Virginia Electric & Power 8-K Other events

Exhibit 99.4

Independent Auditors’ Report

To the Board of Directors of

Virginia Electric and Power Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 9 to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended. Also, as discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting used to develop the market-related value of pension plan assets in 2000.

/s/    DELOITTE & TOUCHE LLP

Richmond, Virginia

January 21, 2003

(May 7, 2003 as to the second paragraph of Note 1 and Note 26)

Virginia Electric and Power Company

Consolidated Statements of Income

	Year Ended December 31,
	2002			2001		2000
	(millions)
Operating Revenue	$	4,972		$	4,944	$	4,791
Operating Expenses
Electric fuel and energy purchases, net		1,281			1,252		1,104
Purchased electric capacity		691			680		740
Restructuring costs		(7	)		48		71
Other operations and maintenance		900			1,268		957
Depreciation and amortization		495			518		558
Other taxes		152			179		275
Total operating expenses		3,512			3,945		3,705
Income from operations		1,460			999		1,086
Other income		32			33		47
Interest and related charges:
Interest expense		275			289		285
Distributions—preferred securities of subsidiary trust		19			11		11
Total interest and related charges		294			300		296
Income before income taxes		1,198			732		837
Income taxes		425			286		279
Income before cumulative effect of a change in accounting principle		773			446		558
Cumulative effect of a change in accounting principle (net of income taxes of $11)		—			—		21
Net income		773			446		579
Preferred dividends		16			23		36
Balance available for common stock	$	757		$	423	$	543

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

Virginia Electric and Power Company

Consolidated Balance Sheets

	At December 31,
	2002		2001
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	132	$	84
Accounts receivable:
Customers (less allowance for doubtful accounts of $12 in 2002 and $23 in 2001)		1,758		1,105
Other		73		57
Receivables from affiliates		41		54
Inventories (average cost method):
Materials and supplies		166		163
Fossil fuel		133		149
Gas stored		147		59
Derivative and energy trading assets		1,261		1,039
Prepayments		47		140
Other		108		71
Total current assets		3,866		2,921
Investments
Nuclear decommissioning trust funds		838		858
Other		22		25
Total investments		860		883
Property, Plant and Equipment
Property, plant and equipment		17,797		17,232
Less accumulated depreciation and amortization		8,240		7,985
Total property, plant and equipment, net		9,557		9,247
Deferred Charges and Other Assets
Intangible assets, net		129		113
Regulatory assets, net		239		231
Derivative and energy trading assets		402		323
Other		110		66
Total deferred charges and other assets		880		733
Total assets	$	15,163	$	13,784

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

Virginia Electric and Power Company

Consolidated Balance Sheets (Continued)

	At December 31,
	2002		2001
	(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	360	$	535
Short-term debt		443		436
Accounts payable, trade		1,591		1,014
Payables to affiliates		56		192
Affiliated current borrowings		100		—
Accrued interest, payroll and taxes		207		214
Derivative and energy trading liabilities		1,206		1,010
Other		206		218
Total current liabilities		4,169		3,619
Long-Term Debt		3,794		3,704
Deferred Credits And Other Liabilities
Deferred income taxes		1,667		1,537
Deferred investment tax credits		96		113
Derivative and energy trading liabilities		279		246
Other		170		170
Total deferred credits and other liabilities		2,212		2,066
Total liabilities		10,175		9,389
Commitments And Contingencies (See Note 21)
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust(1)		400		135
Preferred Stock Not Subject To Mandatory Redemption		257		384
Common Shareholder’s Equity
Common stock, no par, authorized—300,000 shares; outstanding—177,932 shares at 2002 and 171,484 at 2001		2,888		2,738
Other paid-in capital		16		14
Accumulated other comprehensive income (loss)		8		(4	)
Retained earnings		1,419		1,128
Total common shareholder’s equity		4,331		3,876
Total liabilities and shareholder’s equity	$	15,163	$	13,784

⁽¹⁾ As described in Note 16 to Consolidated Financial Statements, the debt securities issued by Virginia Electric and Power Company constitute 100 percent of the Trust’s assets.

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

Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity

	Common Stock			Other Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	Shares	Amount
	(shares in thousands, all other amounts in millions)
Balance at January 1, 2000	172	$	2,738	$	17					$	988		$	3,743
Comprehensive income											579			579
Dividends and other adjustments											(444	)		(444	)
Other					(1	)					(28	)		(29	)
Balance at December 31, 2000	172		2,738		16						1,095			3,849
Comprehensive income (loss)							$	(4	)		446			442
Dividends and other adjustments					(2	)					(413	)		(415	)
Balance at December 31, 2001	172		2,738		14			(4	)		1,128			3,876
Issuance of stock to parent	6		150											150
Tax benefit from stock options exercised					1									1
Comprehensive income								12			773			785
Dividends and other adjustments					1						(482	)		(481	)
Balance at December 31, 2002	178	$	2,888	$	16		$	8		$	1,419		$	4,331

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

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

	Year Ended December 31,
	2002		2001
	(millions)
Net income	$	773	$	446
Other comprehensive income, net of taxes:
Net deferred gains (losses) on derivatives—hedging activities, net of tax (expense) benefit of $(4) and $1		7		(1	)
Cumulative effect of a change in accounting principle, net of tax benefit of $9				(14	)
Amounts reclassified to net income:
Net losses on derivatives—hedging activities, net of tax expense (benefit) of $(2) and $(7)		5		11
Other comprehensive income (loss)		12		(4	)
Comprehensive income	$	785	$	442

The Company’s net income was $579 million for 2000. The Company had no other comprehensive income reportable for that year in accordance with SFAS No. 130,Reporting Comprehensive Income.

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

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2002			2001			2000
	(millions)
Operating Activities
Net income	$	773		$	446		$	579
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of a change in accounting principle, net of income taxes								(21	)
Depreciation and amortization		570			588			637
Deferred income taxes and investment tax credits		97			51			10
Deferred fuel expenses, net		(20	)		(24	)		(33	)
Changes in:
Accounts receivable		(669	)		54			(496	)
Affiliated accounts receivable and payable		(16	)		46			94
Inventories		(75	)		(140	)		4
Prepayments		138			(36	)		(48	)
Accounts payable, trade		577			132			365
Accrued interest, payroll and taxes		(5	)		(23	)		5
Other		(98	)		(13	)		(2	)
Net cash provided by operating activities		1,272			1,081			1,094
Investing Activities
Plant construction and other property additions		(748	)		(668	)		(652	)
Nuclear fuel		(59	)		(83	)		(82	)
Nuclear decommissioning contributions		(36	)		(36	)		(36	)
Other		(14	)		54			—
Net cash flows used in investing activities		(857	)		(733	)		(770	)
Financing Activities
Issuance (repayment) of short-term debt, net		7			(278	)		336
Short-term borrowings from parent, net		100			—			—
Issuance of preferred securities of subsidiary trusts		400			—			—
Repayment of preferred securities of subsidiary trusts		(135	)		—			—
Issuance of long-term debt and preferred stock		658			770			250
Repayment of long-term debt and preferred stock		(887	)		(473	)		(376	)
Common stock dividend payments		(467	)		(392	)		(408	)
Preferred stock dividend payments		(15	)		(25	)		(36	)
Other		(28	)		(7	)		(11	)
Net cash flows used in financing activities		(367	)		(405	)		(245	)
Increase (decrease) in cash and cash equivalents		48			(57	)		79
Cash and cash equivalents at beginning of year		84			141			62
Cash and cash equivalents at end of year	$	132		$	84		$	141
Supplemental Cash Flow Information
Cash paid for:
Interest and related charges, excluding amounts capitalized	$	278		$	298		$	302
Income taxes		165			145			331
Non-cash transactions from financing activities:
Non-cash exchange of mortgage bonds for senior notes		117			—			—
Issuance of common stock in exchange for reduction in amounts payable to parent		150			—			—
Conveyance of telecommunications subsidiary to parent, net of cash		—			—			19

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

Virginia Electric and Power Company

Notes to Consolidated Financial Statements

Note 1. Nature of Operations

Virginia Electric and Power Company (Virginia Power or the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company is a regulated public utility that generates, transmits and distributes electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to approximately 2.2 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia’s total land area but accounts for over 80 percent of its population. The Company has trading relationships beyond the geographic limits of its retail service territory and buys and sells wholesale electricity and natural gas off-system. Within this document, the term “Company” refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations, and all of its subsidiaries.

The Company manages its daily operations along two operating segments, Energy and Delivery. The Energy segment encompasses the Company’s portfolio of generating facilities and power purchase contracts and its trading and marketing activities and electric transmission system. The Delivery segment includes distribution and metering services and customer service. The Delivery segment is subject to cost-of-service rate regulation and Statement of Financial Accounting Standards (SFAS) No. 71,Accounting for the Effects of Certain Types of Regulation(SFAS No. 71).

Note 2. Significant Accounting Policies

General

The Company makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). 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 revenues and expenses for the periods presented. Actual results may differ from those estimates.

The Consolidated Financial Statements represent the Company’s accounts after the elimination of intercompany transactions.

Certain amounts in the 2001 and 2000 Consolidated Financial Statements have been reclassified to conform to the 2002 presentation.

Use of Fair Value Measurements

The Company reports certain contracts and instruments at fair value in accordance with applicable generally accepted accounting principles. Fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.

For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company uses a modified Black-Scholes model and considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. For contracts with unique characteristics, the Company estimates 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 assumptions could have a material effect on the contract’s estimated fair value.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Revenue from energy trading activities includes realized commodity contract revenue, net of related cost of sales, and unrealized gains and losses from marking to market those commodity contracts not yet settled. See Note 5. Beginning October 25, 2002 and January 1, 2003, in accordance with new accounting requirements

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

as discussed further in Note 4, the Company discontinued marking to market unsettled commodity contracts that are not otherwise accounted for as derivatives under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

Electric Fuel and Purchased Energy—Deferred Costs

Where permitted by regulatory authorities, the differences between actual electric fuel and purchased energy and the levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. Approximately 94 percent of rate regulated fuel costs are subject to deferral accounting. SeeRegulatory Assets and Liabilitiesbelow and Note 10.

Income Taxes

The Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. However, under the Public Utility Holding Company Act of 1935 (1935 Act) and the intercompany tax allocation agreement, the Company’s cash payments to Dominion are reduced for a portion of income tax benefits realized by Dominion as a result of filing consolidated returns. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of SFAS No. 109,Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits.

Stock-based Compensation

Employees of the Company may receive stock-based awards, such as stock options and restricted stock, granted under Dominion-sponsored stock plans. The Company measures compensation cost for stock-based awards issued to its employees in accordance with Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations. Compensation expense is measured based on the intrinsic value, the difference between fair market value of Dominion common stock and the exercise price of the underlying award, on the date when both the price and number of shares the recipient is entitled to receive are known, generally the grant date. Compensation expense, if any, is recognized on a straight-line basis over the stated vesting period of the award. Compensation expense associated with these awards was not material in 2002, 2001 and 2000. The pro forma impact on net income, had the Company measured compensation expense based on the fair value of the options on the date of grant, would not have been material for 2002, 2001 and 2000.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2002 and 2001, the Company’s accounts payable included the net effect of checks outstanding but not yet presented for payment of $39 million and $100 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Margin Deposit Assets and Liabilities

Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from the Company exceeding agreed-upon credit limits established by the counterparties. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from various trading counterparties exceeding agreed-upon credit limits established by the Company. These credit limits and the mechanism for calculating the amounts to be held on deposit are determined in the International Swap Dealers Association master agreements and the Master Power Purchase and Sale Agreement of the Edison Electric Institute in place between the Company and the counterparties. As of December 31, 2002 and December 31, 2001, the Company had margin deposit assets of $52 million and $10 million, respectively. Margin deposit liabilities were $22 million at December 31, 2002, and there were no margin deposit liabilities at December 31, 2001. These amounts are reflected in other current assets and other current liabilities.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, other direct costs and capitalized interest. The costs of repairs and maintenance, including minor additions and replacements, are charged to expense as incurred. In 2002, 2001 and 2000, the Company capitalized interest costs of $17 million, $20 million and $18 million, respectively.

For electric distribution and transmission property subject to cost-of-service utility rate regulation, the cost of such property and related cost of removal, less salvage, are charged to accumulated depreciation at retirement. For generation-related property, cost of removal is charged to expense as incurred. The Company records gains and losses upon retirement of generation-related property based upon the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Company’s depreciation rates on property, plant and equipment for 2002, 2001 and 2000 are as follows: generation—1.88 percent, 2.10 percent, 2.80 percent, respectively; transmission—2.14 percent, 2.75 percent, 2.74 percent, respectively; distribution—3.55 percent, 3.77 percent, 3.81 percent, respectively; and general—5.24 percent, 4.30 percent, 4.46 percent, respectively. Amortization of nuclear fuel used in electric generation is provided on a unit-of-production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs.

In 2002, the Company extended the estimated useful lives of most of its fossil fuel stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. These changes in estimated useful lives reduced depreciation expense by approximately $40 million for the entirety of 2002 and will reduce depreciation expense approximately $64 million on an annual basis thereafter. In 2001, the Company increased its estimate of the useful lives of its nuclear facilities by 20 years, which reduced depreciation expense by approximately $72 million for the entirety of 2001 and on an annual basis thereafter. This change in estimate was made in connection with the filing of applications for license extensions with the Nuclear Regulatory Commission (NRC).

For a discussion of a change in the accounting for future decommissioning costs, seeAsset Retirement Obligations in Note 4.

Derivative Instruments

The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity, currency exchange and financial market risks of its business operations. The Company also manages a portfolio of commodity contracts held for trading purposes as part of its strategy to market energy and to manage related risks. Derivative instruments are generally recognized on the Consolidated Balance Sheets at fair value. See Note 9 for further discussion of the Company’s use of derivative instruments and energy trading contracts, including its risk management policy, its accounting policy for derivatives under SFAS No. 133 and the results of its hedging activities for the years ended December 31, 2002 and 2001.

Prior to January 1, 2001, the Company considered derivative instruments to be effective hedges when the item being hedged and the underlying financial instrument or commodity contract showed strong historical correlation. The Company used deferral accounting to account for futures, forwards and other derivative instruments that were designated as hedges. Under this method, realized gains and losses (including the payment of any premium) related to effective hedges of existing assets and liabilities were recognized in earnings in conjunction with the designated asset or liability. Gains and losses related to effective hedges of firm commitments and anticipated transactions were included in the measurement of the subsequent transaction.

Impairment of Long-Lived and Intangible Assets

The Company performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amounts.

Regulatory Assets and Liabilities

Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

regulation may differ from accounting methods generally applied by nonregulated companies. The economic effects of allocations prescribed by regulatory authorities for rate-making purposes must be considered in the application of generally accepted accounting principles. See Notes 10 and 21 for additional information on regulatory assets and liabilities and the impact of legislation on continued application of SFAS No. 71.

Amortization of Debt Issuance Costs

The Company defers and amortizes debt issuance costs and debt premiums or discounts over the lives of the respective debt issues. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and amortized over the lives of the new issues.

Note 3. Accounting Change for Pension Costs

Effective January 1, 2000 and in connection with Dominion’s acquisition of the Consolidated Natural Gas Company (CNG), Dominion and its subsidiaries, including the Company, adopted a new company-wide method of calculating the market-related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. Management believes the new method enhances the predictability of the expected return on pension plan assets; provides consistent treatment of all investment gains and losses; and results in calculated market-related pension plan asset values that are closer to market value than the values calculated under the pre-acquisition methods used by Dominion and CNG.

As the primary participating employer in the Dominion Resources Retirement Plan in 2000, the Company recorded its proportionate share of the cumulative effect of the change in accounting principle, $21 million (net of income taxes of $11 million). Other than the impact of the cumulative effect of the change in accounting principle, the effect of the change on net income for 2000 was not material.

Note 4. Recently Issued Accounting Standards

Asset Retirement Obligations

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143,Accounting for AssetRetirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The Company adopted the standard effective January 1, 2003.

The Company has identified certain asset retirement obligations that are subject to the standard. These obligations are primarily associated with the decommissioning of its nuclear generation facilities.

Under SFAS No. 143, asset retirement obligations will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Under the present value approach used to estimate the fair value of asset retirement obligations, accretion of the liabilities due to the passage of time will be recognized as an operating expense. As a result, the adoption of SFAS No. 143 requires changes in the Company’s accounting and reporting for certain asset retirement obligations already being recognized under its accounting policies prior to the adoption of SFAS No. 143. For example, the Company already recognizes amounts related to future decommissioning activities at its utility nuclear plants. As discussed in Note 8, the accumulated provision for decommissioning is presented on the balance sheet at December 31, 2002 as a component of accumulated depreciation. Under SFAS No. 143, the asset retirement obligation will be reported as a liability.

In addition, the reporting of realized and unrealized earnings of external trusts available for funding decommissioning activities at the Company’s nuclear plants will be recorded in other income and other comprehensive income, as appropriate. Through 2002, the Company recorded these trusts’ earnings in other income with an offsetting charge to expense, also recorded in other income, for the accretion of the decommissioning liability.

On January 1, 2003, the Company implemented SFAS No. 143 and recognized an after-tax gain of $139 million, representing the cumulative effect of a change in accounting principle. Under the Company’s accounting policy prior to the adoption of SFAS No. 143, $838 million had previously been accrued for future asset removal costs, primarily related to future nuclear decommissioning. Such amounts are included in the accumulated provision for depreciation and amortization as of December 31, 2002. With the adoption of SFAS No. 143, the Company calculated its

asset retirement obligations to be $697 million. In recording the cumulative effect of the accounting change, the Company recognized the reduction attributable to the re-measurement of asset retirement obligations and reclassified such amount from the accumulated provision for depreciation and amortization to other non-current liabilities. The cumulative effect of the accounting change also reflected a $175 million increase in property, plant and equipment for capitalized asset retirement costs and a $77 million increase in the accumulated provision for depreciation and amortization, representing the depreciation of such costs through December 31, 2002.

In accordance with SFAS No. 71, the Company will continue its practice of accruing for future costs of removal for its cost-of-service rate regulated electric transmission and distribution assets, even if no legal obligation to perform such activities exists. At December 31, 2002, the Company’s accumulated depreciation and amortization included $375 million, representing the estimated costs of such removal activities.

Energy Trading Contracts

In October 2002, the Emerging Issues Task Force (EITF) rescinded EITF Issue No. 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities(EITF 98-10).As a result, certain energy-related commodity contracts held for trading purposes will no longer be subject to fair value accounting. The affected contracts are those energy-related contracts, held for trading purposes that are not considered derivatives under SFAS No. 133. Under EITF 98-10 accounting, the fair value of energy contracts was measured at each reporting date, with changes in fair value, including unrealized amounts, reported in earnings. Energy-related contracts affected by the rescission of EITF 98-10 will be subject to accrual accounting and recognized as revenue or expense at the time of contract performance, settlement or termination.

The rescission of EITF 98-10 primarily affects the timing of recognition in earnings from the Company’s energy-related trading contracts. In addition, affected contracts will no longer be reported at fair value on the Company’s balance sheet. The EITF 98-10 rescission was effective for all non-derivative energy trading contracts initiated after October 25, 2002. As a result of implementing the change for all non-derivative energy trading contracts initiated prior to October 25, 2002, the Company recognized a loss of $55 million (net of taxes of $35 million) as the cumulative effect of this change in accounting principle effective January 1, 2003.

Accounting For Guarantees

In November 2002, FASB issued Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—An Interpretation of FASB Statements No. 5, 57 and 107. Under the Interpretation, issuers of certain types of guarantees must recognize a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. In addition, the Interpretation requires increased disclosures for specific types of guarantees.

The Interpretation’s initial recognition requirements apply only to guarantees issued or modified after December 31, 2002. The Company does not anticipate any material impact on its future results of operations or financial condition as a result of recording newly issued or modified guarantees at fair value. The Interpretation’s disclosure requirements are effective for financial statements ending after December 15, 2002.

Consolidation of Variable Interest Entities

In January 2003, FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, which addresses consolidation by business enterprises of entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. These entities have been commonly referred to as “special purpose entities.” The underlying principle behind the new Interpretation is that if a business enterprise has the majority financial interest in an entity, defined in the guidance as a variable interest entity, the assets, liabilities, and results of the activities of the variable interest entity should be included in consolidated financial statements with those of the business enterprise. The Interpretation explains how to identify variable interest entities and how an enterprise should assess its interest in an entity to decide whether to consolidate that entity. The Company will apply the provisions of the Interpretation prospectively for all variable interest entities created after January 31, 2003. For variable interest entities created before January 31, 2003, the Company will be required to consolidate all

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

entities in which it was deemed to be the primary beneficiary beginning July 1, 2003. The Company does not anticipate that the adoption of the Interpretation will have a material impact on its results of operations or financial condition.

SFAS No. 133 Guidance

In connection with the January 2003 EITF meeting, FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group’s C11 guidance, relates to contracts with pricing terms that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has certain power purchase and sale contracts that are subject to the guidance addressed in the request for reconsideration. The aggregate fair value of these contracts at December 31, 2002 represented an estimated pretax net unrealized loss of $120 million. The Company is currently evaluating the implementation that would ultimately be required as a result of the guidance being clarified. When these Company contracts are considered with other Dominion subsidiaries’ contracts that are subject to the guidance, Dominion estimates that the aggregate fair value of the contracts is not a material amount.

Note 5. Operating Revenue

	Year Ended December 31,
	2002		2001		2000
	(millions)
Regulated electric sales	$	4,857	$	4,620	$	4,492
Other		115		324		299
Total operating revenue	$	4,972	$	4,944	$	4,791

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation. The Company’s customer accounts receivable at December 31, 2002 and 2001 includes $231 million and $181 million, respectively, of accrued unbilled revenue based on estimated electric energy delivered but not yet billed to its utility customers. Considering historical usage and applicable customer rates, the Company estimates unbilled utility revenue based on total daily electric generation supplied, after adjusting for estimated losses of energy during transmission, and weather factors.

Other revenue includes revenue from energy trading activities, sales of electricity and natural gas at market-based rates, brokered gas sales, service fees associated with rate-regulated electric distribution and other miscellaneous revenue. Revenue from energy trading activities includes realized contract settlements, net of related cost of sales, and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled.

Note 6. Restructuring Costs

2001 Restructuring Costs

In the fourth quarter of 2001, after fully integrating CNG into Dominion’s existing organization and operations, including those of the Company, management initiated a focused review of Dominion’s combined operations and developed a plan of reorganization. As a result, the Company recognized $48 million of restructuring costs which included employee severance and termination benefits and the abandonment of leased office space no longer needed.

The Company recorded $42 million in total severance and related costs, including $26 million billed to the Company by Dominion Resources Services, Inc. (Dominion Services). Under the 2001 restructuring plan, the Company identified 124 positions to be eliminated and recorded $16 million in employee severance-related costs. Severance payments were based on the individual’s base salary and years of service at the time of termination. In 2002, the Company recorded a $7 million adjustment to the liability for severance and related costs and reported it in restructuring costs in the Consolidated Statement of Income. With 89 positions actually being eliminated under the plan, the adjustment reflected a reduction in the number of employee positions being eliminated and a reduction for differences between actual and estimated base salaries and years of service for those employees actually terminated under the plan.

Restructuring and related costs for the year ended December 31, 2001 were as follows:

	(millions)
Severance and related costs	$	16
Severance and related costs—Dominion Services(1)		26
Other(2)		6
Total restructuring costs	$	48

⁽¹⁾ Dominion Services, a subsidiary service company under the 1935 Act, provides certain services to Dominion’s operating subsidiaries. Accordingly, charges are allocated and billed among the operating subsidiaries in accordance with predefined service agreements. See Note 24.

⁽²⁾ Includes charges for abandonment of leased office space and related costs by the Company and Dominion Services.

The change in the liability for severance and related costs during 2002 is presented below:

	Severance Liability
	(millions)
Balance at December 31, 2001	$	16
Amounts paid		(5	)
Revision of estimates		(7	)
Balance at December 31, 2002	$	4

2000 Restructuring Costs

In 2000, following the acquisition of CNG by Dominion, Dominion and its subsidiaries implemented a plan to restructure the operations of the combined companies. The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP) and a transition plan to implement operational changes to provide efficiencies, including the consolidation of post-merger operations and the integration of information technology systems. Through December 31, 2001, a total of 174 positions had been eliminated, and approximately $13 million of severance benefits had been paid. Severance payments were based on the individual’s base salary and years-of- service at the time of termination. During 2000, approximately 400 Company employees elected to participate in the ERP, resulting in an expense approximating $51 million. Some of the ERP participants also received benefits under the involuntary severance package; benefits under the involuntary severance package were subject to reductions as a result of coordination with the additional retirement plan benefits provided by the ERP.

For the year ended December 31, 2000, the Company recorded $71 million for charges in connection with the 2000 restructuring plan, as follows:

n  $14 million under an involuntary severance program (discussed above);

n  $51 million under the ERP; and

n  $6 million of other costs related to consolidation and integration of business operations and administrative functions.

Note 7. Income Taxes

Details of income tax expense were as follows:

	Year Ended December 31,
	2002			2001			2000
	(millions)
Current expense:
Federal	$	297		$	198		$	262
State		30			37			7
Total current		327			235			269
Deferred expense (benefit):
Federal		90			50			32
State		25			18			(5	)
Total deferred		115			68			27
Amortization of deferred investment tax credits, net		(17	)		(17	)		(17	)
Total income tax expense	$	425		$	286		$	279

The statutory U.S. federal income rate reconciles to the effective income tax rates as follows:

	Year Ended December 31,
	2002		2001		2000
U.S statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Utility plant differences	(.2	)	.7		.4
Amortization of investment tax credits	(1.1	)	(1.8	)	(1.4	)
State income tax, net of federal tax benefit	3.0		4.9		.2
Other, net	(1.2	)	.3		(.9	)
Effective tax rate	35.5	%	39.1	%	33.3	%

The Company’s effective income tax rate decreased in 2002 due to a net benefit related to permanent differences, a reduction in percentages of state income taxes to book income and a decrease in book depreciation of regulated assets. The Company’s effective income tax rate increased in 2001 due to its utility operations in Virginia becoming subject to state income taxes in lieu of gross receipts taxes.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

Company’s net accumulated deferred income taxes consist of the following:

	At December 31,
	2002		2001
	(millions)
Deferred income tax assets:
Deferred investment tax credits	$	36	$	43
Other		49		37
Total deferred income tax assets		85		80
Deferred income tax liabilities:
Depreciation method and plant basis differences		1,561		1,479
Income taxes recoverable through future rates		15		19
Deferred state income tax		69		52
Other		58		30
Total deferred income tax liabilities		1,703		1,580
Total net deferred income tax liabilities(1)	$	1,618	$	1,500

⁽¹⁾ For 2002 and 2001, amounts include $49 million and $37 million, respectively, of current deferred tax assets reported in other current assets.

Note 8. Nuclear Operations

The Company has four licensed nuclear reactors at its Surry and North Anna plants in Virginia that serve customers of its regulated electric utility operations. Decommissioning represents the decontamination and removal of radioactive contaminants from a nuclear power plant, once operations have ceased, in accordance with standards established by the NRC. Through June 2007, amounts are being collected from Virginia jurisdictional ratepayers and placed in external trusts and invested to fund the expected costs of decommissioning the Surry and North Anna units.

Accounting for Decommissioning

In accordance with the accounting policy recognized by regulatory authorities having jurisdiction over its electric utility operations, the Company recognizes an expense for the future cost of decommissioning in amounts equal to amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of the Company’s nuclear plants. On the Consolidated Balance Sheets, the external trusts are reported at fair value with the accumulated provision for decommissioning included in accumulated depreciation. Net realized and unrealized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommissioning, are recorded as a component of other income(loss), as permitted by regulatory authorities. See Note 4 for a discussion of the impact of adopting SFAS No. 143 on the Company’s accounting for decommissioning.

The balance of investments held in external trusts for decommissioning, as well as the accumulated provision for decommissioning, at December 31, 2002 and 2001, was $838 million and $858 million, respectively.

The Company collected $36 million from ratepayers in each of the years ended 2002, 2001 and 2000, respectively and expensed like amounts as a component of depreciation. The Company recognized net realized gains and interest income of $11 million, $32 million and $20 million for 2002, 2001, and 2000. The Company recognized net unrealized losses of $67 million, $61 million and $23 million, for 2002, 2001, 2000, respectively. The Company recognized offsetting increases or decreases to its provision for decommissioning in amounts equal to net realized and unrealized gains or losses for each period.

Expected Costs for Decommissioning

The total estimated current cost to decommission the Company’s four nuclear units is $1.5 billion based on a site-specific study that was completed in 2002. A new cost estimate will be completed in 2006. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. Under current operating licenses, decommissioning would begin in 2012 as detailed in the table below. However, the Company filed a request with the NRC for a 20-year life extension for the Surry and North Anna units in 2001. The Company expects to decommission the units during the period 2032 to 2045.

	Surry				North Anna				Total All Units
	Unit 1		Unit 2		Unit 1		Unit 2
	(millions)
NRC license expiration year		2012		2013		2018		2020
Current cost estimate (2002 dollars)	$	375	$	368	$	391	$	363	$	1,497
Funds in external trusts at December 31, 2002		235		230		192		181		838
2002 contributions to external trusts		11		11		7		7		36

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of nuclear facilities. The Company’s 2002 NRC minimum financial assurance amount, aggregated for the four nuclear units, was $1.1 billion and has been satisfied by a combination of surety bonds and the funds being collected and deposited in the external trusts.

Beginning in March 2003, the Company expects to replace the surety bonds currently being utilized with a guarantee issued by Dominion.

Insurance

The Price-Anderson Act limits the public liability of a nuclear power plant owner to $9.5 billion for a single nuclear incident. The Price Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. The Company has purchased $200 million of coverage from commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, the Company could be assessed up to $88 million for each of its four licensed reactors, not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The Price-Anderson Act was first enacted in 1957 and has been renewed three times—in 1967, 1975 and 1988. Price-Anderson expired in August 2002, and Congress is currently holding hearings to reauthorize the legislation. The expiration of Price-Anderson has no impact on existing nuclear license holders.

The Company’s current level of property insurance coverage ($2.55 billion for North Anna and $2.55 billion for Surry) exceeds the NRC’s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The Company’s nuclear property insurance is provided by the Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $43 million. Based on the severity of the incident, the board of directors of the Company’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. The Company has the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

The Company also purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, the Company is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $19 million.

The North Anna Power Station is jointly owned as discussed in Note 13. The co-owner is responsible for its share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

Note 9. Derivative Instruments, Hedge Accounting and Energy Trading Activities

Adoption of SFAS No. 133

The Company adopted SFAS No. 133 on January 1, 2001 and recorded an after-tax charge to accumulated other comprehensive income (AOCI) of $14 million, net of taxes of $9 million.

Risk Management Policy

The Company uses derivative instruments to manage the commodity, currency exchange and financial market risks of its business operations. The Company manages the price risk associated with purchases of natural gas and oil by utilizing derivative instruments including futures and swaps. The Company manages its foreign exchange risk associated with anticipated future purchases denominated in foreign currencies by utilizing currency forward contracts. The Company manages its interest rate risk exposure, in part, by entering into interest rate swap transactions.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of energy commodities, primarily natural gas and electricity. The Company uses established policies and procedures to manage the risks associated with these price fluctuations and uses various derivative instruments, such as futures, swaps and options, to reduce risk by creating offsetting market positions. The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained regarding the use of derivative instruments. In addition, Dominion has established an independent function to monitor compliance with the risk management policies of all subsidiaries.

The Company designates a substantial portion of derivative instruments held for purposes other than trading as fair value or cash flow hedges for accounting purposes. A significant portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with purchases of natural gas, oil and other commodities. The Company also uses cash flow hedge strategies to hedge the variability in foreign exchange rates and variable interest rates on long-term debt using derivative instruments discussed in the preceding paragraphs. The Company also has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt. Certain of the Company’s non-trading derivative instruments are not designated as hedges for accounting purposes. However, management believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and interest rates.

Accounting Policy

Under SFAS No. 133, derivatives are recognized on the Consolidated Balance Sheets at fair value, unless an exception is available under the standard. Certain qualifying derivative contracts have been designated as normal purchases or normal sales contracts. These contracts are not reported at fair value, as otherwise required by SFAS No. 133.

Commodity contracts representing unrealized gain positions are reported as derivative and energy trading assets; commodity contracts representing unrealized losses are reported as derivative and energy trading liabilities. In addition, purchased options and options sold are reported as derivative and energy trading assets and derivative and energy trading liabilities, respectively, at estimated market value until exercise or expiration.

For all derivatives designated as hedges, the Company formally documents the relationship between the hedging instrument and the hedged item, as well as the risk management objective and strategy for using the hedging instrument. The Company assesses whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value of the hedged item is recognized currently in earnings. The Company discontinues hedge accounting prospectively for derivatives that have ceased to be highly effective hedges.

For fair value hedge transactions in which the Company is hedging changes in the fair value of an asset, liability or firm commitment, changes in the fair value of the derivative will generally be offset in the Consolidated Statements of Income by changes in the hedged item’s fair value. For cash flow hedge transactions in which the Company is hedging the variability of cash flows related to a variable-priced asset, liability, commitment or forecasted transaction, changes in the fair value of the derivative are reported in AOCI.

Derivative gains and losses reported in AOCI are reclassified to earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portions of the change in fair value of derivatives and the change in fair value of derivatives not designated as hedges for accounting purposes are recognized in current period earnings. For foreign currency forward contracts designated as cash flow hedges, hedge effectiveness is measured based on changes in the fair value of the contract attributable to changes in the forward exchange rate. For options designated either as fair value or cash flow hedges, changes in time value are excluded from the measurement of hedge effectiveness and are therefore recorded in earnings.

Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in the Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. Changes in the fair value of derivatives not designated as hedges and the portion of hedging derivatives excluded from the measurement of effectiveness are included in other operations and maintenance expense in the Consolidated Statements of Income. Cash flows resulting from the settlement of derivatives used as hedging instruments are included in net cash flows from operating activities.

Derivative and Hedge Accounting Results

The Company recognized no hedge ineffectiveness during 2002. The Company experienced less than $1 million of ineffectiveness related to its hedges during 2001. The following table presents selected information related to cash flow hedges included in AOCI in the Consolidated Balance Sheet at December 31, 2002:

	Accumulated Other Comprehensive Income (Loss) After Tax			Portion Expected to be Reclassified to Earnings during the Next 12 Months			Maximum Term
	(dollar amount in millions)
Interest Rate	$	(3	)	$	(2	)	49 months
Foreign Currency		11			3		59 months
Total	$	8		$	1

The actual amounts that will be reclassified to earnings in 2003 will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates. The effect of amounts being 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.

Energy Trading Activities

The Company’s non-derivative energy contracts initiated before October 25, 2002 and derivative instruments held for energy trading purposes are reported at fair value, with corresponding changes in value recognized immediately in earnings. See Note 4 for discussion of recent changes impacting the fair value accounting for energy trading contracts. Net gains and losses associated with the Company’s commodity trading purchases and sales are presented net as other revenue. See Note 5. Cash flows resulting from the settlement of energy trading contracts are included in net cash flows from operating activities. The composition of operating revenue from commodity trading activities for the years 2002, 2001 and 2000 follows:

	Gains		Losses			Total
	(millions)
2002
Contract settlements	$	10,616	$	(10,640	)	$	(24	)
Unrealized gains and losses		1,496		(1,474	)		22
Operating revenue	$	12,112	$	(12,114	)	$	(2	)
2001
Contract settlements	$	5,520	$	(5,508	)	$	12
Unrealized gains and losses		1,502		(1,361	)		141
Operating revenue	$	7,022	$	(6,869	)	$	153
2000
Contract settlements	$	2,773	$	(2,692	)	$	81
Unrealized gains and losses		1,236		(1,211	)		25
Operating revenue	$	4,009	$	(3,903	)	$	106

Note 10. Regulatory Assets and Liabilities

The Company accounts for its regulated operations in accordance with SFAS No. 71. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process.

In 1999, Virginia enacted the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) that established a detailed plan to restructure Virginia’s electric utility industry. Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia jurisdictional operations is no longer subject to cost-based regulation, effective January 1, 2002. The legislation’s deregulation of generation was an event that required the discontinuance of SFAS No. 71 for the Company’s generation operations in 1999.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

The Company’s regulatory assets and liabilities included the following:

	At December 31,
	2002		2001
	(millions)
Income taxes recoverable through future rates	$	47	$	49
Cost of decommissioning DOE uranium enrichment facilities		34		42
Deferred fuel		133		119
Other		25		21
Total	$	239	$	231

The incurred costs underlying regulatory assets may represent past expenditures by the Company’s rate regulated operations or may represent the recognition of liabilities that ultimately will be settled at some time in the future. At December 31, 2002, approximately $24 million of the Company’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of deferred fuel costs for certain jurisdictions that are recovered within two years.

Income taxes recoverable through future rates resulted from the recognition of additional deferred income taxes, not previously recorded because of past ratemaking practices.

The cost of decommissioning the Department of Energy’s (DOE) uranium enrichment facilities represents the Company’s required contributions to a fund for decommissioning and decontaminating the DOE’s uranium enrichment facilities. The Company began making contributions in 1992 which are expected to continue over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates.

Deferred fuel accounting provides that the difference between 1) reasonably incurred actual cost of fuels used in electric generation and energy purchases and 2) the recovery for such costs included in current rates is deferred and matched against future revenue.

Note 11. Goodwill and Intangible Assets

In 2001, FASB issued SFAS No. 142,Goodwill and Other Intangible Assets which prohibits the amortization of goodwill and intangible assets with indefinite useful lives. SFAS No. 142 also requires that these assets be reviewed for impairment at least annually. Intangible assets with finite lives will continue to be amortized over their estimated useful lives and will be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable.

The Company adopted SFAS No. 142 on January 1, 2002. The Company does not have any goodwill; thus the provisions of SFAS No. 142 requiring the discontinuance of goodwill amortization did not have an impact on the Company’s results of operations in 2002.

All of the Company’s intangible assets are subject to amortization. Amortization expense for intangible assets was $24 million, $19 million and $16 million for 2002, 2001 and 2000, respectively. There were no material acquisitions of intangible assets during 2002. The components of intangible assets at December 31, 2002 were as follows:

	Gross Carrying Amount		Accumulated Amortization
	(millions)
Software and software licenses	$	208	$	89
Other		16		6
Total	$	224	$	95

Amortization expense for intangible assets is estimated to be $28 million for 2003, $26 million for 2004, $21 million for 2005, $19 million for 2006 and $14 million for 2007.

Note 12. Property, Plant and Equipment

Property, plant and equipment, including nuclear fuel, consists of the following:

	At December 31,
	2002		2001
	(millions)
Generation	$	8,497	$	8,415
Transmission		1,598		1,565
Distribution		5,522		5,288
Nuclear fuel		740		757
General		647		655
		17,004		16,680
Other—including plant under construction		793		552
Total	$	17,797	$	17,232

Note 13. Jointly Owned Plants

The Company’s proportionate share of jointly owned plants at December 31, 2002 follows:

	Bath County Pumped Storage Station			North Anna Power Station			Clover Power Station
	(millions, except percentages)
Ownership interest		60.0	%		88.4	%		50.0	%
Plant in service	$	1,028		$	1,861		$	534
Accumulated depreciation		342			1,176			93
Nuclear fuel		—			341			—
Accumulated amortization of nuclear fuel		—			309			—
Plant under construction		4			82			12

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. The Company reports its share of operating costs in the appropriate operating expense (fuel, operations and maintenance, depreciation, taxes, etc.) in the Consolidated Statements of Income.

Note 14. Short-term Debt and Credit Agreements

Joint Credit Facilities

In May 2002, Dominion, CNG, and the Company entered into two joint credit facilities that allow aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2003 and a $750 million three-year revolving credit facility that terminates in May 2005. The 364-day facility includes an option to extend any borrowings for an additional period of one year to May 2004. These joint credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company, and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. The Company expects to renew the 364-day revolving credit facility prior to its maturity in May 2003.

At December 31, 2002, total outstanding commercial paper supported by the joint credit facilities was $1.2 billion, of which the Company’s borrowings were $443 million, with a weighted average interest rate of 1.67 percent. At December 31, 2001, total outstanding commercial paper supported by previous credit agreements was $1.9 billion, of which the Company’s borrowings were $436 million, with a weighted average interest rate of 1.96 percent.

At December 31, 2002, total outstanding letters of credit supported by the three-year facility were $106 million, which were issued for Dominion and CNG on behalf of subsidiaries. There were no outstanding letters of credit at December 31, 2001.

Note 15. Long-term Debt

Long- term debt consists of the following:

	2002 Weighted Average Coupon(2)		At December 31,
			2002			2001
			(millions)
First and Refunding Mortgage Bonds:
6.0% to 8.625%, due 2002 to 2025(1)	7.56	%	$	1,666		$	2,121
Senior and Medium-Term Notes:
Variable rates, due 2002 to 2003(2)	2.37	%		120			340
5.375% to 9.6%, due 2002 to 2038	5.95	%		1,785			1,195
Tax-Exempt Financings(3):
Variable rates, due 2008 to 2027(2)	1.60	%		197			197
4.95% to 5.875%, due 2007 to 2017(4)	5.49	%		292			292
3.15% to 5.45%, due 2022 to 2031	3.67	%		110			110
				4,170			4,255
Fair value hedge valuation(5)				7			4
Amount due within one year				(360	)		(535	)
Unamortized discount and premium, net				(23	)		(20	)
Total long-term debt			$	3,794		$	3,704

⁽¹⁾ Substantially all of the Company’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds (Mortgage Bonds). In 2002, the Company redeemed its $200 million, 6.75 percent 1997-A Mortgage Bonds due February 1, 2007. The Company completed the redemption with part of the proceeds from the issuance of $650 million, 5.375 percent Senior Notes due February 1, 2007 (Senior Notes). The redemption included a direct exchange of Senior Notes for $117 million of Mortgage Bonds. The Company used the remaining proceeds of Senior Notes to redeem the remaining $83 million of Mortgage Bonds and for general corporate purposes, including the repayment of other debt.

⁽²⁾ Represents weighted-average coupon rates for debt outstanding as of December 31, 2002.

⁽³⁾ Certain pollution control equipment at the Company’s generating facilities has been pledged or conveyed to secure these financings.

⁽⁴⁾ In 2002, the Company converted $292 million of its variable rate pollution control bonds to fixed rates, ranging from 4.95 percent to 5.875 percent. Other terms of the bonds remain the same.

⁽⁵⁾ Represents changes in fair value of certain fixed rate long-term debt associated with fair value hedging relationships, as described in Note 22.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

The scheduled principal payments of long-term debt at December 31, 2002 were as follows (in millions):

2003	2004	2005	2006	2007	Thereafter	Total
$360	$325	$ —	$600	$880	$2,005	$4,170

The Company’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2002, there were no events of default under the Company’s covenants.

Note 16. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust

In 2002, Virginia Power Capital Trust II (Trust), a trust subsidiary of the Company, sold 16 million 7.375 percent trust preferred securities for $400 million, representing preferred beneficial interests and 97 percent beneficial ownership in the assets held by the Trust. In exchange for the $400 million realized from the sale of the trust preferred securities and $12 million of common securities that represent the remaining 3 percent beneficial ownership interest in the assets held by the Trust, the Company issued $412 million of its 2002 7.375 percent Junior Subordinated Notes (Junior Subordinated Notes) due July 30, 2042. The Junior Subordinated Notes constitute 100 percent of the Trust’s assets. The Trust must redeem the trust preferred securities when the Junior Subordinated Notes are repaid or if redeemed prior to maturity.

In 2002, the Company redeemed $139 million of junior subordinated notes held by Virginia Power Capital Trust I. The Trust redeemed all outstanding trust preferred securities for $135 million and redeemed $4 million of its common securities held by the Company.

Distribution payments on the trust preferred securities are guaranteed by the Company, but only to the extent that the trusts have funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferred securities is solely dependent upon the Company’s payment of amounts when they are due on the junior subordinated notes. If the payment on the junior subordinated notes is deferred, the Company may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also during the deferral period, it may not make any payments or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

Note 17. Preferred Stock

The Company is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding- up of the Company, each share is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.

Holders of the outstanding preferred stock of the Company are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, or upon default in dividends, or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock.)

In 2002, the Company purchased and redeemed, at par, all shares of its variable rate preferred stock October 1988 Series, June 1989 Series, September 1992A Series and September 1992B Series for $250 million, at the redemption price of $100 per share. The dividend rates for these series were variable and set every 49 days via an auction process. The combined weighted average rates for all series outstanding during 2002, 2001 and 2000, including fees for broker/dealer agreements, were 4.00 percent, 4.32 percent and 5.71 percent, respectively.

In 2002, the Company issued 1,250 units consisting of 1,000 shares per unit of cumulative preferred stock, for $125 million. The preferred stock has a dividend rate of 5.50 percent until the end of the initial dividend period on December 20, 2007. The dividend rate for subsequent periods will be determined according to periodic auctions. The preferred stock has a liquidation preference of $100 per share plus accumulated and unpaid dividends. Except during the initial dividend period, and any non-call period, this preferred stock will be redeemable, in whole or in part, on any dividend payment date at the option of the Company. The Company may also redeem this preferred stock, in whole but not in part, if certain changes are made to

federal tax law which reduce the dividends received percentage.

Presented below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2002:

Dividend	Issued and Outstanding Shares(1)	Entitled Per Share Upon Liquidation
$5.00	107	$	112.50
4.04	13		102.27
4.20	15		102.50
4.12	32		103.73
4.80	73		101.00
7.05	500		105.00	(2)
6.98	600		105.00	(3)
Flex MMP 12/02, Series A	1,250		100.00
Total	2,590

⁽¹⁾ Shares are presented in thousands.

⁽²⁾ Through 7/31/03; $103.53 commencing 8/1/03; amounts decline in steps thereafter to $100.00.

⁽³⁾ Through 8/31/03; $103.49 commencing 9/1/03; amounts decline in steps thereafter to $100.00.

Note 18. Common Stock

In exchange for a $150 million reduction in amounts payable to Dominion, the Company issued common stock to Dominion in 2002.

Note 19. Accumulated Other Comprehensive Income

As of December 31, 2002 and 2001, accumulated other comprehensive income was $8 million and $(4) million, respectively, representing net unrealized gains (losses) on derivative instruments.

Note 20. Employee Benefit Plans

The Company participates in a defined benefit pension plan sponsored by Dominion. Benefits payable under the plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, the Company is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The Company’s net periodic pension cost was $7 million, $7 million and $50 million in 2002, 2001 and 2000, respectively. The 2000 net periodic pension cost included $38 million for the effect of the ERP on the Company’s pension plan. See Note 6 for more information on the ERP. The Company’s contributions to the pension plan were $37 million, $7 million and $12 million in 2002, 2001 and 2000, respectively.

The Company participates in plans which provide certain retiree health care and life insurance benefits to multiple Dominion subsidiaries. Annual premiums are based on several factors such as age, retirement date and years of service. The Company’s net periodic benefit cost was $34 million, $35 million and $42 million in 2002, 2001 and 2000, respectively.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, the Company funds postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. The Company’s contributions to health care and life insurance plans were $17 million, $10 million, and $3 million in 2002, 2001 and 2000, respectively.

The Company also participates in employee savings plans which cover substantially all employees. Employer matching contributions totaled $10 million, $10 million and $12 million in 2002, 2001 and 2000, respectively.

See Note 3 for the discussion of the accounting change for pension costs in 2000.

Note 21. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have a material adverse effect on the Company’s financial position, liquidity or results of operations.

Capital Expenditures

The Company has made substantial commitments in connection with its capital expenditures program. Those expenditures are estimated to total approximately $900 million, $665 million and $625 million for 2003, 2004 and 2005 respectively. Purchases of nuclear fuel are included inFuel Purchase Commitmentsbelow. The Company expects that these expenditures will be met through a combination of sales of securities and short- term borrowings to the extent not funded by cash flow from operations.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

Power Purchase Contracts

The Company has entered into contracts for long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. As of December 31, 2002, the Company has 42 non-utility purchase contracts with a combined dependable summer capacity of 3,758 megawatts.

The table below reflects the Company’s minimum commitments as of December 31, 2002 under these contracts.

	Commitment
Year	Capacity		Other
	(millions)
2003	$	643	$	44
2004		635		29
2005		629		22
2006		614		18
2007		589		11
Later years		5,259		113
Total	$	8,369	$	237
Present value of the total	$	4,386	$	140

Capacity purchases under these contracts totaled $691 million, $680 million and $740 million for 2002, 2001 and 2000, respectively.

In 2001, the Company completed the purchase of three generating facilities and the termination of seven contracts which provided electricity to the Company under long-term power purchase agreements with non-utility generators. The Company recorded an after-tax charge of $136 million in connection with the purchase and termination of the long-term power purchase agreements. Cash payments related to the purchase of the three generating facilities totaled $207 million. The allocation of the purchase price was assigned to the assets and liabilities acquired based upon estimated fair values as of the date of acquisition. Substantially all of the value was attributed to the power purchase agreements which were terminated and resulted in a charge included in operations and maintenance expense.

Fuel Purchase Commitments

The Company enters into long-term purchase commitments for fuel used in electric generation. Estimated fuel purchase commitments for the next five years are as follows: 2003—$439 million; 2004—$237 million; 2005—$174 million; 2006—$142 million; and 2007—$70 million. The Company recovers the costs of these purchases through regulated rates.

Lease Commitments

The Company leases various facilities, vehicles and equipment under both operating and capital leases. Future minimum lease payments under the Company’s operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2002 are as follows: 2003—$39 million; 2004—$28 million; 2005—$20 million; 2006—$12 million; 2007—$10 million; and years after 2007—$34 million.

Under the terms of lease agreements, the Company has guaranteed that residual values of covered vehicles will be at least $44 million at the time such agreements expire or are terminated.

Rental expense included in operations and maintenance expense totaled $30 million, $25 million, and $24 million for 2002, 2001, and 2000, respectively.

In addition, the Company has entered into agreements with another Dominion subsidiary in order to develop, construct, finance and lease a new power generation facility at the Company’s Possum Point station in Prince William County, Virginia. The project is scheduled for completion in 2003 at an estimated cost of $370 million. Upon completion, the Company will operate the new generating facility under an operating lease with estimated annual lease payments of $20 million.

Energy Trading

Subsidiaries of the Company enter into purchases and sales of commodity-based contracts in the energy-related markets, including natural gas, electricity, coal and oil. These agreements may cover current and future periods. The volume of these transactions varies from day to day, based on market conditions. See Note 9 for a discussion of the Company’s energy trading activities and risk management policies.

Environmental Matters

The Company is subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health

and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Historically, the Company recovered such costs arising from regulated electric operations through utility rates. However, to the extent environmental costs are incurred in connection with operations regulated by the Virginia State Corporation Commission, during the period ending June 30, 2007, in excess of the level currently included in Virginia jurisdictional rates, the Company’s results of operations will decrease. After that date, the Company may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations.

Superfund Sites

From time to time, the Company may be identified as a potentially responsible party to a Superfund site. The Environmental Protection Agency (EPA) (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.

In 1987, the EPA identified the Company and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. Current cost studies estimate total remediation costs for the sites to range from $98 million to $152 million. The Company’s proportionate share of the total cost is expected to be in the range of $2 million to $3 million, based on allocation formulas and the volume of waste shipped to the sites. The majority of remediation activities at the Kentucky site are complete and remediation design is ongoing for the Pennsylvania site. The Company has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, the Company has determined that it is probable that the PRPs will fully pay their share of the costs. The Company generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2002, any pending or possible claims were not recognized as an asset or offset against such obligations.

Other EPA Matters

During 2000, the Company received a Notice of Violation from the EPA, alleging that the Company failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. In December 2002, the Attorney General of Connecticut filed a motion to intervene as a plaintiff in the action filed by the New York State Attorney General. This action has been stayed. Management believes that the Company has obtained the necessary permits for its generating facilities. The Company has reached an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for environmental projects in Virginia, West Virginia, Connecticut, New Jersey and New York and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company’s coal-fired generating stations in Virginia and West Virginia. The Company had already committed to a substantial portion of the $1.2 billion expenditures for sulfur dioxide and nitrogen oxide emissions controls. The negotiations over the terms of a binding settlement have expanded beyond the basic agreement in principle and are ongoing. As of December 31, 2002, the Company has recorded, on a discounted basis, $18 million for the civil penalty and environmental projects.

In 2002, the EPA issued a Section 114 request for information about whether projects undertaken at the Company’s Chesterfield, Chesapeake, Yorktown, Possum Point and Bremo Bluff power stations were properly permitted under the Clean Air Act’s New Source Review requirements, to which the Company responded in a timely manner.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

Surety Bonds

At December 31, 2002, the Company had issued $66 million of surety bonds, of which $57 million is associated with the financial assurance requirements imposed by the NRC with respect to the decommissioning of the Company’s nuclear units. See Note 8 for more information on nuclear operations. Under the terms of the surety bonds, the Company is obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2002, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent nuclear fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and in the Company’s contract with the DOE. The Company will continue to safely manage its spent fuel until accepted by the DOE.

Retrospective Premium Assessments

Under several of the Company’s nuclear insurance policies, the Company is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to these insurance companies. For additional information, see Note 8.

Stranded Costs

Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia jurisdictional operations is no longer subject to cost-based rate regulation, effective January 1, 2002. The Company’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007, unless terminated sooner or otherwise modified consistent with the Virginia Restructuring Act. Under the Act, the Company may request a termination of the capped rates at any time after January 1, 2004, and the Virginia Commission may grant the Company’s request to terminate the capped rates, if it finds that a competitive generation services market exists in the Company’s service area. The Company believes capped electric retail rates and, where applicable, wires charges provided under the Virginia Restructuring Act provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

Even in the capped rate environment, the Company remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. At December 31, 2002, the Company’s exposure to potentially stranded costs included: long-term power purchase contracts that could ultimately be determined to be above market (seePower Purchase Contracts above); generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. See Notes 8 and 20.

Note 22. Fair Value of Financial Instruments

Substantially all of the Company’s financial instruments are recorded at fair value, with the exception of the instruments described below. Fair value amounts have been determined using available market information and valuation methodologies considered appropriate by management.

The Company reports the following financial instruments based on historical cost rather than fair value. The financial instruments’ carrying amounts and

fair values as of December 31, 2002 and 2001 were as follows:

	2002				2001
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(millions)
Long-term debt(1)	$	4,154	$	4,408	$	4,239	$	4,313
Preferred securities of subsidiary trust(2)		400		414		135		137

⁽¹⁾ Fair value is estimated using market prices, where available; otherwise, interest rates currently available for issuance of debt with similar terms and remaining maturities are used. The carrying amount of debt issues with short-term maturities and variable rates repriced at current market rates is a reasonable estimate of their fair value.

⁽²⁾ Fair value is based on market quotations.

Note 23. Concentration of Credit Risk

Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. The Company sells electricity and provides distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers as well as rural electric cooperatives and municipalities. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and electricity in its energy trading, hedging and arbitrage activities. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Management does not believe that this geographic concentration contributes significantly to the Company’s overall exposure to credit risk. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

Dominion and its subsidiaries, including the Company, maintain credit policies with respect to its counterparties that management believes minimize overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements, and in the case of energy trading, hedging and arbitrage activities, the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. On behalf of the Company, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. The Company maintains a provision for credit losses based upon factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on Dominion’s credit policies and its December 31, 2002 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative and energy trading contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. In the calculation of net credit exposure, the Company’s gross exposure is reduced by collateral made available by counterparties, including letters of credit and cash received by the Company and held as margin deposits. Presented below is a summary of the Company’s gross and net credit exposure as of December 31, 2002. The amounts presented exclude accounts receivable for regulated electric retail distribution and regulated electric transmission services, amounts payable to affiliated companies and the Company’s provision for credit losses.

	At December 31, 2002
	Credit Exposure Before Credit Collateral		Credit Collateral		Net Credit Exposure
	(millions)
Investment grade(1)	$	304	$	15	$	289
Non-investment grade(2)		44		25		19
No external ratings:
Internal rated—investment grade(3)		198		—		198
Internal rated—non-investment grade(4)		24		—		24
Total	$	570	$	40	$	530

(1) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 19 percent of the total gross credit exposure.

(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures, combined, for this category represented approximately 8 percent of the total gross credit exposure.

(3) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s but are considered investment grade based on the Company’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 29 percent of the total gross credit exposure.

(4) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s and are considered non-investment grade based on the Company’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 2 percent of the total gross credit exposure.

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

Note 24. Related Party Transactions

The Company, through an unregulated subsidiary, exchanges certain quantities of natural gas and other commodities at market prices with other Dominion affiliates in the ordinary course of business. The affiliated commodity transactions are presented below:

	Year Ended December 31,
	2002		2001		2000
	(millions)
Purchases of natural gas, gas transportation and storage services from affiliates	$	162	$	133	$	65
Sales of natural gas to affiliates		279		229		33

Through the same unregulated subsidiary, the Company is involved in facilitating Dominion’s enterprise risk management strategy. In connection with this strategy, the Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by Dominion affiliates to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion’s enterprise risk management strategy, the Company generally manages such risk exposures by entering into offsetting derivative instruments with non-affiliates. The Company reports both affiliated and non-affiliated derivative instruments at fair value, with related changes included in earnings. The Company’s Consolidated Balance Sheets include derivative and energy trading assets of $60 million and $159 million with Dominion affiliates at December 31, 2002 and 2001, respectively, and derivative and energy trading liabilities of $81 million and $77 million with Dominion affiliates at December 31, 2002 and 2001, respectively.

The Company’s income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

	Year Ended December 31,
	2002	2001	2000
	(millions)
Net realized (gains) losses on commodity derivative contracts	$(45)	$(2)	$21

Effective February 1, 2000, Dominion created a subsidiary service company, Dominion Services, which provides certain services to the Company. In connection with the formation of Dominion Services, certain of the Company’s employees became employees of Dominion Services. In 2001, the Company transferred certain assets and liabilities to Dominion Services with a net book value of approximately $27 million; no gain or loss was recorded on the transfer. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of these services provided to the Company and the amount billed for services provided by the Company follow:

	Year Ended December 31,
	2002		2001		2000
	(millions)
Services provided by Dominion Services	$	267	$	313	$	202
Services provided by the Company to other affiliates		29		23		15

The Company leases its principal office building from Dominion under an agreement approved by the Virginia Commission that expires in 2006. This agreement is accounted for as a capital lease. The capitalized cost of the property under that lease, net of accumulated amortization, was approximately $12 million and $14 million at December 31, 2002 and 2001, respectively. The rental payments for this lease were $3 million in each of the years ended December 31, 2002, 2001 and 2000.

During 2002, Dominion advanced funds to certain unregulated subsidiaries of the Company pursuant to a short-term demand note (Demand Note). At December 31, 2002, the net outstanding borrowings under the Demand Note totaled $100 million. Interest charges incurred by the Company in 2002 were not material.

For information about the Company’s agreement with another Dominion subsidiary, Dominion Equipment II, Inc. to develop, construct, finance and lease a new power generation facility at its Possum Point station in Prince William County, Virginia, see Note 21.

In July 2000, the Company transferred all of its issued and outstanding common stock in VPS Communications, Inc. (VPS) to Dominion. Dominion renamed VPS to Dominion Telecom, Inc. (DTI). In 2001, Dominion contributed DTI to Dominion Fiber Ventures LLC (DFV), a telecommunications joint venture. DFV is the sole owner of DTI. The Company leases fiber optic capacity to DTI at rates subject to the approval of the Virginia Commission. Payments received by the Company in connection with Dominion Telecom’s lease of fiber optic equipment, and related fiber optic support and maintenance

services, during 2002, 2001 and the period August 1, 2000 through December 31, 2000 were not material.

In 2001, an unregulated division of the Company transferred certain energy management services contracts and related leases to another Dominion subsidiary for $14 million, representing the Company’s net book value recorded on its books for these contracts.

In exchange for a $150 million reduction in amounts payable to Dominion, the Company issued common stock to Dominion. See Note 18.

The Company’s accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions.

An unregulated subsidiary of the Company, at its sole discretion, has provided approximately $31 million of cash collateral to third parties on behalf of several of its natural gas supply customers. For this and other financial support services, the unregulated subsidiary receives fees and has a security interest in the customers’ assets. The arrangements terminate at various dates beginning in 2005 through 2007, subject to periodic renewal thereafter unless terminated by either party.

See Notes 2, 7 and 20 for discussion of the inclusion of the Company in Dominion’s consolidated federal income tax return and the Company’s participation in certain Dominion employee incentive and benefit plans.

Note 25. Dividend Restrictions

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company, like Dominion, from its subsidiaries, including the Company. The restrictions include a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts.

The Virginia Commission may prohibit any public service company from declaring or paying a dividend to an affiliate, if found not to be in the public interest. As of December 31, 2002, the Virginia Commission had not restricted the payment of dividends by the Company.

Certain agreements associated with the Company’s joint credit facilities with Dominion and CNG contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Company’s ability to pay dividends to Dominion or to receive dividends from its subsidiaries at December 31, 2002.

See Note 16 for a description of potential restrictions on dividend payments by the Company in connection with the deferral of distribution payments on trust preferred securities.

Note 26. Operating Segments

The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on two operating segments:

nEnergy manages the Company’s portfolio of generating facilities and power purchase contracts and its energy trading and marketing, hedging and arbitrage activities. It also manages the Company’s electric transmission system.

nDelivery manages the Company’s electric distribution system as well as the metering services and customer service. The segment continues to be subject to the requirements of SFAS No. 71.

The majority of the Company’s revenue is provided through bundled rate tariffs. Generally, such revenues are allocated between the two segments for management reporting based on prior cost-of-service studies.

In addition, the Company also reports Corporate and Other as a segment. Corporate and Other includes certain expenses which are not allocated to the Energy or Delivery segments, including:

1) corporate operations;

2) transactions or amounts not allocated to the operating segments for internal reporting purposes:

— 2001 termination of power purchase contracts (see Note 21);

— 2002, 2001 and 2000 restructuring costs (see Note 6); and

— 2000 cumulative effect of a change in accounting principle (see Note 3).

Virginia Electric and Power Company

Notes to Consolidated Financial Statements—(Continued)

The Company’s management evaluates performance based on a measure of profit and loss that represents each segment’s contribution to the Company’s net income. Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.

The following table presents segment information pertaining to the Company’s operations:

Description	Energy		Delivery		Corporate and Other			Eliminations			Consolidated Total
	(millions)
Year ended December 31, 2002
Total operating revenue	$	3,918	$	1,042	$	13		$	(1	)	$	4,972
Depreciation and amortization		237		224		34			—			495
Interest and related charges		176		121		—			(3	)		294
Income tax expense		291		132		2			—			425
Net income		516		253		4			—			773
Total assets		10,996		4,167		—			—			15,163
Capital expenditures		462		286		—			—			748
Year ended December 31, 2001
Total operating revenue		3,940		994		12			(2	)		4,944
Depreciation and amortization		264		222		32			—			518
Interest and related charges		178		123		3			(4	)		300
Income tax expense		280		108		(102	)		—			286
Net income		432		178		(164	)		—			446
Total assets		9,734		4,050		—			—			13,784
Capital expenditures		377		291		—			—			668
Year ended December 31, 2000
Total operating revenue		3,796		991		6			(2	)		4,791
Depreciation and amortization		310		210		38			—			558
Interest and related charges		177		116		7			(4	)		296
Income tax expense		210		101		(32	)		—			279
Net income		427		188		(36	)		—			579
Capital expenditures		359		293		—			—			652

Note 27. Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2002 and 2001 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
	(millions)
2002
Operating revenue	$	1,151	$	1,221	$	1,474	$	1,126	$	4,972
Income from operations		312		341		554		253		1,460
Net income		153		175		316		129		773
Balance available for common stock		149		170		311		127		757
2001
Operating revenue	$	1,222	$	1,177	$	1,444	$	1,101	$	4,944
Income from operations		109		297		495		98		999
Net income		25		134		266		21		446
Balance available for common stock		18		128		260		17		423

Independent Auditors’ Report

To Board of Directors of

Virginia Electric and Power Company

Richmond, Virginia

We have audited the consolidated financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and have issued our report thereon dated January 21, 2003 (May 7, 2003 as to the second paragraph of Note 1 and Note 26), which report expresses an unqualified opinion and includes an explanatory paragraph as to changes in accounting principle for derivative instruments and hedging activities in 2001 and the method of accounting used to develop the market-related value of pension plan assets in 2000; such consolidated financial statements and report are included elsewhere in this Form 8-K. Our audits also included the consolidated financial statement schedule of the Company, listed in Item 7(c). Exhibit 99.4. This consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/S/ DELOITTE & TOUCHE LLP

Richmond, Virginia

January 21, 2003

(May 7, 2003 as to the second paragraph of Note 1 and Note 26)

30

Virginia Electric and Power Company

Schedule II—Valuation and Qualifying Accounts

Column A		Column B	Column C			Column D	Column E
			Additions
Description		Balance at Beginning of Period	Charged to Expense		Charged to Other Accounts	Deductions	Balance at End of Period
		(Millions)
Valuation and qualifying accounts which are deducted in the balance sheet from the assets to which they apply:
Allowance for doubtful accounts	2000	12	18		—	14(a)	16
	2001	16	18		—	11(a)	23
	2002	23	15		—	26(a)	12
Valuation allowance for commodity contracts	2000	22	(3	)(b)	—	—	19
	2001	19	7	(b)	—	—	26
	2002	26	(2	)(b)	—	—	24
Reserves:
Liability for pre-2001 workforce reductions	2000	4	—		—	4(c)	—
	2001	—	—		—	—	—
	2002	—	—		—	—	—
Liabilities for restructuring costs:
2000 Plan
Severance and related costs	2000	—	14		—	8(c)	6
	2001	6	(1	)(b)	—	5(c)	—
	2002	—	—		—	—	—
2001 Plan
Severance and related costs	2001	—	16		—	—	16
	2002	16	(7	)(b)	—	5(c)	4

^(a) Represents net amounts charged-off as uncollectible.

^(b) Represents adjustments reflecting changes in estimates.

^(c) Represents payments for workforce reductions and/or restructuring liabilities.

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