any of these potential VIEs. 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 $2.1 billion as of March 31, 2008. We paid $52 million and $55 million for electric capacity and $47 million and $41 million for electric energy to these entities for the three months ended March 31, 2008 and 2007, respectively.

We purchased approximately $86 million and $78 million of shared services from Dominion Resources Services, Inc. (DRS), a VIE of which we are not the primary beneficiary, during the three months ended March 31, 2008 and 2007, respectively.

Note 10. Significant Financing Transactions

Joint Credit Facilities and Short-term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. Short-term financing is supported by a $3.0 billion five-year joint revolving credit facility with Dominion dated February 2006, which is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion and us and other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.

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At March 31, 2008, total outstanding commercial paper supported by the joint credit facility was $522 million, of which our borrowings were $372 million, and the total amount of letter of credit issuances was $315 million, of which $19 million were issued on our behalf.

At March 31, 2008, capacity available under the joint credit facility was $2.2 billion.

Long-Term Debt

In November 2007, we borrowed $14 million in connection with the Economic Development Authority of the County of Chesterfield’s issuance of its Solid Waste and Sewage Disposal Revenue Bonds, Series 2007 A, which mature in 2031 and bear a coupon rate of 5.60%. The bonds were issued pursuant to a trust agreement whereby funds are withdrawn from the trust as improvements are made at our Chesterfield power station. We have withdrawn $6 million from the trust as of March 31, 2008.

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

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

We repaid $33 million of long-term debt during the three months ended March 31, 2008.

Note 11. Commitments and Contingencies

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

Litigation

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

Issues regarding the amount of Norfolk Southern’s claimed damages were tried before the trial court on April 8, 2008. On April 17, 2008, the trial court issued a Final Order and Decree. The court assessed damages of approximately $77.7 million for the contract period from December 1, 2003 through November 30, 2007, and imposed prejudgment interest of approximately $8.5 million, of which our share would be one-half. The court also ordered the two defendants to pay Norfolk Southern the higher rate adjustment factor for the remaining term of the agreement. Interest will be assessed on any difference between the amounts which we and ODEC pay to Norfolk Southern and the amounts which the court ordered to be paid. We believe the court’s interpretation of the transportation agreement and its ruling on other issues in the case are legally incorrect and we and ODEC will appeal the decision. No liability has been recorded in our Consolidated Financial Statements related to this matter.

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Guarantees and Surety Bonds

As of March 31, 2008, we had issued $17 million of guarantees primarily to support tax exempt debt issued through conduits. We had also purchased $55 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 12. Credit Risk

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2008 provision for credit losses, that it is unlikely a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At March 31, 2008, our gross credit exposure totaled $79 million. After the application of collateral, our credit exposure is reduced to $57 million. Of this amount, 27% related to a single counterparty; however, the entire balance is with investment grade entities, including those internally rated.

Note 13. Related Party Transactions

We engage in related-party transactions primarily with other Dominion subsidiaries (affiliates). Our receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. We also enter into certain commodity derivative contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with purchases of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

DRS provides accounting, legal and certain administrative and technical services to us. In addition, we provide certain services to affiliates, including charges for facilities and equipment usage.

Presented below are significant transactions with DRS and other affiliates:

At March 31, 2008 and December 31, 2007, our nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $104 million and $114 million, respectively. We incurred interest charges related to our borrowings from Dominion of $1 million and $3 million in the three months ended March 31, 2008 and 2007, respectively.

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Note 14. Operating Segments

We are organized primarily on the basis of the products and services we sell. The majority of our revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among our DVP and Generation segments. We manage our daily operations through the following segments:

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

Generation includes our generation and energy supply operations.

Corporate and Other includes our corporate and other functions. The contribution to net income by our primary operating segments is determined based on a measure of profit that management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management, either in assessing the segment’s performance or in allocating resources among the segments and are instead reported in the Corporate and Other segment. There were no expenses attributable to our operating segments included in the Corporate and Other segment in the three months ended March 31, 2008. For the three months ended March 31, 2007, the Corporate and Other segment included $6 million of after-tax expenses attributable to our operating segments.

The expenses in 2007 related to the following items attributable to our Generation segment:

•

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

•

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

The following table presents segment information pertaining to our operations:


	DVP		Generation			Corporate and Other			Consolidated Total
(millions)
Three Months Ended March 31,
2008
Operating revenue	$	361	$	1,160		$	3		$	1,524
Net income		79		143			—			222

2007
Operating revenue	$	363	$	1,078		$	2		$	1,443
Net income (loss)		97		(2	)		(6	)		89

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ITEM 4. CONTROLS AND PROCEDURES

Senior management, including our Chief Executive Officer (CEO) and Chief Financial Officer (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

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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

Three Months Ended
March 31,

(millions)

Commodity purchases from affiliates

Services provided by affiliates