Exhibit 13

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2001		2000		1999
	(millions, except per share amounts)
Operating Revenue
Regulated sales
Electric	$	4,619	$	4,492	$	4,230
Gas		1,409		1,374		—
Nonregulated sales
Electric		701		318		346
Gas		1,116		671		—
Gas transportation and storage		702		486		—
Gas and oil production		1,118		857		251
Other		893		1,048		693
Total		10,558		9,246		5,520
Operating Expenses
Electric fuel and energy purchases, net		1,369		1,106		996
Purchased electric capacity		680		741		809
Purchased gas, net		1,822		1,453		—
Liquids, pipeline capacity and other purchases		219		299		—
Restructuring and other acquisition-related costs		105		460		—
Other operations and maintenance		2,938		2,011		1,376
Depreciation, depletion and amortization		1,245		1,176		707
Other taxes		395		485		304
Total		8,773		7,731		4,192
Income from operations		1,785		1,515		1,328
Other income		126		109		75
Interest and related charges
Interest expense		899		958		507
Subsidiary preferred dividends and distributions of subsidiary trusts		98		66		67
Total		997		1,024		574
Income before income taxes and minority interests		914		600		829
Income taxes		370		183		259
Minority interests		—		2		18
Income before extraordinary item and cumulative effect of a change in accounting principle		544		415		552
Extraordinary item (net of income taxes of $197)		—		—		(255	)
Cumulative effect of a change in accounting principle (net of income taxes of $11)		—		21		—
Net Income	$	544	$	436	$	297
Earnings Per Common Share—Basic
Income before extraordinary item and cumulative effect of a change in accounting principle	$	2.17	$	1.76	$	2.88
Extraordinary item		—		—		(1.33	)
Cumulative effect of a change in accounting principle		—		0.09		—
Net income	$	2.17	$	1.85	$	1.55
Earnings Per Common Share—Diluted
Income before extraordinary item and cumulative effect of a change in accounting principle	$	2.15	$	1.76	$	2.81
Extraordinary item		—		—		(1.33	)
Cumulative effect of a change in accounting principle		—		0.09		—
Net income	$	2.15	$	1.85	$	1.48
Dividends paid per common share	$	2.58	$	2.58	$	2.58

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

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CONSOLIDATED BALANCE SHEETS

	At December 31,
	2001			2000
	(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	486		$	360
Customer accounts receivable		1,846			2,254
Less allowance for doubtful accounts		(76	)		(67	)
Other accounts receivable		164			160
Receivable from affiliates		13			122
Inventories:
Materials and supplies (average cost method)		245			150
Fossil fuel (average cost method)		150			102
Gas stored—current portion (LIFO)		182			75
Derivative and energy trading assets		1,311			1,058
Unrecovered gas costs		9			263
Investment securities—trading		244			275
Margin deposit assets		30			287
Prepayments		384			310
Other		366			451
Total		5,354			5,800
Investments
Loans receivable, net		106			676
Investments in affiliates		490			471
Available for sale securities		393			292
Nuclear decommissioning trust funds		1,697			851
Other		474			508
Total		3,160			2,798
Property, Plant and Equipment, Net
Property, plant and equipment		33,105			28,011
Less accumulated depreciation, depletion and amortization		(14,424	)		(13,162	)
Total		18,681			14,849
Deferred Charges and Other Assets
Goodwill, net		4,210			3,502
Regulatory assets, net		574			497
Prepaid pension cost		1,511			1,455
Derivative and energy trading assets		545			79
Other		334			317
Total		7,174			5,850
Total assets	$	34,369		$	29,297

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

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CONSOLIDATED BALANCE SHEETS—(CONTINUED)

	At December 31,
	2001		2000
	(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,354	$	336
Short-term debt		1,859		3,237
Accounts payable, trade		1,776		1,688
Accrued interest		240		195
Accrued payroll		180		178
Accrued taxes		144		316
Derivative and energy trading liabilities		1,086		1,021
Other		839		625
Total		7,478		7,596
Long-Term Debt
Long-term debt		11,797		10,101
Notes payable—affiliates		322		—
Total		12,119		10,101
Deferred Credits and Other Liabilities
Deferred income taxes		3,812		2,813
Deferred investment tax credits		128		147
Derivative and energy trading liabilities		322		100
Other		626		646
Total		4,888		3,706
Total liabilities		24,485		21,403
Commitments and Contingencies (see Note 27)
Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts*		1,132		385
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		384		509
Common Shareholders’ Equity
Common stock—no par, authorized—500.0 shares; outstanding—264.7 shares at 2001 and 245.8 shares at 2000		7,129		5,979
Other paid-in capital		28		16
Accumulated other comprehensive income (loss)		289		(23	)
Retained earnings		922		1,028
Total common shareholders’ equity		8,368		7,000
Total liabilities and shareholders’ equity	$	34,369	$	29,297

* As described in Note 22 to the Consolidated Financial Statements, debt securities issued by Dominion Resources, Inc. and certain subsidiaries constitute 100 percent of the trusts’ assets.

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

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

	Common Stock					Other Paid-In Capital		Accumulated Other Comprehensive Income (Loss)
	Shares		Amount								Retained Earnings			Total
	(millions)
Balance at January 1, 1999	195		$	3,933		$	16	$	(20	)	$	1,408		$	5,337
Stock repurchase and retirement	(9	)		(372	)										(372	)
Comprehensive income									5			297			302
Dividends and other adjustments												(493	)		(493	)
Balance at December 31, 1999	186			3,561			16		(15	)		1,212			4,774
Issuance of stock—CNG acquisition	87			3,527											3,527
Issuance of stock—public offering	6			354											354
Issuance of stock—employee, executive loan and direct stock purchase plans	4			195											195
Stock repurchase and retirement	(37	)		(1,641	)										(1,641	)
Premium income equity securities				(21	)										(21	)
Stock awards and stock options exercised (net of change in unearned compensation)				4											4
Comprehensive income									(8	)		436			428
Dividends and other adjustments												(620	)		(620	)
Balance at December 31, 2000	246			5,979			16		(23	)		1,028			7,000
Issuance of stock and stock options—Louis Dreyfus acquisition	14			894											894
Issuance of stock—employee and direct stock purchase plans	3			185											185
Stock awards and stock options exercised (net of change in unearned compensation)	2			79											79
Tax benefit from stock options exercised							12								12
Comprehensive income									312			544			856
Dividends and other adjustments				(8	)							(650	)		(658	)
Balance at December 31, 2001	265		$	7,129		$	28	$	289		$	922		$	8,368

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	Before-Tax Amount			Deferred Income Tax (Expense) Benefit			Net-of-Tax Amount
				(millions)
2001
Net income							$	544
Other comprehensive income:
Net deferred gains on derivatives—hedging activities	$	728		$	(263	)		465
Unrealized gains on investment securities		21			(10	)		11
Foreign currency translation adjustments		(9	)		—			(9	)
Minimum pension liability adjustment		7			(3	)		4
Cumulative effect of a change in accounting principle		(289	)		106			(183	)
Amounts reclassified to net income:
Realized gains on investment securities		(14	)		6			(8	)
Net losses on derivatives—hedging activities		51			(19	)		32
Other comprehensive income	$	495		$	(183	)		312
Comprehensive income							$	856
2000
Net income							$	436
Other comprehensive income:
Unrealized gains on investment securities	$	15		$	(6	)		9
Foreign currency translation adjustments		(4	)		—			(4	)
Minimum pension liability adjustment		(24	)		8			(16	)
Amounts reclassified to net income:
Realized losses on investment securities		5			(2	)		3
Other comprehensive loss	$	(8	)		—			(8	)
Comprehensive income							$	428
1999
Net income							$	297
Other comprehensive income:
Unrealized losses on investment securities	$	(17	)	$	3			(14	)
Foreign currency translation adjustments		22			—			22
Amounts reclassified to net income:
Realized gains on investment securities		(4	)		1			(3	)
Other comprehensive income	$	1		$	4			5
Comprehensive income							$	302

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2001			2000			1999
	(millions)
Cash flows from (used in) operating activities
Net income	$	544		$	436		$	297
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of a change in accounting principle, net of income taxes		—			(21	)		—
DCI impairment losses		281			291			—
Extraordinary item, net of income taxes		—			—			255
Gains on sales of businesses		(4	)		(23	)		—
Depreciation, depletion, and amortization		1,322			1,268			798
Deferred income taxes		241			22			64
Deferred fuel expenses, net		(24	)		(33	)		(35	)
Changes in:
Accounts receivable		463			(953	)		81
Inventories		(170	)		(62	)		(6	)
Unrecovered gas costs		255			(217	)		—
Purchase and origination of mortgages		(1,528	)		(4,281	)		(2,575	)
Proceeds from sale and principal collections of mortgages		993			4,295			2,597
Accounts payable, trade		(25	)		626			(24	)
Accrued interest and taxes		(113	)		139			(48	)
Broker margin deposits and liabilities		346			(244	)		1
Derivative and energy trading assets and liabilities		(339	)		(32	)		—
Other		172			132			(150	)
Net cash from operating activities		2,414			1,343			1,255
Cash flows from (used in) investing activities
Plant construction and other property additions		(1,224	)		(1,385	)		(871	)
Gas and oil properties and equipment		(944	)		(353	)		(90	)
Loan originations		—			(2,911	)		(2,581	)
Repayment of loan originations		283			4,255			2,238
Proceeds from sale of businesses		141			836			180
Acquisition of businesses		(2,215	)		(2,779	)		(167	)
Proceeds from sale of securities		30			137			35
Purchase of securities		(104	)		(235	)		(53	)
Other investments		(36	)		(140	)		(152	)
Other		(124	)		(22	)		(81	)
Net cash used in investing activities		(4,193	)		(2,597	)		(1,542	)
Cash flows from (used in) financing activities
Issuance of common stock		245			532			—
Issuance of preferred securities of subsidiary trusts		747			—			—
Repurchase of common stock		—			(1,641	)		(372	)
Issuance of long-term debt		7,365			8,108			6,446
Repayment of long-term debt and preferred stock		(4,193	)		(6,813	)		(5,790	)
Issuance (repayment) of short-term debt, net		(1,620	)		1,820			394
Common dividend payments		(649	)		(615	)		(493	)
Other		10			(57	)		(44	)
Net cash from financing activities		1,905			1,334			141
Increase (decrease) in cash and cash equivalents		126			80			(146	)
Cash and cash equivalents at beginning of period		360			280			426
Cash and cash equivalents at end of period	$	486		$	360		$	280
Supplemental cash flow information:
Cash paid during the year for:
Interest, excluding capitalized amounts	$	854		$	988		$	522
Income taxes		284			240			199
Noncash transactions from investing and financing activities:
Noncash stock and stock option issuance—Louis Dreyfus acquisition		894			—			—
Noncash stock issuance—CNG acquisition		—			3,527			—
Note received in sale of businesses		25			—			260

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF 

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) explains the results of operations and general financial condition of Dominion. MD&A should be read in conjunction with the Consolidated Financial Statements. “Dominion” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion Resources, Inc.’s consolidated subsidiaries, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Risk Factors and Cautionary Statements That May Affect Future Results

This report contains statements concerning Dominion’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by words such as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

Dominion makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These factors include changes to financial or regulatory accounting principles or policies imposed by governing bodies, industry conditions in the regulated, unregulated and transition energy markets, political and economic conditions (including inflation rates) and financial market conditions, including availability and cost of capital and credit ratings. Some more specific risks are discussed below.

Dominion bases its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements are made. Dominion cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may and often do materially differ from actual results. Dominion undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Dominion’s Operations Are Weather Sensitive

Dominion’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather can be destructive, causing outages, property damage and requiring Dominion to incur additional expenses.

Dominion Is Subject to Complex Government Regulation Which Could Adversely Affect Its Operations

Dominion’s operations are subject to extensive regulation and require numerous permits, approvals and certificates from various federal, state and local governmental agencies. Dominion must also comply with environmental protection legislation and other regulations. Management believes the necessary approvals have been obtained for Dominion’s existing operations and that its business is conducted in accordance with applicable laws. However, Dominion remains subject to a varied and complex body of laws and regulations. New laws or regulations or the revision or reinterpretation of existing laws or regulations may require Dominion to incur additional expenses.

Costs of Environmental Compliance, Liabilities and Litigation Could Exceed Dominion’s Estimates

Dominion is subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect 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, particularly with laws relating to power plant emissions. In addition, Dominion may be a responsible party for environmental clean up at a site identified by a regulatory body. Dominion’s management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

Capped Electric Rates in Virginia May Be Insufficient to Allow Full Recovery of Stranded Costs

        Under the Virginia Utility Restructuring Act, Dominion’s electric base rates (excluding fuel costs and certain other allowable adjustments) remain unchanged until July 2007 unless modified consistent with that Act. The capped rates and wires charges that, where applicable, will be assessed to customers opting for alternative suppliers, allow Dominion to recover certain generation-related costs and fuel costs; however, Dominion remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. See Future Issues and Outlook-Regulated Electric Operations of MD&A and Note 27 to the Consolidated Financial Statements.

31

The Electric Industry is Increasingly Subject to Competition

Effective January 1, 2002, the generation portion of Dominion’s electric utility operations in Virginia is open to competition and is no longer subject to cost-based rate regulation. As a result there will be increased pressure to lower costs, including the cost of purchased electricity. Because Dominion’s electric utility business has not previously operated in a competitive environment, the extent and timing of entry by additional competitors into the electric market in Virginia is yet unknown. Therefore, it is difficult to predict the extent to which Dominion will be able to operate profitably within this new environment. In addition, the success of Dominion’s power merchant plants is dependent upon Dominion’s ability to find buyers willing to enter into power purchase agreements at prices sufficient to cover operating costs.

There Are Inherent Risks in the Operation of Nuclear Facilities

Dominion operates nuclear facilities that are subject to inherent risks. These include the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning and potential liabilities arising out of the operation of these facilities. Dominion maintains decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, it is possible that damages could exceed the amount of Dominion’s insurance coverage. In addition, in today’s environment there is a heightened risk of a terrorist attack on the nation’s nuclear plants. Dominion expects to incur increased security costs at its nuclear facilities.

The Use of Derivative Contracts Could Result in Financial Losses

Dominion uses derivatives including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, Dominion could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. For additional information concerning Dominion’s derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management of MD&A and Notes 2 and 15 to the Consolidated Financial Statements.

Dominion’s Telecommunication Business Strategy’s Success Is Dependent Upon Market Conditions

The current strategy of Dominion’s joint venture in the telecommunication’s business is based upon its ability to deliver lit capacity, dark fiber and colocation services to its customers. The market for these services, like the telecommunications industry in general, is rapidly changing. Dominion cannot assure that growth in demand for these services will occur as expected. If the market for these services fails to grow as quickly as anticipated or becomes saturated with competitors, including competitors using alternative technologies such as wireless, Dominion’s investment in the telecommunication business may be adversely affected.

Dominion’s Exploration and Production Business Is Dependent on Factors Including Commodity Prices Which Cannot Be Predicted Or Controlled

These factors include: price fluctuations in natural gas and crude oil prices; results of future drilling activity; Dominion’s ability to identify and locate prospective geological structures and to drill and successfully complete wells in those structures; Dominion’s ability to expand its leased land positions in desirable areas, which are often subject to competition; and other risks incident to the operations of natural gas and oil wells. In addition, Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. The principal limitation is that these capitalized amounts may not exceed the present value of estimated future net revenues from the production of proved gas and oil reserves (the ceiling test). If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

An Inability to Access Financial Markets Could Affect the Execution of Dominion’s Business Plan

Dominion relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow of its operations. Management believes that Dominion and its subsidiaries will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of Dominion’s control may increase the cost of borrowing to Dominion or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn or the bankruptcy of an unrelated energy company. Restrictions on Dominion’s ability to access financial markets may affect Dominion’s ability to execute its business plan as scheduled.

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Operating Segments

In general, management’s discussion of Dominion’s results of operations focuses on the contributions of its operating segments. However, the discussion of Dominion’s financial condition under Liquidity and Capital Resources is based on legal entities. Dominion’s three primary operating segments are:

Dominion Energy manages Dominion’s generation portfolio, consisting primarily of generating units and power purchase agreements. It also manages Dominion’s generation growth strategy; energy trading, marketing, hedging and arbitrage activities; and gas pipeline and certain gas production and storage operations. Dominion Energy’s operating results largely reflect: the impact of weather on demand for electricity; customer growth as influenced by overall economic conditions and acquisitions; and changes in prices of commodities, primarily electricity and natural gas, that the segment actively markets and trades, uses for hedging purposes, and consumes in generation activities.

Dominion Delivery manages Dominion’s electric and gas distribution systems, as well as customer service and electric transmission. Dominion Delivery’s operating results reflect the impact of weather on demand for electricity and natural gas and customer growth as influenced by overall economic conditions. The businesses of Dominion Delivery are subject to cost-of-service rate regulation and changes in prices of commodities consumed or delivered are generally recoverable in rates charged to customers. However, these rates may be subject to price caps, limiting recovery of higher costs in certain circumstances.

Dominion Exploration & Production manages Dominion’s onshore and offshore gas and oil exploration, development and production operations. Operations are located on the outer continental shelf and deep water areas of the Gulf of Mexico and in selected regions in the lower 48 states and Canada. Dominion E&P’s operating results reflect successful discovery of and production from natural gas and oil reserves and changes in prices of natural gas and oil. Dominion E&P manages commodity risk through the use of derivative contracts such as forwards, swaps, and options.

In addition, Dominion also reports the financial services operations of Dominion Capital, Inc. (DCI) and Dominion’s corporate operations as operating segments. Dominion has substantially completed its exit of the core operating businesses of DCI, as required by the SEC under the Public Utility Holding Company Act of 1935 (1935 Act). DCI’s primary business was financial services, including loan administration, commercial lending and residential mortgage lending. Corporate and other includes those costs of Dominion’s corporate operations and certain other charges not allocated to Dominion’s other operating segments.

For more information on Dominion’s operating segments, see Note 30 to the Consolidated Financial Statements.

Critical Accounting Policies

Dominion has identified the following accounting policies that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions.

Accounting for risk management and energy trading contracts at fair value—Dominion uses derivatives to manage its commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. The accounting requirements for derivatives and hedging activities are complex and interpretation of these requirements by standard-setting bodies is ongoing. All derivatives, other than specific exceptions, are reported on the Consolidated Balance Sheet at fair value, beginning in 2001. Energy trading contracts are also reported on the Consolidated Balance Sheets at fair value. Changes in fair value, except those related to derivative instruments designated as cash flow hedges, are generally included in the determination of Dominion’s net income at each financial reporting date until the contracts are ultimately settled. The measurement of fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, Dominion seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies deemed appropriate by Dominion management. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, Dominion must estimate the expected future cash flows of forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition of changes in fair value of certain hedging derivatives. See Selected Information—Energy Trading Activities and Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2, 15, and 28 to the Consolidated Financial Statements.

33

Accounting for gas and oil operations—Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. Depreciation of gas and oil producing properties is computed using the unit-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as dismantlement and abandonment costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proven reserve quantities and estimates of the amount and timing of future expenditures to develop the proven reserves. Actual reserve quantities and development expenditures may differ from the forecasted amounts. Also, amounts capitalized in the depreciable base of costs are subject to a ceiling test. The test limits capitalized amounts to a ceiling — the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves. Dominion performs the test quarterly, on a country-by-country basis, and would recognize asset impairments to the extent capitalized costs exceed the ceiling. See Notes 2 and 31 to the Consolidated Financial Statements.

Accounting for regulated operations—Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition used for accounting purposes, Dominion’s consolidated financial statements may recognize a regulatory asset for expenditures that otherwise would be expensed. 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. See Notes 2, 9, and 18 to the Consolidated Financial Statements.

Results of Operations

Dominion’s discussion of its results of operations includes a summary of contributions by the operating segments to net income and diluted earnings per share, an overview of consolidated 2001 and 2000 results of operations and more detailed discussion of the results of operations of the operating segments.

	2001						2000						1999
	Net Income			EPS			Net Income			EPS			Net Income			EPS
	(millions, except per share amounts)
Dominion Energy	$	723		$	2.86		$	489		$	2.07		$	271		$	1.42
Dominion Delivery		366			1.45			339			1.43			175			0.91
Dominion E&P		320			1.27			255			1.08			44			0.23
Dominion Capital		(14	)		(0.06	)		11			0.05			78			0.41
		1,395			5.52			1,094			4.63			568			2.97
Corporate and Other		(851	)		(3.37	)		(658	)		(2.78	)		(271	)		(1.42	)
Consolidated Total		544			2.15			436			1.85			297			1.48
Consolidated Operating Revenue		10,558						9,246						5,520
Consolidated Operating Expense	$	8,773					$	7,731					$	4,192

For additional information about Dominion’s operating segments, see Note 30 to the Consolidated Financial Statements and the following discussion of each segment’s results of operations.

Overview of 2001 Results

Dominion earned $2.15 per diluted share in 2001 reflecting net income of $544 million and an increase of $108 million and $0.30 per diluted share over 2000. As described below, Dominion recognized higher overall operating revenue reflecting the operations of acquired businesses. This increase was partially offset by comparatively milder weather and higher operating expenses. The increase in operating expenses reflected the recognition of charges associated with the impairment of certain investments at DCI, restructuring activities, and credit-related exposures associated with the bankruptcy of Enron Corp. and certain subsidiaries (Enron).

Operating Revenue

        Operating revenue increased $1.3 billion to $10.6 billion for 2001 as compared to 2000. Dominion acquired Millstone Power Station (Millstone) on March 31, 2001 and its operations contributed largely to the increase in nonregulated electric sales. Regulated electric sales also increased, reflecting comparatively higher fuel recovery rates and continued customer growth partially offset by comparatively mild weather. Regulated gas sales, nonregulated gas sales and gas and oil production revenue increased as 2000 results only included 11 months of Consolidated Natural Gas Company (CNG) operations. In addition, 2001 reflects the inclusion of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) for two months as well as higher realized prices for gas. The results of Dominion’s trading and marketing operations, which are recorded as nonregulated gas and nonregulated electric sales, net of cost of sales, also contributed to the overall increase in operating revenue.

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Operating Expenses

Operating expenses increased $1 billion to $8.8 billion for 2001 as compared to 2000. Higher prices for commodities consumed contributed to increased electric fuel and energy purchases and purchased gas. In addition, purchased gas increased as 2000 amounts only included 11 months of CNG operations. Purchased capacity decreased as Dominion terminated certain contracts in early 2001. Depreciation increased due to the inclusion of Millstone. However, this increase was partially offset by an extension of the useful lives of Dominion’s nuclear plants in connection with the expected relicensing of those plants. Dominion incurred restructuring charges in 2001 and 2000 primarily associated with its acquisition and integration of CNG. In both 2001 and 2000, Dominion recognized impairment and other loan losses on certain DCI loans and other investments. Impairment losses associated with exit activities were reported as restructuring costs and impairment losses associated with the normal operations of DCI were reported as other operations and maintenance. Other operations and maintenance also increased due to the inclusion of Millstone operations, costs associated with terminating certain capacity contracts, and provisions for credit-related exposures associated with Enron’s bankruptcy. Other taxes decreased reflecting the change from gross receipts taxes to state income taxes in Virginia effective January 2001.

Other Factors Affecting Net Income

Interest expense and related charges decreased, reflecting lower overall interest rates on outstanding debt. Dominion’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, higher effective rates associated with foreign earnings and higher pretax income in relation to nonconventional fuel tax credits realized.

Overview of 2000 Results

Dominion earned $1.85 per diluted share in 2000, reflecting net income of $436 million and an increase of $139 million and $0.37 per diluted share over 1999. The inclusion of CNG operations for 11 months of 2000 contributed largely to the increases in both operating revenue and expenses and Dominion’s overall results for 2000. In addition to the impact of CNG, the increase in net income in 2000 over 1999 also included: an extraordinary item in 1999 for the write-off of certain net regulatory assets; the contributions by Dominion’s existing regulated electric utility and gas exploration operations; the costs of restructuring and other CNG acquisition-related activities; costs associated with the DCI exit strategy; acquisition-related interest costs; and a change in the method of accounting for pensions.

Operating Revenue

Total operating revenue increased $3.7 billion to $9.2 billion for 2000 as compared to 1999. The introduction of regulated gas sales and gas transportation and storage in 2000 as well as increases in nonregulated gas sales, gas and oil production and other revenue resulted from the inclusion of CNG operations beginning in late January 2000. Regulated electric sales also increased as a result of customer growth, higher fuel rates, and a charge for rate refunds taken in 1999. Nonregulated electric sales decreased for 2000, reflecting a decrease in available capacity after the expiration of two major long-term power purchase contracts late in 1999.

Operating Expenses

Operating expenses increased $3.5 billion to $7.7 billion for 2000 as compared to 1999. The introduction of purchased gas and liquids, pipeline capacity and other purchases in 2000, as well as increases in other operations and maintenance and depreciation resulted from the inclusion of CNG operations beginning in late January 2000. Electric fuel and energy purchases increased in 2000 due to increased generation activity and higher costs for fossil fuels consumed and energy purchases. In addition, Dominion recognized restructuring and acquisition-related charges for the integration and transition of CNG, and operations and losses associated with DCI investments, some of which were attributable to the DCI exit strategy.

Other Factors Affecting Net Income

Interest expense and related charges increased, reflecting additional borrowings in 2000. The proceeds were used primarily to finance the acquisition of CNG. Also in 2000, the cumulative effect of changing its accounting for certain components of its pension expense increased Dominion’s net income by $21 million. In 1999, Dominion recorded an extraordinary item of $255 million, reflecting primarily the write-off of regulatory assets.

Dominion Energy

	2001		2000		1999
	(millions, except per share amounts)
Operating revenue	$	6,144	$	4,894	$	3,645
Operating expense		4,749		3,939		2,970
Net income contribution		723		489		271
EPS contribution	$	2.86	$	2.07	$	1.42
Electricity supplied (mmwhr)		72		74		71
Gas transmission throughput (bcf)		553		567		—
Gas and oil production (bcfe)		11		12		—

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2001 Results

Dominion Energy contributed $723 million and $2.86 per diluted share for 2001, an increase of $234 million and $0.79 per diluted share over 2000 results. The increase in net income reflects higher revenues due to a full year of CNG operations for 2001, the acquisition of Millstone and reductions in certain operating expenses, including depreciation associated with nuclear plant relicensing and capacity expenses.

Operating Revenue

Operating revenue increased $1.3 billion to $6.1 billion for 2001 as compared to 2000 reflecting the acquisition of Millstone and a full year of CNG operations for 2001. Regulated electric sales for 2001 reflected customer growth and comparatively higher fuel rates; however, these increases were largely offset by comparatively mild weather. Millstone operations contributed largely to the increase in nonregulated electric sales. Nonregulated gas sales and gas transportation and storage revenue increased reflecting a full year of CNG operations and increased transportation rates. The results of Dominion’s trading and marketing operations contributed to the overall increase in operating revenue. The 2001 results also included sales to other Dominion segments of $143 million.

Operating Expenses

Operating expenses increased $810 million to $4.7 billion for 2001 as compared to 2000. Higher commodity prices contributed to increased electric fuel and energy purchases and purchased gas. In addition, purchased gas increased because 2000 expenses included only 11 months of CNG operations. Depreciation increased overall due to the inclusion of Millstone. This increase was partially offset by an extension of the useful lives of Dominion’s nuclear plants in connection with the expected relicensing of those plants. This change in estimate resulted in a $78 million decrease in depreciation expense. Purchased capacity decreased as Dominion terminated certain contracts in early 2001. Other operations and maintenance increased due to the inclusion of Millstone operations and scheduled outages at both nuclear and fossil plants.

2000 Results

Dominion Energy contributed $489 million and $2.07 per diluted share for 2000, an increase of $218 million and $0.65 per diluted share over 1999 results. The increase in net income reflects primarily the inclusion of CNG operations.

Operating Revenue

Operating revenue increased $1.2 billion to $4.9 billion for 2000 as compared to 1999 reflecting primarily the inclusion of CNG operations for 2000. The introduction of gas transportation and storage in 2000 and increases in nonregulated gas sales and other revenue resulted from the inclusion of CNG operations beginning in late January 2000. Regulated electric sales increased as a result of customer growth, higher fuel rates, and a charge in 1999 for rate refunds. Nonregulated electric sales decreased for 2000 reflecting a decrease in available capacity after the expiration of two major long-term power purchase contracts late in 1999. 2000 results also included sales to other Dominion segments of $163 million.

Operating Expenses

Operating expenses increased $969 million to $3.9 billion for 2000 as compared to 1999. The introduction of purchased gas and liquids, pipeline capacity and other purchases in 2000, as well as increases in other operations and maintenance expense and depreciation resulted from the inclusion of CNG operations beginning in late January 2000. Electric fuel and energy purchases increased in 2000 due to increased generation activity and higher costs for fossil fuels consumed and energy purchases.

Selected Information—Energy Trading Activities

Dominion Energy manages Dominion’s energy trading, hedging and arbitrage activities through the Dominion Energy Clearing-house (the Clearinghouse). Dominion believes these operations complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas, electricity and oil. Settlement of a contract may require physical delivery of the underlying commodity or, in some cases, an exchange of cash. These contracts are classified as energy trading contracts for financial accounting purposes, and are included in the Consolidated Balance Sheets as components of current and non-current derivative and energy trading assets and liabilities.

        In accordance with generally accepted accounting principles, Dominion reports energy trading contracts in its financial statements at fair value. Both realized and unrealized changes in these contracts’ fair value are included in net income. For a discussion of how Dominion determines fair value for its energy trading contracts, see Critical Accounting Policies presented earlier in MD&A. Arbitrage activities constitute a substantial portion of the Clearinghouse’s activities. Accordingly, when the Clearinghouse enters into a contract to purchase a commodity, it typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or sometimes will pay a net cash margin

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(a realized loss). Until the contracts are settled, however, Dominion must record the monthly changes in the fair value of both contracts. These changes in fair value represent unrealized gains and losses. To the extent purchase and sales contracts with identical or similar terms are held by the Clearinghouse, the changes in their fair values will generally offset one another. Although the Clearinghouse may hold purchase or sales contracts for delivery of commodities at particular locations and times that have not been offset, such exposures are monitored and actively managed on a daily basis. Dominion’s risk management policy and procedures are designed to ensure that its exposure to commodity price changes is limited. For additional discussion of trading activities, see Market Rate Sensitive Instruments and Risk Management and Notes 2, 15, and 28 to the Consolidated Financial Statements.

A summary of the changes in the unrealized gains and losses in Dominion’s portfolio of energy contracts held for trading purposes during 2001 follows:

	Energy Trading Contracts
	(millions)
Net unrealized gain at December 31, 2000	$	25
Contracts realized or otherwise settled during the period		(1	)
Net unrealized loss at inception of contracts initiated
during the period		(4	)
Change in unrealized gains and losses attributable to
net arbitrage gains and changes in market prices.		129
Changes in unrealized gains and losses attributable
to changes in valuation techniques		16
Net unrealized gain at December 31, 2001	$	165

Unrealized gains and losses in Dominion’s portfolio of energy trading contracts at December 31, 2001 are summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:

	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less than 1 year		1-2 years		2-3 years	3-5 years	Greater than 5 years	Total
	(millions)
Prices actively quoted	$	20		41	11	—	—	$	72
Prices provided by other external sources		—	$	13	10	20	—	$	43
Prices based on models and other valuation methods	$	14		12	6	6	12	$	50

Dominion Delivery

	2001		2000		1999
	(millions, except per share amounts)
Operating revenue	$	2,963	$	2,826	$	1,160
Operating expense		2,202		2,123		735
Net income contribution		366		339		175
EPS contribution	$	1.45	$	1.43	$	0.91
Electricity delivered (mmwhr)		72		74		71
Gas throughput (mmcf)		357		356		—

2001 Results

Dominion Delivery contributed $366 million and $1.45 per diluted share for 2001, an increase of $27 million and $0.02 per diluted share over 2000 results. The increase in net income reflects slightly higher gas throughput and slightly lower volumes of electricity delivered, as well as overall higher gas and electric rates.

Operating Revenue

Total operating revenue increased $137 million to $3.0 billion for 2001 as compared to 2000, reflecting a full year of CNG operations for 2001. This is reflected in higher regulated gas sales and gas transportation and storage revenue. These revenues also increased as a result of higher overall throughput and rates. Regulated electric sales for 2001 reflect customer growth and comparatively higher fuel rates partially offset by the comparatively milder weather.

Operating Expenses

Operating expenses increased $79 million to $2.2 billion for 2001 as compared to 2000. Higher prices of commodities delivered or consumed contributed to increased purchased gas expense. In addition, purchased gas increased as 2000 amounts only included 11 months of CNG operations.

2000 Results

Dominion Delivery contributed $339 million and $1.43 per diluted share for 2000, an increase of $164 million and $0.52 per diluted share over 1999 results. The increase in net income reflects the inclusion of CNG operations.

Operating Revenue

Total operating revenue increased $1.7 billion to $2.8 billion for 2000 as compared to 1999 reflecting primarily the inclusion of CNG operations for 2000. The introduction of regulated gas sales and gas transportation and storage in 2000 resulted from the inclusion of CNG operations beginning in late January

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2000. Regulated electric sales increased as a result of customer growth, higher fuel rates, and a charge in 1999 for rate refunds. Weather did not result in material changes in regulated electric sales for the comparable periods. However, colder weather in Dominion’s gas distribution service territories resulted in higher than normal throughput and was reflected in regulated gas sales and gas transportation and storage revenue.

Operating Expenses

Operating expenses increased $1.4 billion to $2.1 billion for 2000 as compared to 1999. The introduction of purchased gas and liquids, pipeline capacity and other purchases in 2000, as well as increases in other operations and maintenance expense and depreciation resulted from the inclusion of CNG operations beginning in late January 2000.

Dominion E&P

	2001		2000		1999
	(millions, except per share amounts)
Operating revenue	$	1,460	$	1,330	$	256
Operating expense		934		920		212
Net income contribution		320		255		44
EPS contribution	$	1.27	$	1.08	$	0.23
Natural gas and oil produced (bcfe)		327		304		109

2001 Results

Dominion E&P contributed $320 million and $1.27 per diluted share for 2001, an increase of $65 million and $0.19 per diluted share over 2000 results. The increase in net income reflects a full year of CNG operations for 2001, two months of Louis Dreyfus operations and higher realized gas and oil prices.

Operating Revenue

Total operating revenue increased $130 million to $1.5 billion for 2001 as compared to 2000 reflecting a full year of CNG operations for 2001, two months of Louis Dreyfus operations and higher gas and oil prices. Average realized gas and oil prices increased 16 percent to $3.85/mcfe during 2001. For 2001, overall gas and oil production increased 8 percent to 327 bcfe. These increases reflect the addition of Louis Dreyfus operations in the fourth quarter of 2001 offset somewhat by natural declines at certain Dominion gas and oil production properties. Dominion E&P sold $106 million of natural gas and oil to other Dominion segments in 2001.

Operating Expenses

Operating expenses increased $14 million to $934 million for 2001 as compared to 2000 and include the addition of Louis Dreyfus operations in the fourth quarter of 2001, as well as higher operations and maintenance expenses associated with service industry and contractor costs. Operating expenses associated with purchases of gas and oil for brokered sales decreased for 2001.

2000 Results

Dominion E&P contributed $255 million and $1.08 per diluted share for 2000, an increase of $211 million and $0.85 per diluted share over 1999 results. The increase in net income reflects the inclusion of CNG operations.

Operating Revenue

Total operating revenue increased $1.1 billion to $1.3 billion for 2000 as compared to 1999 reflecting primarily the inclusion of CNG operations in 2000. Dominion E&P sold $51 million of natural gas and oil to other Dominion segments in 2000. In addition to CNG operations, 2000 results included a full year of operations from property acquisitions in 1999 including a Canadian exploration and production company and other properties in the San Juan Basin of New Mexico.

Operating Expenses

Operating expenses increased $708 million to $920 million for 2000 compared to 1999. The introduction of purchased gas and liquids, pipeline capacity and other purchases in 2000 as well as increases in other operations and maintenance expense and depreciation resulted from the inclusion of CNG operations beginning in late January 2000.

Dominion Capital

	2001			2000		1999
	(millions, except per share amounts)
Other revenue	$	234		$	433	$	473
Operating expense (including interest)		268			410		360
Net income (loss) contribution		(14	)		11		78
EPS contribution	$	(0.06	)	$	0.05	$	0.41

During 2000, DCI implemented a strategy to exit and windup its core operating businesses as required by the SEC under the 1935 Act in connection with Dominion’s acquisition of CNG. The results of DCI reflect this strategy.

2001 Results

DCI reported losses of $14 million and $0.06 per diluted share for 2001, as compared to net income of $11 million and $0.05 per diluted share in 2000. Other revenue decreased $199 million to $234 million for 2001 as compared to 2000. These results reflect lower interest income as a substantial portion of the commercial loan portfolio was sold in the fourth quarter of 2000. In addition, mortgage loans originated in the second quarter of

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2001 were not securitized but sold as part of the Saxon Capital sale. Operating expenses decreased $142 million to $268 million for 2001 compared to 2000 reflecting reduced interest expense and lower general and administrative expenses resulting from reduced operations. See Corporate and Other below and Note 6 to Consolidated Financial Statements.

2000 Results

DCI contributed $11 million and $0.05 per diluted share for 2000, as compared to net income of $78 and $0.41 per diluted share in 1999. Other revenue decreased $40 million to $433 million for 2000 as compared to 1999. Mortgage volumes were $2.1 billion in 2000, down from $2.4 billion in 1999. As a result of the sale and restructuring of loans, the commercial finance operations portfolio decreased to $676 million at the end of 2000 compared to $2.0 billion at the end of 1999.

Corporate and Other

	2001			2000			1999
	(millions)
Net expense	$	(851	)	$	(658	)	$	(271	)

2001 Results

Net expenses associated with corporate and other operations were $851 million and $(3.37) per diluted share, an increase in net expenses of $193 million and $0.58 per diluted share as compared to 2000. Net expenses for 2001 include the following unusual charges which were not allocated to Dominion’s other operating segments (amounts are pre-tax): restructuring costs of $105 million; impairment of DCI investments of $281 million; loss of $40 million on the sale of Saxon Capital; provision for credit exposure associated with Enron bankruptcy of $151 million; and a charge of $220 million related to the purchase of three non-utility generating plants previously serving Dominion under long-term contracts. See Notes 7, 8, 15, and 27 to the Consolidated Financial Statements.

2000 Results

Net expenses associated with corporate and other operations were $658 million and $(2.79) per diluted share, an increase of $387 million and $1.37 per diluted share as compared to 1999. 2000 results included restructuring and acquisition-related charges of $460 million, DCI impairments of $119 million and the cumulative effect of an accounting change of $21 million. In 1999, Dominion recorded an extraordinary item of $255 million, net of tax, reflecting primarily the write-off of certain net regulatory assets. See Notes 7, 8, and 9 to the Consolidated Financial Statements.

Liquidity and Capital Resources

Dominion and its subsidiaries depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by the cash flow from operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term debt financing.

Internal Sources of Liquidity

Cash flow from operating activities provided $2.4 billion, $1.3 billion and $1.3 billion during 2001, 2000 and 1999, respectively. The increase in cash flow from operating activities during 2001, as compared to 2000, reflects primarily: collections of receivables outstanding as of December 31, 2000; recovery of previously deferred gas costs; and the inclusion of CNG’s operations for the entire year. These sources of cash were partially offset by a reduction in payables, a decrease in cash flow from financial services operations due to the exiting of DCI’s core businesses, and an increase in inventory purchases. At December 31, 2000, receivables resulting from gas sales, marketing and trading activities, as well as unrecovered gas costs, were higher than normal due to the sharp increase in gas prices in late 2000. Dominion’s cash flow information for 2000 includes CNG operations beginning January 28, 2000. Cash flow from operating activities during 2000, as compared to 1999, increased primarily due to the acquisition of CNG.

Dominion’s operations are subject to risks and uncertainties that may negatively impact cash flows from operations. Such risks and uncertainties include, but are not limited to, the following:

• unusual weather and its effect on energy sales to customers and energy commodity prices;

• extreme weather events that could disrupt offshore gas and oil production or cause catastrophic damage to Dominion’s electric distribution and transmission systems;

• exposure to unanticipated changes in prices for energy commodities purchased or sold;

• effectiveness of Dominion’s risk management activities and underlying assessment of market conditions and related factors, including energy commodity prices, basis, counter-party credit risk, liquidity, volatility, capacity, transmission, currency exchange rates, and interest rates;

• the cost of replacement electric energy in the event of unscheduled generation outages;

• contractual or regulatory restrictions on transfers of funds among Dominion and its subsidiaries; and

• timeliness of recovery for costs subject to cost-of-service utility rate regulation.

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External Sources of Liquidity

Dominion Resources, Inc., Virginia Electric and Power Company and CNG (the Dominion Companies) rely on access to bank and capital markets as a significant source of liquidity for capital requirements not satisfied by cash provided by the companies’ operations. The Dominion Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by the issuing company’s credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including the SEC and, in the case of Virginia Electric and Power Company (Virginia Power), the Virginia State Corporation Commission (Virginia Commission). Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities. Management believes that the current credit ratings of the Dominion Companies provide sufficient access to the capital markets. However, disruptions in the bank and capital markets not specifically related to Dominion may affect the Dominion Companies’ ability to access these funding sources or cause an increase in the return required by investors.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. The credit ratings for the Dominion Companies are most affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable, such as major acquisitions. Credit ratings for the Dominion Companies as of March 1, 2002 follow:

	Standard & Poor’s	Moody’s
Dominion Resources, Inc.
Senior unsecured debt securities	BBB+	Baa1
Preferred securities of subsidiary trusts	BBB-	Baa2
Commercial paper	A-2	P-2
Virginia Power
Mortgage bonds	A	A2
Senior unsecured debt securities (including tax-exempt)	A-	A3
Preferred securities of subsidiary trust	BBB+	Baa1
Preferred stock	BBB+	Baa2
Commercial paper	A-1	P-1
CNG
Senior unsecured debt securities	BBB+	A3
Preferred securities of subsidiary trust	BBB-	Baa1
Commercial paper	A-2	P-2

A downgrade in an individual company’s credit rating would not generally restrict its ability to raise short-term and long-term financing so long as its credit rating is still “investment grade,” but it would increase the cost of borrowing. Dominion’s management proactively manages the financial structure of its consolidated businesses, including its business mix and acquisition investments in an effort to maintain the Dominion Companies’ current credit ratings.

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, the Dominion Companies must enter enabling agreements. These agreements contain covenants that, in the event of default, could trigger the acceleration of principal and interest payments and, in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to the Dominion Companies. Some of the typical covenants include:

• the timely payment of principal and interest;

• information requirements, including submittal of financial reports filed with the SEC to lenders;

• keeping books and records in accordance with generally accepted accounting principles;

• payment of taxes, maintaining insurance;

• performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, restrictions on disposition of substantial assets;

• financial covenants, such as a limit on total funded debt to total capitalization; and

• limitations on liens.

Dominion monitors the covenants on a regular basis in order to provide assurance that events of default will not occur. As of December 31, 2001, there were no events of default under the Dominion Companies’ covenants.

During 2001, the Dominion Companies issued long-term debt, preferred securities through affiliated subsidiary trusts, and common stock totaling $8.4 billion. As discussed below, proceeds were used primarily to repay short-term debt, finance major acquisitions and capital expenditures, and support financial services operations.

2001—Financings Associated with Major Acquisitions

In 2001, Dominion Resources, Inc., refinanced the remaining bridge financing associated with the CNG acquisition with the following issuances of securities: $300 million of 8.4 percent trust preferred securities due 2041, issued through an affiliated trust, and $1 billion of 2-year fixed rate 6 percent senior notes.

Also in 2001, Dominion Resources, Inc., through another affiliated trust, issued $250 million ($247 million after discount) of 8.4 percent capital securities due 2031, in connection with the acquisition of Millstone. The balance of the acquisition was funded by proceeds of common stock issued in 2000 and cash temporarily available from other internal sources. Dominion

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expects to permanently finance the portion temporarily funded by internal sources by issuing Dominion Resources, Inc. debt securities in the future. In January 2002, Dominion Resources, Inc. issued $250 million 3.875 percent medium-term notes due 2004 for this purpose.

Dominion financed the cash consideration for the acquisition of Louis Dreyfus and the repayment of certain Louis Dreyfus debt with the following issuances of CNG securities: $200 million of 7.8 percent trust preferred securities due 2041, issued through an affiliated trust; $500 million of 5.375 percent senior notes due 2006; and $450 million of 6.25 percent senior notes due 2011.

2001—Short-Term Borrowings

At December 31, 2001, the Dominion Companies had commercial paper programs with an aggregate limit of $2.05 billion supported by a $1.75 billion 364-day revolving credit facility and a $300 million multi-year facility. These credit facilities mature in the second quarter of 2002 and are expected to be replaced. During 2001, credit facilities totaling $1.05 billion matured and were not renewed.

The Dominion Companies’ net borrowings under the commercial paper program were $1.86 billion at December 31, 2001, a decrease of $555 million from amounts outstanding at December 31, 2000. Commercial paper borrowings are used primarily to fund working capital requirements and bridge financing of acquisitions, and therefore may vary significantly during the course of the year depending upon the timing and amount of cash requirements not satisfied by cash provided by operations.

In addition to commercial paper, Virginia Power may also issue up to $200 million aggregate outstanding principal of extendible commercial notes (ECNs) to meet working capital requirements. ECNs are unsecured notes that are expected to be sold in private placements. Any ECNs issued would have a stated maturity of 390 days from issuance and may be redeemed, at Virginia Power’s option, within 90 days or less from issuance. There were no ECNs outstanding at December 31, 2001.

2001—Issuance of Common Stock

In 2001, Dominion received proceeds of $245 million from the issuance of common stock through Dominion Direct (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans, and the exercise of employee stock options. In addition, Dominion issued 14 million shares of common stock and stock options as part of the consideration paid in the acquisition of Louis Dreyfus at a total value of approximately $894 million.

2001—Other Securities Issuances and Repayments

During 2001, Dominion and its consolidated subsidiaries also issued the following other securities and used the net proceeds primarily for general corporate purposes, including the repayment of commercial paper and other debt and capital expenditures:

• Senior notes: $1.1 billion bearing interest at (5.75 percent—6.85 percent) due 2006-2011;

• Medium-term notes: $220 million bearing interest at variable rates due 2003;

• Medium-term notes denominated in Canadian dollars and issued through a Canadian subsidiary: $117 million (US dollars) bearing interest at 6.1 percent due 2006;

• Tax exempt bonds: $50 million bearing interest at variable rates due in 2031; and

• Notes with affiliates: $194 million 6 percent note to an affiliated telecommunications entity due 2005, and a $518 million variable rate demand note due by 2006 to another affiliated telecommunications entity. See Dominion Fiber Ventures, LLC below and Note 29 to the Consolidated Financial Statements.

In 2001, Dominion and its consolidated subsidiaries repaid approximately $1.0 billion of long-term debt securities, excluding debt repayments associated with financial services operations. Also in 2001, Dominion purchased and redeemed, at par, all of the outstanding shares of the Virginia Power January 1987 and June 1987 series of money market preferred stock for $125 million.

In January 2002, Virginia Power called its $200 million, 6.75 percent 1997-A mortgage bonds due February 1, 2007 for redemption in February 2002. Virginia Power funded the redemption by issuing $650 million of 5.375 percent senior notes due 2007. Virginia Power used the remaining proceeds for general corporate purposes and to repay other debt.

2001—DCI Financing Activities

In connection with the purchases and originations of loans and the sales and collections of loans during 2001, DCI issued $3.3 billion and repaid $3.0 billion of long-term debt. With the sale of Saxon Capital in July 2001, DCI no longer engages in the financial services activities giving rise to these sources and uses of cash. For a discussion of Dominion’s divestiture of its financial services business, see Note 6 to the Consolidated Financial Statements.

Amounts Available under Shelf Registrations

At December 31, 2001, Dominion Resources, Inc. had approximately $2.3 billion principal amount remaining under currently effective shelf registrations, which was reduced in January 2002 by the issuance of $250 million of medium term notes due

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2004. Virginia Power had $900 million principal amount remaining under an effective shelf registration, which was reduced in January 2002 by the aforementioned issuance of $650 million of senior notes. At December 31, 2001, CNG did not have any amounts remaining under effective shelf registrations. However, CNG expects to file a shelf registration with the SEC in March 2002 for an additional $1.5 billion principal amount in debt and trust preferred securities.

Investing Activities

In 2001, investing activities resulted in a net cash outflow of $4.2 billion, reflecting the following primary investing activities:

• capital expenditures of $1.2 billion that included construction and expansion of generation facilities, environmental upgrades, purchase of nuclear fuel, and construction and improvements of gas and electric transmission and distribution assets;

• capital expenditures of $944 million that included the purchase of gas and oil producing properties, drilling and equipment costs and undeveloped lease acquisitions;

• proceeds from securitizations and collections of loans receivable by DCI of $283 million;

• acquisition of Millstone for approximately $1.3 billion;

• cash consideration for acquisition of Louis Dreyfus for approximately $902 million; and

• proceeds from the sale of Saxon Capital of $141 million.

For discussion of Dominion’s acquisition of Millstone and Louis Dreyfus, see Note 5 to the Consolidated Financial Statements.

Capital Expenditures

Dominion’s planned capital expenditures during 2002, 2003 and 2004 are expected to total approximately $2.5 billion, $3.2 billion and $3.3 billion, respectively. These expenditures include construction and expansion of generation facilities, environmental upgrades, construction improvements of gas and electric transmission and distribution assets, purchases of nuclear fuel and expenditures to develop natural gas and oil properties. Dominion expects to fund its capital expenditures with cash from operations; a combination of sales of securities and short-term borrowings.

Contractual Cash Obligations and Commitments

Other than planned capital expenditures, Dominion has contractual cash obligations and commitments associated with the following: repayment of long-term debt and mandatorily redeemable preferred securities of subsidiary trusts (see Notes 20 and 22 to the Consolidated Financial Statements); purchased power contracts, fuel purchase contracts, natural gas pipeline and storage capacity contracts and leases (see Note 27 to the Consolidated Financial Statements). Dominion expects to fund these obligations and commitments with cash flow from operations and a combination of sales of securities and short-term borrowings. Contractual cash obligations and commitments at December 31, 2001 follow: 2002—$2.7 billion; 2003—$3.2 billion; 2004—$2.4 billion; 2005—$1.9 billion; 2006—$2.3 billion; and years after 2006—$13.8 billion. The amount for 2002 includes $1.35 billion associated with the redemption of previously issued securities that are scheduled to mature. These amounts do not include working capital commitments, including the repayment of short-term debt (see Note 19 to the Consolidated Financial Statements) and settlement of derivative and energy trading contracts (see Note 15 to the Consolidated Financial Statements), or amounts for interest or distributions payable on securities issued by Dominion (see Notes 20 and 22 to the Consolidated Financial Statements). In addition, at December 31, 2001, Dominion had issued $3.3 billion of guarantees to various third parties in relation to payment of obligations by certain of its subsidiaries and officers. At December 31, 2001, subsidiary debt subject to such guarantees totaled $1.1 billion and officers’ borrowings under the executive stock loan program guaranteed by Dominion totaled $84 million.

        As of December 31, 2001, Dominion, through certain subsidiaries, has entered into agreements with special purpose entities (Lessors) in order to finance and lease several new power generation projects, as well as its corporate headquarters and aircraft. The Lessors have an aggregate financing commitment from equity and debt participants (Investors) of $2.2 billion, of which $817 million has been used for total project costs to date. Dominion, in its role as construction agent for the Lessors, is responsible for completing construction by a specified date. In the event a project is terminated before completion, Dominion has the option to either purchase the project for 100 percent of project costs or terminate the project and make a payment to the Lessor of approximately but no more than 89.9 percent of project costs. Upon completion of each individual project, Dominion has use of the project assets subject to an operating lease. Dominion’s lease payments to the Lessors are sufficient to provide a return to the Investors. At the end of each individual project’s lease term, Dominion may renew the lease at negotiated amounts based on project costs and current market conditions, subject to Investors’ approval; purchase the project at its original construction cost; or sell the project, on behalf of the Lessor, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, Dominion may be required to make a payment to the Lessor, ranging from 81 percent to 85 percent of the project cost depending on the individual project and applicable agreement. Dominion has guaranteed a portion of the obligations of its subsidiaries to the Lessors during the construction and

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post-construction periods. These transactions do not contain any type of credit rating or stock price trigger events.

As noted above, as of December 31, 2001, amounts subject to these agreements totaled $817 million, and the total amount, upon completion of all projects, is projected to be approximately $2.2 billion. The projects are accounted for as operating leases for financial accounting purposes. Accordingly, neither the project assets nor related obligations are reported on Dominion’s balance sheets. The contractual cash commitments and obligations discussed above include annual payments of approximately $6 million associated with these projects representing minimum payments under leases for which the leased assets are currently in use. Projects currently under development are scheduled for completion during the period 2002 through 2004. Annual lease payments for the projects are estimated to be $33 million in 2002, increasing to $133 million by 2004.

Dominion Fiber Ventures, LLC

In December 2000, Dominion formed Dominion Fiber Ventures, LLC (DFV) to facilitate the expansion of the telecommunications businesses of its subsidiary, Dominion Telecom, Inc. (DTI). In March 2001, Dominion contributed all outstanding shares of DTI with an estimated equity value of $110 million to DFV, in exchange for 100 percent of Class B managing membership interests in DFV. A third-party investor trust contributed $60 million in cash for 100 percent of the Class A membership interests in DFV. As a result of the Class A membership interests having substantive minority veto rights, Dominion’s investment in DFV is accounted for using the equity method and is reported in investments in affiliates on the 2001 Consolidated Balance Sheet.

In March 2001, DFV issued $665 million of 7.05 percent senior secured notes due March 2005 (DFV Senior Notes) and contributed part of the net proceeds to DTI. Pending the need for cash to fund capital expenditures in the expansion of its telecommunications network, DFV and DTI temporarily loaned proceeds from the issuance of the DFV Senior Notes and cash contributed by the Class A member to Dominion. Dominion used the proceeds to repay commercial paper. At December 31, 2001, Dominion owed $367 million under these loans and reported it as notes payable —affiliates on the 2001 Consolidated Balance Sheet.

The DFV Senior Notes are secured by DTI stock and in part by certain rights with respect to 665,000 shares of Series A Mandatorily Convertible Preferred Stock (Preferred Stock), liquidation preference $1,000 per share, issued by Dominion and held by Piedmont Share Trust (Piedmont Trust). Dominion is the beneficial owner of Piedmont Trust which is consolidated in the preparation of Dominion’s financial statements. If the DFV Senior Notes are not otherwise paid at maturity, or in the event there is a downgrade of Dominion Resources, Inc. senior unsecured debt to BBB- or Baa3 and the closing price of Dominion’s common stock is below $45.97 for 10 consecutive trading days, the Preferred Stock is subject to remarketing, with the proceeds being used to retire the DFV Senior Notes. If the remarketing of the Preferred Stock were to occur, the Preferred Stock, as convertible securities, would be considered in the calculation of diluted earnings per share of Dominion’s common stock or could result in the issuance of additional shares of Dominion common stock, if converted.

Related Party Transactions

For additional information about Dominion’s investment in DFV and other related party transactions, see Note 29 to the Consolidated Financial Statements.

Future Issues and Outlook

Regulated Electric Operations

Electric Deregulation Legislation

Virginia—In 1999, Virginia enacted comprehensive restructuring legislation. The Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) established a plan to restructure Virginia’s electric utility industry and provided for the phase-in of choice for retail customers from January 1, 2002 through January 1, 2004. The Virginia Commission has ordered that retail choice be fully implemented in Virginia by January 1, 2003 for customers of Dominion’s regulated electric subsidiary.

        Under the Virginia Restructuring Act, the generation portion of Dominion’s Virginia jurisdictional operations is no longer subject to cost-based rate regulation, effective January 1, 2002. Dominion’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007 unless terminated sooner as provided by the Virginia Restructuring Act. Recovery of generation-related costs will continue through capped rates and, where applicable, a wires charge assessed on those customers opting for alternative suppliers. Dominion may petition the Virginia Commission to terminate the capped rates after January 1, 2004. If Dominion were to request that the capped rates be terminated, the Virginia Commission may terminate the capped rates if it finds that a competitive generation services market exists within Dominion’s service area. Dominion’s wires charge is the excess of its capped unbundled rate for generation over the projected market price for generation. The wires charge is intended to compensate Dominion for its investment in and commitments for generation-related utility assets prior to the enactment of the restructuring legislation. Dominion’s methodology for calculating the wires charge and applicable market price has been approved by the Virginia Commission. Additionally, the Virginia Restructuring Act provides that after the end of the capped rate period, any default

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service provided by Dominion will be based upon competitive market prices for electric generation services.

Dominion began the phase-in of retail choice on January 1, 2002. The phase-in will be completed on January 1, 2003. Dominion is able to accommodate this schedule as a result of experience gained during its retail access pilot program, as well as extensive testing of its processes and systems to support customers switching to retail access. Additionally, the pilot demonstrated Dominion’s ability to sell energy displaced by shopping customers in the wholesale market.

During the capped rate period, Dominion may require a 12-month minimum stay period for electricity customers with an annual peak demand of 500 kilowatts or greater who request electricity supply service after receiving electricity supply service from a competitive service provider. This measure will mitigate the practice of large commercial and industrial customers returning to Dominion’s capped rate service during periods of higher market prices and leaving during periods of lower market prices —a practice known as “seasonal gaming.”

As discussed in the Separation of Generation and Delivery Operations in Virginia and Alliance RTO sections below, the Virginia Restructuring Act also calls for the functional separation of generation, transmission and distribution.

North Carolina—The North Carolina General Assembly is exploring the future of electric service in North Carolina, the development of a competitive wholesale market and retail competition. However, there has been little recent activity.

Separation of Generation and Delivery Operations in Virginia

The Virginia Restructuring Act addressed divestiture, functional separation and other corporate relationships. The Act required Virginia’s electric utilities to file with the Virginia Commission their plans to separate generation from transmission and distribution operations.

Dominion’s proposed separation plan included transferring the generation assets and operations, including its non-utility power purchase contracts, from its regulated electric utility, Virginia Power, to a separate affiliated company. In December 2001, the Virginia Commission directed Dominion to separate its generation, distribution, and transmission functions through creation of divisions within Virginia Power, rather than through transfer of generation assets to a separate affiliate. The Virginia Commission’s December 2001 order did not preclude further consideration of Dominion’s proposed corporate reorganization and asset transfer, pending, in the Virginia Commission’s view, further developments in needed market structures and competitive retail electric generation markets. Dominion has filed a notice of appeal of the Virginia Commission’s order. No assessment can be made at this time concerning future developments.

Because Virginia Power’s operations were largely functionally separated in its existing corporate structure, implementation of the plan ordered by the Virginia Commission will require few changes in Virginia Power’s operations. Virginia Power will continue to provide electric service to its customers at capped rates until July 1, 2007, unless capped rates are terminated after January 1, 2004, as provided in the Virginia Restructuring Act. Virginia Power will continue serving customers who select alternative energy suppliers by delivering the electric energy and will collect a wires charge, if applicable, as discussed above. Virginia Power will also be permitted to continue its activities in wholesale energy markets. However, effective January 1, 2002, Virginia codes of conduct became effective, governing certain transactions and communications between Virginia Power’s electric distribution and transmission operations and its generation division. These codes of conduct are designed to prevent cross-subsidies between the generation and other divisions and to ensure that the generation and other divisions operate independently.

Alliance RTO

Both the Virginia Restructuring Act and the Federal Energy Regulatory Commission (FERC) merger conditions require that Dominion join a regional transmission organization (RTO). By joining an RTO, Dominion’s regulated electric utility subsidiary, Virginia Power, would transfer operational control of its transmission assets to the RTO, a separate entity. Dominion, together with eight other member companies (Alliance Companies), filed with FERC for approval of the proposed “Alliance RTO.” Dominion also filed an application to transfer control of its transmission facilities to the Alliance RTO with the Virginia Commission and North Carolina Utilities Commission. In December 2001, FERC concluded the Alliance Companies lack sufficient scope as an RTO and also ordered the Alliance Companies to determine how they could fit within the Midwest Independent System Operator. Dominion will examine the possibility of joining RTOs other than those representing Midwest utilities, as directed by FERC. As a result of the FERC decision, the North Carolina application was dismissed and the Virginia application was stayed. Dominion expects to refile or amend the state applications.

        Despite these delays, Dominion remains committed to supporting electric deregulation by becoming a member of an RTO. The formation of RTOs is important to enhancing wholesale electric competition through the creation of standardized market rules, tariffs, and interconnection agreements. RTOs will put all suppliers on an equal footing and enhance access to non-discriminatory delivery services. Membership in an RTO and regionalization of electric markets will provide opportunities for Dominion to expand its business by providing generation

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services to more customers. While a new regional authority will make major operational decisions and operate the entire grid, Dominion will continue to ensure that the local systems operate reliably. In 2001, Dominion focused on the new systems, business processes, regulatory filings and contractual relationships necessary to implement electric deregulation and regional transmission operations.

Wholesale Competition

Dominion’s electric utility subsidiary sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service territory. In January 2002, Dominion’s electric utility subsidiary filed for FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside its service territory. Any such sales would be voluntary. Dominion expects FERC to approve the tariff during the first quarter of 2002.

Dominion’s sales of natural gas and oil in wholesale markets are not regulated by FERC.

Exposure to Potentially Stranded Costs

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. At December 31, 2001, Dominion’s exposure to potentially stranded costs consisted of long-term purchased power contracts that could ultimately be determined to be above market; 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.

Dominion believes capped electric retail rates and, where applicable, wires charges provided under the Virginia Restructuring Act provide a reasonable opportunity to recover a substantial portion of its potentially stranded costs. Based on estimates at March 31, 1999, Dominion would have otherwise been exposed, on a pre-tax basis, to an estimated $3.2 billion of potential losses related to long-term power purchase commitments without the recoveries provided by the capped rates. Recovery of Dominion’s potentially stranded costs remains subject to numerous risks even in the capped-rate environment including, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs, and recovery of certain other items. See Notes 16, 26 and 27 to the Consolidated Financial Statements.

Rate Matters—Electric

Virginia—Dominion’s separation plan, as described in Separation of Generation and Delivery Operations in Virginia, proposed an index-based fuel cost recovery based on forecasted generation by fuel types and projected fuel price indices, to be effective after January 1, 2002. Dominion subsequently withdrew the index-based fuel cost recovery mechanism and will continue to develop an alternative methodology. Dominion’s current Virginia jurisdictional fuel factor will remain in effect until December 31, 2002. Proceedings to be initiated during 2002 will determine the fuel factor after that date.

Dominion filed its Virginia Commission-approved unbundled rates reflecting the functional separation of generation, transmission and distribution in January 2002. As previously discussed, Dominion will phase in retail choice for all customers in its service territory by January 1, 2003. Where applicable, wires charges, effective January 1, 2002 and subject to annual adjustment, will be paid by Dominion’s Virginia jurisdictional retail customers who choose an alternative generation supplier during the capped rate period.

North Carolina—Dominion’s regulated electric utility cannot request an increase in its North Carolina jurisdictional base rates until 2006, except for certain events that would have a significant financial impact. Fuel rates, however, are still subject to change under annual proceedings.

Regulated Gas Distribution Operations

Gas Deregulation Legislation

Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.

        Ohio—Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Public Utilities Commission of Ohio (Ohio Commission), Dominion on its own initiative offers retail choice to customers. Dominion’s Energy Choice program is available to all 1.2 million customers in Dominion’s Ohio service area. At December 31, 2001, approximately 586,000 of Dominion’s Ohio customers were participating in this open-access program. Large industrial customers in Ohio also source their own natural gas supplies.

Pennsylvania—At December 31, 2001, approximately 125,000 residential and small commercial customers had opted for Energy Choice in Dominion’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from unregulated suppliers.

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West Virginia—At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. The West Virginia Public Service Commission (West Virginia Commission) recently issued regulations to govern pooling services; these services are one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future.

Rate Matters—Gas Distribution

Ohio—In October 2001, the Ohio Commission approved a program developed by Dominion to address the inability of certain customers to pay delinquent account balances. In many cases, these customers were impacted by last winter’s unusually high gas prices and cold weather. Under this one-time matching program, Dominion matched dollar-for-dollar, up to $500 per customer, the first payment received by December 31, 2001 for qualifying customers who had received a disconnection notice or who had been disconnected as of October 31, 2001. Matching amounts totaling $10 million were credited to customers’ accounts at December 31, 2001.

The Ohio Commission and Dominion also agreed that adjustments of approximately $100 million to depreciation were appropriate in order to reflect the effect of certain fixed assets exceeding their original estimated useful lives. The Ohio Commission initially held that payments made under the matching program and subsequent write-offs of bad debts in excess of the amount already recovered in rates could be offset by reductions in the excess depreciation reserve through a bad debt rider. The Ohio Commission revised its decision on the bad debt rider but allowed the payment-matching program to continue. Under the revised final order, the Ohio Commission authorized the deferral of certain amounts incurred by Dominion in excess of the amount of bad debt expense already recovered in rates, pending recovery in the next rate case. Dominion recognized a regulatory asset of $80 million, representing the excess customer bad debt costs as of December 31, 2001. Dominion believes that it will recover those amounts deferred. See Note 18 to the Consolidated Financial Statements.

Pennsylvania—The Audit Bureau of the Pennsylvania Public Utility Commission (Pennsylvania Commission) has conducted a compliance audit of Dominion’s purchased gas cost rates for the years 1997 through 1999. In the fourth quarter of 2001, Dominion received an audit report in which the Audit Bureau noted certain exceptions and proposed adjustments that, if determined to be appropriate, would result in refunds to customers. Dominion is discussing the matter with the Pennsylvania Commission and believes that the ultimate resolution of this issue will not have a material impact on its financial position, results of operations or cash flows.

West Virginia—In 2001, the West Virginia Commission approved a settlement between Dominion and certain third parties, regarding the costs of gas supplies and increased operating costs, that stipulated that Dominion would receive a $9.5 million increase in gas and non-gas revenues. The settlement also provides for a two-year rate moratorium. The new rates took effect on January 1, 2002 and will be in place through December 31, 2003.

Interstate Gas Transmission Operations

FERC Policy Developments

FERC’s most significant near-term policy initiative regarding interstate gas pipelines may also impact Dominion’s interstate electric transmission operations. FERC proposes to eliminate its existing, separate code of conduct regulations for natural gas pipelines and electric transmission utilities, and to replace these requirements with uniform standards applicable to interstate “Transmission Providers” both of natural gas and of electricity. The proposed standards would redefine the scope of affiliates covered by standards of conduct for most FERC-regulated companies. If the proposed policy is adopted, it will supersede the existing broad standards, imposed as a result of the CNG acquisition, that are now applicable to Dominion, and will improve its competitive standing among other integrated energy companies.

Dominion supports FERC’s policy goal to ensure a competitive interstate energy market. However, Dominion advocates certain adjustments to recognize the significant operational differences between gas pipelines and electric transmission companies. Dominion anticipates further action by FERC by mid-2002. While Dominion expects the outcome of a final rule to improve its ability to compete with similarly-situated transmission providers, Dominion does not expect the final rule to have a short-term material impact on its results of operations, financial position or cash flows.

Rate Matters—Gas Transmission

Dominion implemented various rate filings, tariff changes, and negotiated rate service agreements during 2001. In all material respects, the filings were approved by FERC in the form requested by Dominion and were subject to only minor modifications. Dominion has no significant rate matters pending before FERC at this time.

Environmental Matters

Dominion is subject to rising 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 affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

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

Environmental Protection and Monitoring Expenditures

Dominion incurred approximately $116 million, $94 million, and $78 million of expenses (including depreciation) during 2001, 2000, and 1999, respectively, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $126 million in 2002. In addition, capital expenditures related to environmental controls were $221 million, $214 million, and $84 million for 2001, 2000, and 1999, respectively. The amount estimated for 2002 for these expenditures is $321 million.

Clean Air Act Compliance

The Clean Air Act requires Dominion to reduce its emissions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X), which are gaseous by-products of fossil fuel combustion, and to obtain operating permits for all major emissions-emitting facilities. Permit applications have been submitted for Dominion’s affected facilities. The Clean Air Act’s SO₂ reduction program is based on the issuance of a limited number of SO₂ emission allowances, each of which may be used as a permit to emit one ton of SO₂ into the atmosphere or may be sold to a third party. Evaluation and planning of future projects to comply with SO₂ and NO_X limitations are ongoing and will be influenced by changes in the regulatory environment, availability of SO₂ allowances, various state and federal SO₂ and NO_X control programs, and emission control technology.

In response to NO_X reduction requirements mandated by the Environmental Protection Agency (EPA) for states in which it operates, Dominion plans to install NO_X reduction equipment at its affected coal-fired generating facilities at an estimated capital cost of approximately $650 million over the next several years.

In the near future, the Bush Administration and the United States Congress may consider various “multi-pollutant” legislative proposals that would require fossil-fuel fired generating units to comply with more stringent pollution control standards for NO_X, SO₂ and mercury. Many of the proposals would rely upon flexible cap and trade programs for compliance and would exempt covered facilities from other Clean Air Act requirements. All of the proposals would phase-in the emission reduction requirements under a variety of timeframes, up to 16 years. Dominion’s management cannot predict whether any of these proposals will pass this year or in the future. However, if more stringent emissions standards are ultimately imposed on Dominion’s generating units, new, perhaps significant, expenditures could be required.

During 2000, Virginia Power received a Notice of Violation from the EPA alleging that it 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 Virginia Power alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. Virginia Power also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Management believes that Virginia Power has obtained the necessary permits for its generating facilities. Virginia Power 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 Virginia Power’s coal-fired generating stations in Virginia and West Virginia. Dominion had already committed to a substantial portion of the $1.2 billion expenditures for SO₂ and NO_X emissions controls. The negotiations over the terms of a binding settlement have expanded beyond the basic agreement in principle and are ongoing.

Global Climate Change

        In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions. However, the Protocol will not become binding unless approved by the United States Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol but will work to establish new “voluntary” approaches to achieve reductions of greenhouse gas emissions. However, the United States Congress may consider legislation that would implement mandatory reductions of greenhouse gas emissions. The cost of compliance with the Protocol or similar mandatory greenhouse gas reduction obligations could be significant. Given the uncertainties of future action by the federal government on this issue, Dominion cannot predict the likely future impact on its operations at this time.

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Accounting Matters

Recently Issued Accounting Standards

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS Nos. 141, Business Combinations, 142, Goodwill and Other Intangible Assets, 143, Accounting for Asset Retirement Obligations, and 144, Accounting for the Impairment or Disposal of Long-Lived Assets. See Note 4 to the Consolidated Financial Statements for a discussion of the impact of adopting these new standards.

Restructuring Charges

After completing the transition period for fully integrating CNG into Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations in the fourth quarter of 2001. The objective of this review was to identify any activities or resources that were no longer necessary since the end of the transition period. As a result, restructuring charges of $105 million were recognized in the fourth quarter of 2001 for items such as employee severance and other termination benefits and cancellation or modification of leases to eliminate office space no longer needed. See Note 7 to the Consolidated Financial Statements. Dominion’s 2001 and 2000 restructuring plans should reduce future annualized operating costs by approximately $33 million and $102 million, respectively, that would otherwise have been incurred.

Business Opportunities and Other Operations

Independent Power Production Operations

Dominion’s focus in its power generation business is to acquire and develop additional power generation in the MAIN-to-Maine region. The region begins at the Mid-America Interconnected Network (MAIN) that includes electric service territories of the upper Midwest and is home to Dominion’s Kincaid and Elwood generating facilities. The target region extends east to Virginia Power’s service territory and north to New England, where Dominion operates Millstone. Dominion is benefiting from the CNG acquisition, as it is developing natural gas-fired power generation facilities along its natural gas pipeline system. Dominion is in various stages of development for new natural gas-fired power generation facilities throughout the MAIN-to-Maine region with estimated completion dates from 2002 to 2004. Dominion is striving to grow a balanced portfolio of generation assets, while maintaining fuel and regional diversity throughout the MAIN-to-Maine region.

Exploration and Production Operations

Dominion continues to focus on increasing earnings from gas and oil properties primarily through acquisition and development activities, exploration, and operating efficiencies. The acquisition of Louis Dreyfus represents the addition of significant, long-lived natural gas reserves located in several onshore United States regions serving northeast markets. This addition also provides significant new development drilling opportunities, complementing Dominion’s existing development and exploration activities.

Additionally, Dominion will seek opportunities to enhance the value of its reserves through the convergence of its gas and electric products and optimization of its gas storage facilities. Continued use of new and emerging production, prospecting and drilling technologies, when applied to sound business practices developed over time in gas and oil operations, should help improve operational efficiencies, as well as minimize finding, developing and lifting costs.

Effect of Changes in Commodity Prices

Dominion’s operations are impacted by changes in energy commodity prices. To the extent that energy commodities are sold by one of Dominion’s utilities with cost-of-service rate regulation, such commodity costs are generally recovered through rates. Market price changes impact Dominion’s revenue from natural gas and oil production and from commodity sales through unregulated subsidiaries. Dominion has established an enterprise risk management function to reduce such price risk exposures.

Nuclear Relicensing

Dominion filed applications for 20-year life-extensions for the North Anna and Surry units in May 2001 with the Nuclear Regulatory Commission (NRC). The NRC has accepted and is reviewing the applications. Over the next two years, the NRC will perform site visits and review the applications in detail.

        Dominion has also performed an internal assessment on the probability of a successful license renewal application for both of its operating Millstone units. Based on this assessment and other factors, Dominion has initiated preparations to apply for a 20-year extension of the licenses for both its operating Millstone units. Dominion expects to file a completed application based on NRC guidelines in 2004.

Nuclear Insurance

The Price Anderson Act (Act) expires in August 2002, but operating nuclear reactors would continue to be covered by the law, which would channel and cap claims if a nuclear accident should occur. The Act has been renewed three times since 1957, and Congress is currently holding hearings on reauthorizing the legislation.

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Pipeline Operations

Dominion plans to expand its natural gas transmission system with a $497 million, 263-mile interstate pipeline. The Greenbrier Pipeline will originate in Kanawha County, West Virginia, and extend through southwest Virginia into Granville County, North Carolina. Piedmont Natural Gas is a 33 percent owner in the pipeline project.

Telecommunications Operations

Dominion continues the expansion of its telecommunications operations as a competitive provider of services through its jointly-owned affiliate, Dominion Fiber Ventures, LLC. These services include providing facilities-based, high-bandwidth capacity throughout the eastern United States with particular concentration on under-served markets. Dominion continues building its network through the acquisition of dark fiber capacity on existing third-party networks. The future growth of its network will occur through joint development projects on third-party rights of way.

Future Acquisitions

Because Dominion’s industry is rapidly changing, there are many opportunities for acquisitions of assets, as well as for business combinations. Dominion investigates any opportunity that may increase shareholder value and build on existing businesses. Dominion has participated in the past—and its security holders may assume that at any time Dominion may be participating—in bidding or other negotiations for such transactions. Such participation may or may not result in a transaction for Dominion. However, any such transaction that does take place may involve consideration in the form of cash, debt or equity securities. It may also involve payment of a premium over book or market values. Such transactions or payments could affect the market prices and rates for Dominion’s securities.

Market Rate Sensitive Instruments and Risk Management

Dominion’s financial instruments, derivative financial instruments and derivative commodity contracts are exposed to potential losses due to adverse changes in interest rates, commodity prices and equity security prices as described below. Interest rate risk generally is related to Dominion’s outstanding debt and financial services activities. Commodity price risk is present in Dominion’s electric operations, gas production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. Dominion uses derivative commodity contracts to manage price risk exposures for these operations. Dominion is exposed to equity price risk through various portfolios of equity securities.

Dominion’s sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10 percent unfavorable change in interest rates and commodity prices.

Commodity Price Risk—Trading Activities

As part of its strategy to market energy and to manage related risks, Dominion manages a portfolio of derivative commodity contracts held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. Dominion uses established policies and procedures to manage the risks associated with these price fluctuations and uses various commodity instruments, such as futures, forwards, swaps and options, to reduce risk by creating offsetting market positions. In addition, Dominion seeks to use its generation capacity, when not needed to serve customers in its service territory, to satisfy commitments to sell energy.

A hypothetical 10 percent unfavorable change in commodity prices would have resulted in a decrease of approximately $12 million and $3 million in the fair value of its commodity contracts held for trading purposes as of December 31, 2001 and 2000, respectively.

Commodity Price Risk—Non-Trading Activities

Dominion manages the price risk associated with purchases and sales of natural gas, oil and electricity by using derivative commodity instruments including futures, forwards, options and swaps.

For sensitivity analysis purposes, the fair value of Dominion’s non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange.

A hypothetical 10 percent unfavorable change in market prices of Dominion’s non-trading derivative commodity instruments would have resulted in a decrease in fair value of approximately $155 million and $56 million as of December 31, 2001 and December 31, 2000, respectively.

The impact of a change in energy commodity prices on Dominion’s non-trading derivative commodity instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are generally offset by recognition of the hedged transaction, such as revenue from sales.

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Interest Rate Risk

Dominion manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. Dominion also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. In addition, Dominion, through subsidiaries, retains ownership of mortgage investments, including subordinated bonds and interest-only residual assets retained at securitization of mortgage loans originated and purchased. For financial instruments outstanding at December 31, 2001, a hypothetical 10 percent increase in market interest rates would decrease annual earnings by approximately $10 million. A hypothetical 10 percent increase in market interest rates, as determined at December 31, 2000, would have resulted in a decrease in annual earnings of approximately $40 million.

Foreign Exchange Risk

Dominion’s Canadian natural gas and oil exploration and production activities are relatively self-contained within Canada. As a result, Dominion’s exposure to foreign currency exchange risk for these activities is limited primarily to the effects of translation adjustments that arise from including that operation in its consolidated financial statements. Since these translation adjustments do not impact cash flows, Dominion’s management monitors this exposure but believes it is not material. Although Dominion may purchase products and services denominated in foreign currencies for use in its non-Canadian operations and may use currency forward contracts to manage related risks, such commitments were not material at December 31, 2001 and 2000.

Equity Price Risk

Dominion is subject to equity price risk due to marketable equity securities held as investments and in trust funds. These marketable securities are reported on the balance sheet at fair value. The following table presents marketable equity securities held by Dominion by category at December 31, 2001 and 2000.

	2001				2000
	Cost		Fair Value		Cost		Fair Value
	(millions)
Marketable securities	$	127	$	121	$	134	$	118
Nuclear decommissioning trust investments		734		952		279		549

Risk Management Policies

Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the price risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Management believes, based on Dominion’s credit policies and the December 31, 2001 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. See Note 15 to the Consolidated Financial Statements for discussion of the effects of Enron’s bankruptcy on Dominion’s December 31, 2001 consolidated financial statements.

SELECTED CONSOLIDATED FINANCIAL DATA

	2001		2000		1999			1998		1997
	(millions, except per share amounts)
Operating revenue	$	10,558	$	9,246	$	5,520		$	6,081	$	7,263
Income before extraordinary item and cumulative effect of a change in accounting principle		544		415		552			548		412
Extraordinary item (net of income taxes of $197)		—		—		(255	)		—		—
Cumulative effect of a change in accounting principle (net of income taxes of $11)		—		21		—			—		—
Net income		544		436		297			548		412
Earnings per common share—basic		2.17		1.85		1.55			2.81		2.22
Earnings per common share—diluted		2.15		1.85		1.48			2.81		2.22
Total assets		34,369		29,297		17,782			17,549		20,184
Long-term debt, subsidiary preferred stock subject to mandatory redemption and preferred securities of subsidiary trusts		13,251		10,486		7,321			6,817		7,761
Dividends paid per share		2.58		2.58		2.58			2.58		2.58

50

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1    Nature of Operations

Dominion Resources, Inc. (Dominion) is a holding company headquartered in Richmond, Virginia. Its principal subsidiaries are Virginia Electric and Power Company (Virginia Power), Consolidated Natural Gas Company (CNG), and Dominion Energy, Inc. (DEI). Dominion and CNG are registered public utility holding companies under the Public Utility Holding Company Act of 1935 (1935 Act).

Virginia Power is a regulated public utility that generates, transmits, and distributes electricity within a 30,000-square-mile area in Virginia and northeastern North Carolina. Virginia Power sells electricity to approximately 2.1 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. Virginia Power has trading relationships beyond its retail service territory and buys and sells wholesale electricity and natural gas off-system.

CNG operates in all phases of the natural gas business. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania, and West Virginia. Its interstate gas transmission pipeline system serves each of its distribution subsidiaries, non-affiliated utilities and end use customers in the Midwest, Mid-Atlantic and Northeast. CNG’s exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore. CNG also provides a variety of energy marketing services and holds an equity investment in energy activities in Australia that is classified as held for sale.

DEI is an independent power producer and a natural gas and oil exploration and production company active in the U.S. and Canada.

Dominion has substantially exited the core operating businesses of Dominion Capital, Inc. (DCI) as required by the Securities and Exchange Commission (SEC) under the 1935 Act. DCI’s primary business was financial services including loan administration, commercial lending and residential mortgage lending. See Note 6.

In 2000, Dominion created a subsidiary service company under the 1935 Act that serves Dominion’s various subsidiaries. CNG also operated a service company during 2000. Effective January 1, 2001, Dominion combined the two service companies.

Dominion manages its daily operations along three primary operating segments: Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In addition, Dominion also reports the operations of DCI and its corporate and other operations as operating segments. Assets remain wholly owned by its legal subsidiaries. See Note 30.

The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion Resources, Inc.’s consolidated subsidiaries or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Note 2     Significant Accounting Policies

General

Dominion includes certain estimates and assumptions in preparing consolidated financial statements in accordance with 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 Dominion’s accounts after the elimination of intercompany transactions. Dominion follows the equity method of accounting for investments in partnerships and corporate joint ventures when Dominion is able to influence the financial and operating policies of the investee. For all other investments, the cost method is applied.

Certain amounts in the 2000 and 1999 consolidated financial statements have been reclassified to conform to the 2001 presentation.

Use of Fair Value Measurements

        Dominion 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, Dominion seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, Dominion 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, Dominion 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, Dominion 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

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENT—(Continued)

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.

Concentration of Credit Risk

Dominion engages in transactions for the purchase and sale of products and services with various companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Although this concentration could affect Dominion’s overall exposure to credit risk, management believes that Dominion is exposed to minimal risk. A significant portion of Dominion’s business is conducted with major companies in the energy industry. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Dominion maintains credit policies with respect to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Dominion 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 the December 31, 2001 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. See Note 15 for discussion of the effects of Enron’s bankruptcy on Dominion’s December 31, 2001 consolidated financial statements.

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. Operating revenue from energy trading activities includes realized commodity contract revenue, net of related cost of sales, and unrealized gains and losses resulting from marking to market those commodity contracts not yet settled. The primary types of sales and service activities reported as operating revenue include:

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services.

Regulated gas sales consist primarily of state-regulated retail natural gas sales.

Nonregulated electric sales consist primarily of sales of electricity from utility, independent power production and merchant nuclear plant resources at market-based rates, and net operating revenue from electric trading activities.

Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas sales, and net operating revenue from gas trading activities. Natural gas sold includes gas produced by Dominion as well as gas purchased from others.

Gas transportation and storage consists primarily of federally-regulated sales of gathering, transmission, distribution and storage services. Also included are gas distribution charges to retail customers opting for alternate suppliers.

Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by Dominion. Gas and oil production revenue is reported net of royalties.

Other revenue consists primarily of service fees associated with rate-regulated electric and gas distribution; sales of coal, brokered oil and other extracted products; gas and oil processing; capacity release; and interest and other income from financial services operations.

Electric Fuel, Purchased Energy and Purchased Gas—Deferred Costs

Where permitted by regulatory authorities, the differences between actual electric fuel, purchased energy and purchased gas expenses and the levels of recovery of such expenses in current rates are deferred and matched against recoveries in future rates. See Regulatory Assets and Liabilities below and Note 18.

Income Taxes

        Dominion and its subsidiaries file a consolidated federal income tax return. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (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 amortized over the service lives of the properties giving rise to the credits.

Stock-based Compensation

Dominion 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 as 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. This date is generally the date of grant. See Note 25.

52

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENT—(Continued)

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2001 and 2000, accounts payable included the net effect of checks outstanding but not yet presented for payment of $214 million and $171 million, respectively. For purposes of the consolidated statements of cash flows, Dominion considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a maturity of three months or less.

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 2001, 2000, and 1999, Dominion capitalized interest costs of $41 million, $30 million, and $30 million, respectively.

The cost of depreciable gas utility and transmission and electric transmission and distribution property retired and related cost of removal, less salvage, are charged to accumulated depreciation. For generation-related property, cost of removal is charged to expense as incurred. Dominion 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 useful service lives or, in the case of gas and oil producing properties, the unit-of-production method. Estimated useful lives of Dominion’s property, plant and equipment are as follows: generation 20 – 60 years, transmission 20 – 78 years, distribution 10 – 50 years, storage 20 – 78 years, and other 5 – 31 years. 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 2001, Dominion increased its estimate of the useful lives of its nuclear facilities by 20 years. This change in estimate was made in connection with the current and future filing of applications for relicensing with the Nuclear Regulatory Commission (NRC).

Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration, and development activities are capitalized. The principal limitation is that these capitalized amounts may not exceed the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves (the ceiling test). If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-country basis.

Depreciation of gas and oil producing properties is computed using the unit-of-production method. Under the full cost method of accounting, amortization is also accrued on estimated future costs to be incurred in developing proved gas and oil reserves, and on estimated dismantlement and abandonment costs net of projected salvage values. However, the costs of investments in unproved properties are excluded from amortization until it is determined whether proved reserves exist.

Impairment of Long-Lived Assets

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

Investment Securities

Dominion accounts for and classifies investments in marketable equity and debt securities in two categories. Debt and equity securities purchased and held with the intent of selling them in the current period are classified as trading securities and are reported at fair value with unrealized gains and losses included in earnings. All other debt and equity securities are classified as available-for-sale securities. These are reported at fair value with unrealized gains and losses reported as a component of accumulated other comprehensive income, net of tax.

Loans Receivable, Net

        Loans receivable are stated at their outstanding principal balance, net of the allowance for credit losses and any deferred fees or costs. Origination fees, net of certain direct origination costs, are deferred and recognized as an adjustment of the yield of the loan receivable. The allowance for credit losses is established through provisions for credit losses charged against income. Loans receivable deemed to be uncollectible are charged against the allowance for credit losses, and subsequent recoveries, if any, are credited to the allowance. At December 31, 2001 and 2000, the allowance for credit losses for loans receivable was $79 and $61 million, respectively.

Sale of Loans by Financial Services Businesses

Securitizations involve selling loans to an unconsolidated special purpose trust in exchange for cash and certain retained interests. Retained interests may include subordinated bonds

53

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENT—(Continued)

or other securities issued by the trust or interests in the loans sold. Cash proceeds are determined based on the difference between interest rates to be received on the loans sold and the interest rate to be paid to investors participating in the securitizations. The determination of cash proceeds is also affected by estimates of prepayments, credit losses, servicing costs, and non-refundable fees and premiums. Gains and losses realized on the sale of loans are recognized based on the difference between the carrying amount of the loans sold and the sum of the cash proceeds received and the fair value of interests retained in the securitization on the settlement date. Fair value is based on the present value of estimated cash flows, adjusted to reflect the effects of credit losses, prepayments and other factors appropriate in each securitization. Dominion securitized commercial loans receivable in collateralized loan obligation (CLO) and collateralized debt obligation (CDO) transactions. Retained interests in CLO and CDO transactions are reported as available for sale securities. In addition, Dominion securitized residential mortgage loans. Dominion classifies its retained interests from securitizations of mortgage loans as investment securities-trading.

Retained interests from the securitization of mortgage loans include interest-only strips which are recorded based on the net present value of projected cash flows, using management’s best estimates of key assumptions. These assumptions include credit losses, prepayment speeds, forward yield curves, and discount rates commensurate with the risks involved. Interest-only strips are amortized in proportion to the estimated income received. They are analyzed quarterly to determine whether prepayment experience, losses and changes in the interest rate environment have had an impact on the valuation. Expected cash flows of the underlying loans sold are reviewed based upon current economic conditions and the type of loans originated and are revised as necessary. See Notes 8 and 13 for more information about Dominion’s investments in retained interests, including the recognition of impairments in 2001 and 2000.

Derivatives

Dominion uses derivatives such as futures, swaps, forwards and options to manage the commodity, currency exchange and financial market risks of its business operations. Dominion also manages a portfolio of commodity contracts held for trading purposes as part of its strategy to market energy and to manage related risks. Effective January 1, 2001, upon adoption of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, derivatives are generally recognized on the consolidated balance sheets at fair value. See Note 15 for further discussion of Dominion’s use of derivatives 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 year ended December 31, 2001.

Prior to January 1, 2001, Dominion considered derivative instruments to be effective hedges when the item being hedged and the underlying financial or commodity instrument showed strong historical correlation. Dominion 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 earnings of 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.

Goodwill, Net

Goodwill arising from acquisitions completed before July 1, 2001 was amortized on a straight-line basis over periods up to 40 years. As of December 31, 2001 and 2000, Dominion had amortized $173 million and $83 million of goodwill, respectively. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, Dominion has not amortized goodwill arising from acquisitions initiated after June 30, 2001 and will cease amortization of all goodwill effective January 1, 2002. See Note 4 for further discussion of the adoption of SFAS 142 effective January 1, 2002. See Note 5 for discussion of Dominion’s acquisitions during 2001.

Regulatory Assets and Liabilities

Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate 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 9 and 18 for the impact of legislation on continued application of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, and additional information on regulatory assets and liabilities.

Amortization of Debt Issuance Costs

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

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 3    Accounting Change for Pension Costs

Effective January 1, 2000 and in connection with Dominion’s acquisition of CNG, Dominion 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. Dominion 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.

The $21 million cumulative effect of the change on prior years (net of income taxes of $11 million) is included in income for the year ended December 31, 2000. The effect of the change on 2000 was to increase income before extraordinary item and cumulative effect of a change in accounting principle by $11 million ($0.05 per share-basic and diluted) and net income by $32 million ($0.14 per share-basic and diluted).

Retroactive application of the new method, on a pro forma basis, would not have materially changed Dominion’s net income for 1999.

Note 4     Recently Issued Accounting Standards

Business Combinations and Goodwill

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS Nos. 141, Business Combinations, and 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 141 also includes guidance on the initial recognition and measurement of goodwill and other intangible assets arising from business combinations initiated after June 30, 2001. SFAS No. 142 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.

Dominion will adopt SFAS No. 142 effective January 1, 2002. The discontinuance of goodwill amortization under SFAS No. 142 is expected to result in an increase in net income of $95 million in 2002. Dominion will test goodwill for impairment using an annual two-step process described in SFAS No. 142. The first step is a screen for potential impairment, while the second step measures the amount of the impairment, if any. Dominion will perform the first step of the required impairment tests of goodwill as of January 1, 2002 before the end of the second quarter of 2002. The standard requires that if impairment were determined to exist under that test, it would be reflected as the cumulative effect of a change in accounting principle. Dominion has not yet determined the effect these tests may have on its earnings or financial position.

Asset Retirement Obligations

In 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. Dominion will adopt the standard effective January 1, 2003.

Dominion has identified retirement obligations associated with the decommissioning of its nuclear generation facilities and certain dismantlement and restoration activities for its gas and oil wells. However, Dominion has not yet performed a complete assessment of possible retirement obligations associated with other electric and gas utility property. Dominion has not yet determined the financial impact of adopting the new standard.

Also, under the new standard, the realized and unrealized earnings of external trusts available for funding decommissioning activities at Dominion’s utility nuclear plants will be recorded in other income and other comprehensive income, as appropriate. Currently, Dominion records these trusts’ earnings in other income with an offsetting charge to expense, also recorded in other income, associated with the accretion of the decommissioning liability. See Note 16. Upon adoption of the new standard, Dominion will discontinue its practice of accruing, as part of depreciation expense, amounts associated with the future costs of removal for its gas and electric utility and gas and oil exploration and production assets. However, Dominion may continue its practice of accruing for such costs subject to cost-of-service utility rate regulation even when an asset removal obligation does not exist but would do so through the recognition of regulatory assets and liabilities, as appropriate.

Impairment or Disposal of Long-Lived Assets

In 2001, FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. Dominion will apply the provisions of this standard prospectively beginning January 1, 2002 and does not expect the adoption to have a material impact on its results of operations or financial condition.

55

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 5     Acquisitions

Louis Dreyfus Natural Gas Corp. (Louis Dreyfus)

On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus, a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. The results of Louis Dreyfus have been included in the consolidated financial statements since that date. Dominion’s proven gas and oil reserves increased approximately 60 percent as a result of the acquisition of Louis Dreyfus.

Dominion recognized goodwill in the acquisition to reflect the value attributable to: the complementary nature of the Louis Dreyfus assets in relation to Dominion’s growth strategy for its integrated energy businesses; Louis Dreyfus’ experienced exploration and production technical personnel; and potential operational efficiencies from the consolidation of Louis Dreyfus’ operations with Dominion’s existing exploration and production operations. By providing Dominion with a presence in additional large natural gas basins and increasing its holdings in certain basins in which it already operates, management believes that the acquisition results in a more balanced portfolio of producing properties, a more stable production profile and a larger platform for future growth. Dominion has not yet completed the assignment of goodwill associated with the Louis Dreyfus acquisition to its operating segments. In addition, the goodwill is not deductible for income tax purposes.

The aggregate purchase price was $1.8 billion, which consisted of approximately 14 million shares of Dominion common stock valued at $881 million and $902 million in cash. The value of the common stock issued was determined based on the average market price of common shares over the two-day period before and after the terms of the acquisition were agreed to and announced. In addition, Dominion issued approximately 675,000 stock options to employees of Louis Dreyfus in exchange for outstanding Louis Dreyfus options with a fair value on the date of grant of approximately $13 million.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	At November 1, 2001
	(millions)
Current assets	$	89
Property, plant and equipment		2,387
Deferred charges and other assets		43
Goodwill		519
Total Assets		3,038
Current liabilities		167
Long-term debt		1,426	*
Deferred credits and other liabilities		551
Total liabilities assumed		2,144
Net assets acquired	$	894

* Long-term debt includes approximately $1.1 billion of debt issued by CNG and preferred securities issued through an affiliated trust to finance the cash portion of the acquisition and refinance certain Louis Dreyfus debt.

Dominion is in the process of evaluating and measuring certain liabilities assumed in the acquisition; thus, the allocation of the purchase price is subject to refinement. Potential adjustments are not expected to be material. In accordance with SFAS No. 142, no goodwill amortization was recorded during 2001. See Note 4.

Millstone Power Station

        On March 31, 2001, Dominion acquired Millstone Power Station (Millstone), a nuclear power station located in Waterford, Connecticut and accounted for the acquisition under the purchase method of accounting. The results of Millstone have been included in the consolidated financial statements since that date. The acquisition includes a 100% ownership interest in Unit 1 and Unit 2 and a 93.47% ownership interest in Unit 3 for a total of 1,954 megawatts of generating capacity. Unit 1 is being decommissioned and is no longer in service. Dominion acquired the decommissioning trusts for the three units that were fully funded to the regulatory minimum at closing. See Note 16.

The aggregate purchase price was $1.3 billion in cash; representing approximately $1.2 billion for plant assets and $105 million for nuclear fuel. Dominion recorded $302 million of goodwill representing the excess of the purchase price over amounts allocated to Millstone’s assets acquired and liabilities assumed. Through December 31, 2001, Dominion amortized $6 million of goodwill based on the straight-line method and 40 years. See Note 4.

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CNG

On January 28, 2000, Dominion acquired all of the outstanding shares of CNG and accounted for the acquisition under the purchase method of accounting. The results of CNG have been included in the consolidated financial statements since that date.

The aggregate purchase price was $6.4 billion, consisting of approximately 87 million shares of Dominion common stock valued at $3.5 billion and approximately $2.9 billion in cash. Dominion recorded $3.5 billion of goodwill representing the excess of the purchase price over the fair value of CNG’s operations not subject to cost-based rate regulation and the historical carrying value of CNG’s operations subject to cost-of-service rate regulation. Through December 31, 2001, Dominion amortized $165 million of goodwill based on the straight-line method and 40 years. See Note 4.

The initial purchase price allocation included estimated values for amounts expected to be realized from the sale of Virginia Natural Gas (VNG) and CNG International, which were classified as net assets held for sale. Dominion sold VNG and CNG International’s Argentine investments in 2000. See Note 6. At December 31, 2001 the unsold portion of CNG International included primarily its equity investment in Australian energy activities.

Unaudited Pro Forma Results

The following unaudited pro forma combined results of operations for the years ended December 31, 2001 and 2000 have been prepared assuming the acquisition of Millstone and Louis Dreyfus had occurred at the beginning of each period. The pro forma adjustment for Millstone in 2001 reflects the effect of scheduled outages during the first quarter of 2001. The pro forma results are provided for information only. The results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the indicated date, nor are they necessarily indicative of future results of operations of the combined businesses.

			Unaudited
	As Reported		Millstone Acquisition			Louis Dreyfus Acquisition		Pro Forma Combined Results
	(Millions, except per share amounts)
Year ended December 31,
2001
Operating revenue	$	10,558	$	85		$	554	$	11,197
Income before cumulative effect of a change in accounting principle		544		(62	)		155		637
Net income		544		(62	)		155		637
Earnings Per Share—Basic
Income before cumulative effect of a change in accounting principle	$	2.17						$	2.41
Net income	$	2.17						$	2.41
Average shares of common stock		250.2					14.3		264.5
Earnings Per Share—Diluted
Income before cumulative effect of a change in accounting principle	$	2.15						$	2.39
Net income	$	2.15						$	2.39
Average shares of common stock		252.5					14.5		267.0
2000
Operating revenue	$	9,246	$	499		$	474	$	10,219
Income before cumulative effect of a change in accounting principle		415		10			71		496
Net income		436		10			71		517
Earnings Per Share—Basic
Income before cumulative effect of a change in accounting principle	$	1.76						$	1.99
Net income	$	1.85						$	2.07
Average shares of common stock		235.2					14.3		249.5
Earnings Per Share—Diluted
Income before cumulative effect of a change in accounting principle	$	1.76						$	1.98
Net income	$	1.85						$	2.07
Average shares of common stock		235.9					14.4		250.3

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 6     Divestitures

As of December 31, 2001, Dominion had substantially completed its strategy to exit the core operating businesses of DCI as required by the SEC under the 1935 Act. See Note 8 for charges recognized in connection with the DCI exit strategies. In 2000, Dominion sold $600 million of commercial loans and transferred $223 million of outstanding commercial loan commitments. As discussed in Note 13, Dominion securitized a substantial portion of the remainder of its financial subsidiaries’ commercial loans in CLO and CDO transactions in 2000 and 2001. As of December 31, 2001, Dominion held commercial and other loans receivable of $106 million, net of allowances for loan losses, and $268 million of CLO and CDO-related retained interests. At December 31, 2000, Dominion held CLO and CDO-related retained interests of $159 million.

In 2001, Dominion sold Saxon Capital and recognized an after-tax loss of $25 million. Under the terms of the sale, Dominion received $116 million in cash, a $25 million note and a non-controlling equity interest that was subsequently sold for $25 million. In addition, Dominion retained approximately $300 million in retained interests related to prior mortgage loan securitizations. Dominion held $269 million and $347 million of retained interests from mortgage loan securitizations at December 31, 2001 and 2000, respectively.

In 2000, Dominion completed the sales of VNG and CNG International’s Argentine assets for $678 million. As these entities were classified as net assets held for sale, the sales did not result in any gain or loss. Also in 2000, Dominion completed the sale of its interest in Corby Power Limited for $78 million, resulting in an after-tax gain of $13 million.

During 1999 and 2000, Dominion sold its interests in generation capacity located in Latin America for $405 million. Dominion recognized an impairment loss of $21 million, after taxes, associated with these investments in 1999.

Note 7     Restructuring and Acquisition-Related Activities

2001 Restructuring Costs

In the fourth quarter of 2001, after completing the transition period for fully integrating Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations. The objective of this review was to identify any activities or resources which were no longer necessary when the post-CNG acquisition transition period had ended. As a result, Dominion recognized $105 million of restructuring costs which included employee severance and termination benefits and the abandonment of leased office space no longer needed. In addition, restructuring charges included approximately $46 million related to departing employees for modifications of stock options, special termination benefits and losses related to the settlement of the related nonqualified pension obligation and plan curtailment attributable to reductions in expected future years of service of plan participants. See Notes 25 and 26.

Under the restructuring plan, Dominion identified approximately 340 salaried positions to be eliminated and recorded $42 million in employee severance-related costs. As of December 31, 2001, 12 positions had been eliminated. Severance payments were based on the individual’s base salary and years of service at the time of termination.

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

	(millions)
Severance and related costs	$	42
Nonqualified plan benefits, settlement and other costs		46
Lease termination and restructuring		13
Other, net		4
Total restructuring costs		105
Severance liability at December 31, 2001(1)		42
Lease termination liability at December 31, 2001	$	10

(1) Amount paid during the fourth quarter of 2001 was not material.

2000 Restructuring and Acquisition-Related Activities

During 2000, Dominion incurred charges associated with the divestiture of certain businesses and the implementation of a restructuring plan for the operations of Dominion and its subsidiaries. The divestitures and restructuring plans were driven by certain requirements associated with the CNG acquisition and a focus on operations in the region that begins at the Mid-America Interconnected Network (MAIN) and extends north-eastward through Maine (MAIN-to-Maine). The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP) and a transition plan to consolidate operations after the CNG acquisition.

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For the year ended December 31, 2000, Dominion recorded $460 million of restructuring and acquisition-related costs, including exiting certain businesses of DCI, as follows:

	(millions)
Severance and related costs	$	70
Commodity contract losses		55
Information technology related costs		35
Lease termination and restructuring		14
DCI exit strategies (see Note 8)		172
ERP benefit costs (see Note 26)		114
Curtailment gains (see Note 26)		(26	)
Other, net		26
Total	$	460

At December 31, 2001, the remaining severance liability of $3 million represented amounts payable to employees terminated under Dominion’s 2000 restructuring plan. The change in the liability for severance and related benefit costs is presented below:

	(millions)
Balance at December 31, 2000	$	29
Amounts paid		(24	)
Revision of estimates		(2	)
Balance at December 31, 2001	$	3

Employee Severance Programs—Through December 31, 2001, 750 salaried positions had been eliminated and $65 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. In addition, severance payments were provided to employees at DCI who were terminated as part of Dominion’s strategy to exit certain businesses of DCI.

Change in Risk Management Strategy—During the first quarter of 2000, Dominion created an enterprise risk management group with responsibility for managing Dominion’s aggregate energy portfolio, including the related commodity price risk, across its consolidated operations. In connection with this change in risk management strategy, management evaluated CNG’s hedging strategy in relation to Dominion’s combined operations and designated CNG’s portfolio of derivative contracts that existed on January 28, 2000, as held for purposes other than hedging for accounting purposes. This action required a change to mark-to-market accounting and resulted in $55 million of losses recognized in the first quarter of 2000 before Dominion had either financially settled the contracts or had entered into offsetting contracts.

Other—Restructuring and other acquisition-related costs included amounts paid to employees to retain their services during the post-acquisition transition period, amounts payable under certain employee contracts and information technology systems and operations integration costs. The information technology costs included excess amortization expense attributable to shortening the useful lives of capitalized software being impacted by systems integration and related conversion costs. Dominion also incurred lease termination and restructuring costs as a result of the consolidation of operations.

Note 8     Impairment Losses—DCI Operations

In 2001, Dominion recognized impairment losses of $281 million on various investments at DCI and reported the losses in other operations and maintenance expenses. These charges, after-tax, reduced 2001 net income by $183 million. In 2000, Dominion recognized impairment losses of $291 million, of which $172 million was determined to be attributable to Dominion’s DCI exit strategy and were included in restructuring and other acquisition-related costs. The remaining $119 million of impairment charges were related to normal operations of DCI and are included in other operations and maintenance expenses. See Notes 6, 7, and 13. These charges, after-tax, reduced 2000 net income by $186 million for 2000. The 2001 and 2000 impairments are reflected in the Corporate and Other operating segment. See Note 30.

The table below presents a summary of the impairments losses recorded in 2001 and 2000:

	2001		2000
	(millions)
Investment in:
Retained interests—mortgage securitizations	$	21	$	106
Retained interests—CLO/CDO securitizations		81		—
Loans receivable		94		36
Venture capital and other equity investments		64		46
Investment in First Source		—		49
Real-estate projects and other		21		54
Total	$	281	$	291

Retained Interests—Mortgage, CLO and CDO Securitizations

As part of routine quarterly reviews of its retained interests in mortgage, CLO and CDO securitizations during the fourth quarter of 2001, Dominion considered the following: historical performance of its securitized pools; recent prepayment and credit loss experience of loans in those pools; other industry data; and economic factors prevailing in the U.S. economy, particularly conditions brought about by the September 11, 2001 events and the mortgage interest rate environment at that time. In light of recent actual credit loss experience and actual prepayment activity of certain mortgage and commercial loans in the securitization trusts, Dominion increased its credit loss and prepayment speed assumptions used to estimate the fair value of its retained interests in mortgage, CLO and CDO securitizations. With these changes in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

estimates, Dominion recognized a write-down of the carrying values of its retained interests in mortgage and CLO/CDO securi-tizations of $21 million and $81 million, respectively, during the fourth quarter of 2001. See Note 13 for significant credit loss, prepayment and discount rate assumptions.

Loans and Other Investments

The other impairments and loss provisions reflect Dominion’s current estimate of net realizable values considering the dramatically weakened economy and increasing instances of bankruptcies, defaults, and major restructurings that significantly diminished investment values in the fourth quarter of 2001. Dominion’s valuation methodologies and assumptions vary by investment and include cash flow analysis, signed contracts, independent third-party appraisals, and, in certain cases, liquidation value.

Note 9     Extraordinary Item

In 1999, legislation was passed that established a detailed plan to restructure the electric utility industry in Virginia. The legislation’s deregulation of generation was an event that required discontinuation of SFAS No. 71 for Dominion’s generation operations in 1999. Dominion’s transmission and distribution operations continue to meet the criteria for recognition of regulatory assets and liabilities as defined by SFAS No. 71. In addition, the cost of fuel used in electric generation continues to be subject to deferral accounting.

In order to measure the amount of regulatory assets to be written off upon discontinuance of SFAS No. 71, Dominion evaluated the estimated recovery of regulatory assets through its Virginia jurisdictional rates during the transition period ending July 2007. Generation-related assets and liabilities that will not be recovered through the transition period rates were written off in 1999, resulting in an after-tax charge to earnings of $255 million. See Note 18 for discussion of net regulatory assets at December 31, 2001. The $255 million charge also included the write-off of approximately $38 million, after-tax, of deferred investment tax credits and approximately $18 million, after-tax, of other generation-related assets. A corresponding regulatory asset of $23 million was established representing the amount expected to be recovered during the transition period related to these assets.

The events that caused the discontinuance of SFAS No. 71 for generation-related operations, also required a review of generation assets for impairment. This review was based on estimates of possible future market prices, load growth, competition and other assumptions. It also included the effects of nuclear decommissioning and other currently identified environmental expenditures. Based on those analyses, no plant write-downs were appropriate at that time.

Dominion also reviewed its long-term power purchase contracts for potential loss in accordance with SFAS No. 5, Accounting for Contingencies, and Accounting Research Bulletin No. 43, Chapter 4, Inventory Pricing. Based on projections of possible future market prices for wholesale electricity as of March 31, 1999, the results of the analysis indicated no loss recognition was appropriate at that time. Other projections of possible future market prices indicated a possible loss of $500 million. In the absence of the transition period rates provided by the legislation, the potential loss exposure would have been approximately $3.2 billion at March 31, 1999.

Significant estimates were required in recording the effect of the deregulation legislation, including the resulting impact on the fair value determination of generating facilities and estimated purchases under long-term power purchase contracts. Such projections were highly dependent on future customer load projections, generating unit availability, the timing and type of future capacity additions in Dominion’s market area and future market prices for fuel and electricity.

Note 10     Income Taxes

Income before provision for income taxes, classified by source of income, before minority interests, was as follows:

	Year Ended December 31,
	2001		2000		1999
	(millions)
U.S.	$	816	$	552	$	797
Non-U.S.		98		48		32
Total	$	914	$	600	$	829

Details of income tax expense were as follows:

	Year Ended December 31,
	2001			2000			1999
	(millions)
Current
Federal	$	104		$	255		$	187
State		62			20			18
Non-U.S.		3			—			4
Total current		169			275			209
Deferred
Federal		151			(111	)		66
State		24			16			—
Non-U.S.		45			22			(1	)
Total deferred		220			(73	)		65
Amortization of deferred
investment tax credits—net		(19	)		(19	)		(15	)
Total income tax expense	$	370		$	183		$	259

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

	Year Ended December 31,
	2001(1)		2000		1999
U.S. statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Utility plant differences	0.5		0.8		0.3
Preferred dividends	0.9		2.1		1.6
Amortization of investment tax credits	(1.7	)	(2.3	)	(1.8	)
Nonconventional fuel credit	(4.6	)	(7.1	)	(4.4	)
Other benefits and taxes related to foreign operations	3.0		(2.7	)	(0.2	)
State taxes, net of federal benefit	5.9		4.3		1.5
Goodwill amortization	3.3		4.4		—
Employee pension and other benefits	(1.4	)	(1.4	)	—
Other, net	(0.5	)	(2.6	)	(0.8	)
Effective tax rate	40.4	%	30.5	%	31.2	%

(1) Dominion’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, higher effective rates associated with foreign earnings and higher pretax income in relation to nonconventional fuel tax credits realized.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Dominion’s net deferred taxes consist of the following:

	At December 31,
	2001		2000
	(millions)
Deferred income tax assets:
Deferred investment tax credits	$	43	$	55
Other		122		231
Total deferred income tax assets		165		286
Deferred income tax liabilities:
Depreciation method and plant basis differences		1,911		1,994
Income taxes recoverable through future rates		19		20
Partnership basis differences		113		141
Investee earnings reported in different tax periods		143		—
Postretirement and pension benefits		464		481
Intangible drilling costs		520		269
Geological, geophysical and other exploration differences		170		157
Deferred state income taxes		221		37
Other comprehensive income		182		—
Other		113		—
Total deferred income tax liabilities		3,856		3,099
Total net deferred income tax liabilities(1)	$	3,691	$	2,813

(1) For 2001, includes $121 million of current deferred tax assets reported in other current assets.

        At December 31, 2001, Dominion had U.S. federal net operating loss carryforwards of $139 million that will expire beginning in 2003. These amounts resulted from the acquisition of subsidiaries. Dominion also has net operating loss carryforwards for state income tax purposes which have been reserved.

Note 11    Earnings Per Share

The following table presents Dominion’s basic and diluted earnings per share (EPS) calculation:

	Year Ended December 31,
	2001		2000		1999
	(millions, except per share amounts)
Basic
Income before extraordinary item and cumulative effect of a change in accounting principle	$	544	$	415	$	552
Average shares of common stock outstanding—basic		250.2		235.2		191.4
Basic EPS	$	2.17	$	1.76	$	2.88
Diluted
Income before extraordinary item and cumulative effect of a change in accounting principle	$	544	$	415	$	552
Income effect of total return equity swap, net of taxes		—		—		(12	)
Income before extraordinary item and cumulative effect of a change in accounting principle—diluted	$	544	$	415	$	540
Average shares of common stock outstanding		250.2		235.2		191.4
Net effect of dilutive stock options		2.3		0.7		—
Average shares of common stock outstanding—diluted		252.5		235.9		191.4
Diluted EPS	$	2.15	$	1.76	$	2.81
Average anti-dilutive shares excluded from the EPS calculation		6		5		—

Note 12    Gas Stored

At December 31, 2001 and 2000, stored gas inventory used in local gas distribution operations was valued at $84 million and $41 million, respectively, under the LIFO method. Based on the average price of gas purchased during 2001, the current cost of replacing the inventory of gas stored—current portion exceeded the amount stated on a LIFO basis by approximately $308 million. At December 31, 2001 and 2000, the stored gas inventory of certain of Dominion’s nonregulated gas operations was valued at $98 million and $34 million, respectively, using primarily the weighted average cost method.

A portion of gas in underground storage used as a pressure base and for operational balancing was included in property, plant and equipment in the amount of $124 million and $126 million at December 31, 2001 and 2000, respectively. Property, plant and equipment also reflects a reduction for volumes temporarily withdrawn from storage and valued at replacement costs of $25 million and $211 million as of December 31, 2001 and 2000, respectively.

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Note 13    Securitization of Financial Assets

Securitization of Commercial Loans

During 2001 and 2000, Dominion sold commercial loans in CLO and CDO-related securitization transactions. In those transactions, Dominion retained servicing responsibilities and interests which are subordinate to those of investors participating in the securitizations. The investors and the securitization trusts have no recourse to Dominion’s other assets for failure of debtors to pay when due. The majority of the loans sold are variable rate loans. As a result, changes in interest rates will not cause a material change in the performance of the loan portfolios. Dominion receives annual servicing fees and rights to future cash flows after the investors in the securitization trusts have received their contracted return. The estimated fair value of Dominion’s retained interests at the time of the 2001 securitization was based on expected cash flow recoveries from the loan portfolios, assuming a credit loss rate of 2 percent, and a discount rate of 10 percent. The following table summarizes key information about the securitizations of commercial loans during 2001 and 2000:

	Loans Securitized		Cash Proceeds		Retained Interests		Annual Servicing Fees
	(millions)
2001	$	423	$	227	$	196	38 basis points of the outstanding balance
2000	$	646	$	570	$	76	38 basis points of the outstanding balance

Securitization of Residential Mortgages

During 2001, 2000 and 1999, Dominion sold residential mortgage loans in securitization transactions. In each of those securi-tizations, Dominion retained servicing responsibilities and interests in the mortgage loans sold which are subordinate to the interests of investors participating in the securitizations. The investors and the securitization trusts have no recourse to Dominion’s other assets for failure of debtors to pay when due. Dominion’s retained interests in mortgage securitizations were based on rights to annual servicing fees approximating 50 basis points of the outstanding balance and rights to future cash flows from the performance of the loan portfolios after the investors in the securitization trust have received their contracted return. In addition, Dominion continues to receive future cash flows from prepayment penalties on mortgage loans that prepay during the contractual penalty period. The value of the retained interests is subject to credit, prepayment and interest rate risks related to the mortgage loans sold. In 2001, 2000 and 1999, Dominion recognized pretax gains of $21 million, $85 million and $107 million, respectively, on the securitization of residential mortgage loans.

The following table presents weighted-average rates (per annum) for key economic assumptions used in measuring the retained interests from securitizations completed during 2001:

	Retained Interests— Mortgage Loans(1)		Retained Interests— CLO
Prepayment speed	(2	)	N/A
Weighted-average life (in years)	3.28		2.2
Expected credit losses	3.22	%	2	%
Residual cash flows discounted at	17	%	10	%

(1) Dominion sold all of its servicing rights as part of its sale of Saxon Mortgage in 2001.

(2) Fixed rate loans ramp up to 26.25 Constant Prepayment Rate (CPR) over 16 months. Adjustable rate loans ramp up to 67.275 CPR over 16 months, ramping down to 41.4 CPR over 12 months. Second liens ramp up to 36.75 CPR over 16 months, ramping down to 23.1 CPR over 26 months. Two-year hybrid loans ramp up to 33.12 CPR over 14 months; ramping up to 67.275 CPR in month 25; ramping up to 32.085 CPR over 7 months. Three-year hybrid loans ramp up to 33.12 CPR over 14 months; ramping up to 62.1 CPR in month 37; ramping down to 32.085 CPR over 7 months.

        As a result of an acceleration of prepayments and loan defaults, Dominion recognized a loss of $21 million in the fourth quarter of 2001 on its retained interests from securitizations of mortgage loans. During the first half of 2000, in response to changes in market conditions, Dominion increased the discount rate used to value the interest-only strips included in its retained interests from 12 percent to 17 percent, and recognized a loss of $106 million. In connection with the DCI exit strategy, Dominion reclassified its retained interests from securitizations of mortgage loans from available-for-sale to trading.

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Activity for the retained interests from securitizations of mortgage loans, including interest-only strips and servicing rights, and the CLO and CDO retained interests is summarized as follows:

	Interest-Only Strips— Mortgage Loans(1)			Servicing Rights— Mortgage Loans			Retained Interest— CLO			Retained Interest— CDO
	(millions)
Balance at January 1, 1999	$	282		$	35			—		$	24
Retained from securitization		169			16			—			34
Amortization		(7	)		(12	)		—			—
Cash received		(79	)		—			—			—
Fair value adjustment		(18	)		—			—			—
Balance at December 31, 1999		347			39			—			58
Retained from securitization		99			18		$	76			30
Amortization		(16	)		(7	)		—			—
Cash received		(51	)		—			—			(4	)
Gain on trading securities		25			—			—			—
Fair value adjustment		(102	)		(5	)		—			(1	)
Balance at December 31, 2000		302			45			76			83
Retained from securitization		33			—			196			—
Amortization		(9	)		—			—			—
Cash received		(55	)		—			—			(6	)
Gain on trading securities		19			—			—			—
Servicing rights sold(2)		—			(45	)		—			—
Fair value adjustment		(21	)		—			(67	)		(14	)
Balance at December 31, 2001	$	269		$	—		$	205		$	63

(1) Includes prepayment penalties.

(2) Dominion sold all of its servicing rights as part of its sale of Saxon Mortgage in 2001.

Presented below are the fair values of Dominion’s retained interests and related key economic assumptions as of December 31, 2001 and the sensitivity of the retained interests’ fair value to adverse changes of 10 percent and 20 percent in those assumptions:

	Retained Interest— Mortgage Loans			Retained Interest— CLO			Retained Interest— CDO
	(millions, except percentages)
Carrying amount/fair value	$	261		$	205		$	63
Weighted-average life (in years)		2.69			2.2			3.8
Prepayment speed assumption (annual rate)		(1	)		N/A			N/A
Impact on fair value of 10% adverse change	$	(15	)		N/A			N/A
Impact on fair value of 20% adverse change	$	(30	)		N/A			N/A
Expected credit losses (annual rate)		3.32	%		4	%(2)		2	%(3)
Impact on fair value of 10% adverse change	$	(8	)	$	(7	)	$	(1	)
Impact on fair value of 20% adverse change	$	(15	)	$	(11	)	$	(3	)
Residual cash flows discount rate (annual)		17	%		10	%		16.9	%
Impact on fair value of 10% adverse change	$	(6	)	$	(12	)	$	(2	)
Impact on fair value of 20% adverse change	$	(15	)	$	(17	)	$	(4	)
Interest rates on variable and adjustable contracts		(4	)		N/A			N/A
Impact on fair value of 10% adverse change		—			N/A			N/A
Impact on fair value of 20% adverse change	$	(3	)		N/A			N/A

(1) Fixed rate loans ramp up to 25 CPR over 16 months. Adjustable rate loans ramp up to 65 CPR over 16 months, ramping down to 40 CPR over 12 months. Second liens ramp up to 35 CPR over 16 months, ramping down to 22 CPR over 26 months. Two-year hybrid loans ramp up to 32 CPR over 14 months; ramping up to 65 CPR in month 25; ramping to 31 CPR over 7 months. Three-year hybrid loans ramp up to 32 CPR over 14 months; ramping up to 60 CPR in month 37; ramping down to 31 CPR over 7 months.

(2) Defaults occur at the beginning of each period. They are applied on constant percentage to the period’s beginning collateral balance.

(3) Assets rated Caa1 and lower are defaulted using a CDR vector based upon Moody’s Cumulative Default Rates for Caa1-C securities. A 2 percent per annum CDR is applied to remaining assets with ongoing recoveries of 40 percent and 80 percent on bonds and loans, respectively.

(4) Based on the full forward 1-month LIBOR, 6-month LIBOR or 1-year CMT through January 1, 2005 based on the variable component of the variable rate contracts.

These sensitivities are hypothetical. Changes in fair value based on a 10 percent variation in assumptions generally cannot be extrapolated because the relationship of the change in assumption to the change in fair value may not be linear. Also, the effect of a variation in a particular assumption on the fair value of the retained interests was calculated without changing any other assumption. In reality, changes in one factor may result in changes in another factor which might magnify or

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counteract the sensitivities. For example, increases in market interest rates may result in lower prepayments and increased credit losses.

Note 14    Investment Securities

Dominion holds marketable debt and equity securities classified as available-for-sale. Those investments are reported as available-for-sale securities on the consolidated balance sheets. In addition, the Millstone nuclear decommissioning trust funds holds marketable debt and equity securities classified as available-for-sale. See Note 16 for additional disclosure of Dominion’s accounting for the Millstone decommissioning trusts. Available-for-sale securities as of December 31, 2001 and 2000 are summarized below:

	Fair Value		Total Unrealized Gains Included in AOCI		Total Unrealized Losses Included in AOCI
	(millions)
2001
Equity securities	$	551	$	11	$	4
Debt securities		684		1		16
Total	$	1,235	$	12	$	20
2000
Equity securities	$	118	$	1	$	15
Debt securities		174		—		1
Total	$	292	$	1	$	16

Debt securities backed by mortgages and loans do not have stated contractual maturities as borrowers have the right to call or repay obligations with or without call or prepayment penalties. At December 31, 2001, these debt securities totaled $277 million. The fair value of all other debt securities at December 31, 2001 by contractual maturity are as follows:

	(millions)
Due in one year or less	$	52
Due after one year through five years		81
Due after five years through ten years		119
Due after ten years		155
Total	$	407

Proceeds from sales of available-for-sale securities were $484 million, $3 million and $35 million for 2001, 2000, and 1999 respectively. Realized gains associated with sales of available-for-sale securities totaled $18 million, $1 million and $5 million for 2001, 2000 and 1999, respectively. Realized losses on those sales totaled $4 million, $6 million, and $1 million for 2001, 2000 and 1999, respectively. The increase in proceeds and realized gains relates primarily to activity in the Millstone nuclear decommissioning trusts. The cost of these securities was determined on a specific identification basis. For 2001, 2000 and 1999, net unrealized holding gains on trading securities increased earnings by $21 million, $6 million and $1 million, respectively. Net unrealized holding gains for 2000 included a $14 million loss relating to the reclassification of certain available-for-sale securities to the trading category.

Note 15    Derivatives, Hedge Accounting and Energy Trading Activities

Adoption of SFAS No. 133

        Dominion adopted SFAS No. 133 on January 1, 2001 and recorded an after-tax charge to accumulated other comprehensive income (AOCI) of $183 million, net of taxes of $106 million. Dominion reclassified approximately $183 million, net of taxes, AOCI associated with the January 1, 2001 transition adjustment to earnings during 2001. The effect of the amounts reclassified from AOCI to earnings was generally offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Risk Management Policy

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Dominion designates a substantial portion of derivatives held for purposes other than trading as fair value or cash flow hedges. A significant portion of Dominion’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas, oil and other commodities. Dominion also uses cash flow hedge strategies to hedge the variability in foreign exchange rates and variable interest rates on long-term debt. In its cash flow hedges, Dominion uses the derivative instruments discussed in the preceding paragraphs. Dominion also engages in fair value hedges by using natural gas swaps, futures and options to mitigate the fixed price exposure inherent in its firm commodity commitments. In addition, Dominion has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt. Certain 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. 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, Dominion 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. Dominion 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. Further, for derivatives that have ceased to be highly effective hedges, Dominion discontinues hedge accounting prospectively.

For fair value hedge transactions in which Dominion 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 Dominion 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 as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion 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, 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 operation 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.

2001 Derivatives and Hedge Accounting Results

Dominion recognized a pre-tax net gain of $2 million for hedge ineffectiveness during 2001. This amount includes a pre-tax gain of $3 million related to cash flow hedges and a loss of $1 million related to fair value hedges. In addition, Dominion recognized a net pre-tax loss of $45 million during 2001, representing the change in time value excluded from the measurement of effectiveness for options designated as cash flow hedges subsequent to January 1, 2001.

Approximately $209 million of net gains in AOCI at December 31, 2001 is expected to be reclassified to earnings during 2002. The actual amounts that will be reclassified to earnings in 2002 will vary from this amount as a result of changes in market prices. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies. As of December 31, 2001, Dominion is hedging its exposure to the variability in future cash flows for forecasted transactions over periods of one to seven years.

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Energy Trading Activities

Dominion’s energy trading contracts are reported at fair value, with corresponding changes in value recognized immediately in earnings. Net gains and losses associated with Dominion’s commodity trading activities are accounted for net of related cost of sales in nonregulated electric sales and nonregulated gas sales. 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 2001, 2000 and 1999 follows:

	Gains		Losses			Total
			(millions)
2001
Contract settlements	$	5,208	$	(5,209	)	$	(1	)
Unrealized gains and losses		1,378		(1,238	)		140
Operating revenue		6,586		(6,447	)		139
2000
Contract settlements		2,773		(2,692	)		81
Unrealized gains and losses		1,236		(1,211	)		25
Operating revenue		4,009		(3,903	)		106
1999
Contract settlements	2,577		(2,481)			96
Unrealized gains and losses		114		(101	)		13
Operating revenue	$	2,691	$	(2,582	)	$	109

Enron Bankruptcy

On December 2, 2001, Enron Corp. and certain of its subsidiaries (collectively referred to as Enron) voluntarily filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Dominion is a party to various contracts with Enron that were initiated primarily for purposes of hedging anticipated purchases and sales of natural gas and for use in its energy trading operations. As a result of Enron’s bankruptcy filing, Dominion reexamined the estimated collectibility of its net accounts receivable balance from Enron and the valuation of its Enron commodity contracts carried at fair value on Dominion’s consolidated balance sheet at December 2, 2001. In reexamining the valuation of these assets, Dominion considered, among other factors, its contractual ability to exercise the right of setoff, the likelihood of continued performance by Enron under its contracts and its expectation regarding amounts to be realized upon potential future termination of its contracts by Dominion.

Based on management’s evaluation of these factors, Dominion recorded a pre-tax charge to earnings of approximately $151 million in the fourth quarter of 2001 related to its estimated Enron exposure. This charge is comprised of approximately $9 million for net credit exposure on past energy sales to Enron for which payment has not yet been received and approximately $142 million related to the impaired fair value of natural gas forward and swap contracts with Enron. Management believes that this charge substantially eliminates any further Enron-related earnings exposure. However, various contingencies, including developments in the Enron bankruptcy proceedings, may affect Dominion’s ultimate exposure to Enron.

Concurrent with the December 2, 2001 Enron bankruptcy filing, Dominion’s Enron derivatives designated as cash flow hedges of anticipated purchases and sales of natural gas no longer qualified for hedge accounting and, accordingly, were de-designated from their hedging relationships for accounting purposes.

Other

        In June 2001, the FASB cleared guidance that permits certain option-type contracts for the purchase or sale of electricity to qualify for the normal purchases and sales exception, if certain criteria are met. Qualifying contracts, for which Dominion elects and formally documents this exception, are not reported at fair value, as otherwise required by SFAS No. 133. In response to the June 2001 guidance and other guidance issued during the second quarter, Dominion reevaluated certain of its long-term power purchase contracts. Dominion determined that such contracts qualified under the guidance and thus designated them as normal purchases and sales. In late December 2001, the FASB issued revised guidance on this matter to be effective April 1, 2002. Dominion believes that its long-term power purchase contracts that are currently designated as normal purchases and normal sales will continue to qualify for the exception.

Future interpretations of SFAS No. 133 by the FASB or other standard-setting bodies could result in fair value accounting being required for certain contracts that are not currently being subjected to such requirements. Accordingly, future interpretations may impact Dominion’s ultimate application of the standard. However, if future SFAS No. 133 interpretive guidance results in additional contracts becoming subject to fair value accounting, Dominion would pursue hedging strategies to mitigate any potential future volatility in reported earnings.

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Note 16    Nuclear Operations

Dominion has a total of seven licensed nuclear reactors at its Surry and North Anna plants in Virginia and its Millstone plant in Connecticut. Surry and North Anna serve native load in Dominion’s regulated electric utility operations. Millstone is a nonregulated merchant plant. See Notes 5 and 17 regarding the acquisition of Millstone and other information regarding jointly-owned utility plants.

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 July 2007, amounts are being collected from ratepayers and placed in external trusts and invested to fund the expected costs of decommissioning the Surry and North Anna units. As part of its acquisition of Millstone, Dominion acquired the decommissioning trusts for the three units that were fully funded to the regulatory minimum as of the acquisition date. Currently, Dominion believes that the amounts available in the trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone units, without any additional contributions to the trusts.

Accounting for Decommissioning

Utility Nuclear Plants—In accordance with the accounting policy recognized by regulatory authorities having jurisdiction over its electric utility operations, Dominion 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 Dominion’s utility 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 the offsetting expense for decommissioning, are recorded as a component of other income (loss) as permitted by regulatory authorities.

The balance of investments held in external trusts for Surry and North Anna decommissioning as well as the accumulated provision for decommissioning at December 31, 2001 and 2000, was $858 million and $851 million, respectively.

Dominion collected $36 million from ratepayers in each of the years 2001, 2000 and 1999 and expensed like amounts as a component of depreciation. Dominion recognized net realized gains of $32 million, $20 million and $17 million for 2001, 2000, and 1999. Dominion recognized net unrealized losses of $61 million and $23 million, for 2001 and 2000, respectively; and net unrealized gains in 1999 of $60 million. Dominion recognized offsetting increases or decreases to its provision for decommissioning in amounts equal to net realized and unrealized gains or losses for each period.

Merchant Nuclear Plant—The external trusts that hold investments dedicated to funding the decommissioning of Dominion’s merchant nuclear plant are classified as “available for sale” and reported in the consolidated balance sheets at fair value. See Note 14. The balance of investments held in external trusts for Millstone decommissioning at December 31, 2001 was $839 million.

The accumulated provision for decommissioning, which is included in accumulated depreciation in the consolidated balance sheets, was recorded upon the acquisition of Millstone at its estimated fair value using discounted cash flows of expected costs to perform the decommissioning activities. The balance of the accumulated provision for Millstone decommissioning was $660 million at December 31, 2001.

The accretion of the provision for decommissioning is expensed as a component of depreciation and was $30 million for the year ended December 31, 2001. Dominion realized net gains on trust investments of $15 million in 2001 and recorded such gains in other income.

Expected Costs for Decommissioning

The total estimated cost to decommission Dominion’s seven nuclear units is $3.4 billion based upon site-specific studies completed in 1998 and 1999. Dominion expects to perform new cost studies in 2002. For all units except Millstone Unit 1, the current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when operating licenses expire. Millstone Unit 1 is not in service and will be monitored until decommissioning activities begin for the remaining Millstone units. The current operating licenses expire in the years detailed in the following table. However,

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Dominion filed a request with the NRC in 2001 for a 20-year life extension for the Surry and North Anna units and expects to file a similar request for the Millstone units in 2004. Dominion expects to decommission the Surry and North Anna units during the period 2032 to 2045 and the Millstone units during the period 2050 to 2055.

	Surry				North Anna				Millstone
	Unit 1		Unit 2		Unit 1		Unit 2		Unit 1			Unit 2		Unit 3		Total
	(millions)
NRC license expiration year		2012		2013		2018		2020		(1	)		2015		2025
Current cost estimate (1998 dollars)	$	411	$	413	$	401	$	387		—			—		—	$	1,612
Current cost estimate (1999 dollars)		—		—		—		—	$	631		$	500	$	618		1,749
Funds in external trusts at December 31, 2001		239		234		198		187		288			278		273		1,697
2001 contributions to external trusts		11		11		7		7		—			—		—		36

(1) Unit 1 is being decommissioned and was not in service.

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of the nuclear facilities. Dominion’s 2001 NRC minimum financial assurance amount, aggregated for the nuclear units, was $1.9 billion and will be satisfied by a combination of surety bonds and the funds being collected in the external trusts.

Insurance

The Price-Anderson Act limits the public liability of an owner of a nuclear power plant 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. Dominion 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, Dominion could be assessed up to $88 million for each of its seven 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 expires August 1, 2002, but operating nuclear reactors would continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation.

Dominion’s current level of property insurance coverage ($2.55 billion for North Anna, $2.55 billion for Surry and $2.75 billion for Millstone) 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. Dominion’s nuclear property insurance is provided by 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 $70 million. Based on the severity of the incident, the board of directors of Dominion’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion 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.

Dominion 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, Dominion 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 $29 million.

Old Dominion Electric Cooperative, a part owner of the North Anna Power Station, and Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation, part owners of Millstone’s Unit 3, are responsible for their share of the nuclear decommissioning obligations and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

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Note 17    Property, Plant and Equipment

Major classes of property, plant and equipment and their respective balances are:

	At December 31,
	2001		2000
	(millions)
Utility
Production	$	8,414	$	8,103
Transmission		3,165		3,085
Distribution		7,024		6,764
Storage		755		573
Plant under construction		587		562
Nuclear fuel		757		755
Other electric and gas		1,528		1,574
Total utility		22,230		21,416
Nonutility
Exploration and production properties:
Proved		7,303		5,210
Unproved		1,689		550
Independent power properties—nuclear		1,170		—
Independent power properties—other		381		358
Other		332		477
Total nonutility		10,875		6,595
Total property, plant and equipment	$	33,105	$	28,011

Costs of unproved properties capitalized under the full cost method of accounting that are excluded from amortization at December 31, 2001, and the years in which such excluded costs were incurred, follow:

	Incurred in Year Ended December 31,
	Total		2001		2000		Prior Years
	(millions)
Property acquisition costs	$	947	$	861	$	41	$	45
Exploration costs		120		80		40		—
Capitalized interest		27		13		14		—
Total	$	1,094	$	954	$	95	$	45

Amortization rates for capitalized costs under the full cost method of accounting for Dominion’s United States and Canadian cost centers were as follows:

	Year Ended December 31,
	2001		2000		1999
	(Per Mcf Equivalent)
United States cost center	$	1.13	$	1.13	$	0.75
Canadian cost center		0.78		0.92		0.80

Dominion’s proportionate share of jointly-owned utility plants at December 31, 2001 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		$	1,859		$	533
Accumulated depreciation		321			1,162			83
Nuclear fuel		—			314			—
Accumulated amortization of nuclear fuel		—			303			—
Construction work in progress		3			28			4

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 proportions as their respective ownership interest. Such operating costs are classified in the appropriate expense category in the consolidated statements of income.

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Note 18    Regulatory Assets and Liabilities

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. Dominion’s regulatory assets and liabilities included the following at December 31, 2001 and 2000:

	2001		2000
	(millions)
Regulatory assets
Unrecovered gas costs	$	9	$	263
Other postretirement benefit costs (1)		115		126
Income taxes recoverable through future rates (2)		179		164
Deferred cost of fuel used in electric generation		119		98
Cost of decommissioning DOE uranium
enrichment facilities (3)		42		49
Customer bad debts (4)		80		—
Other		39		60
Regulatory assets, net		574		497
Total regulatory assets		583		760
Regulatory liabilities
Amounts payable to customers		91		—
Estimated rate contingencies and refunds (5)		43		41
Total regulatory liabilities	$	134	$	41

(1) Costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect the new method of accounting and the cost related to the accrued benefit obligation recognized as part of Dominion’s accounting for its acquisition of CNG.

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

(3) Cost of decommissioning the Department of Energy’s uranium enrichment facilities, representing the unamortized portion of Dominion’s required contributions. Beginning in 1992, Dominion began making contributions over a 15-year period and collecting these costs in electric customers’ fuel rates.

(4) In 2001 the Public Utilities Commission of Ohio authorized the deferral of costs associated with certain uncollectible customer accounts not contemplated by current rates. Dominion expects recovery of such costs, which will be included in Dominion’s next base rate case.

(5) Estimated rate contingencies and refunds are associated with certain increases in prices by Dominion’s rate regulated utilities and other rate-making issues that are subject to final modification in regulatory proceedings.

The incurred costs underlying regulatory assets may represent past expenditures by Dominion’s rate regulated electric and gas operations or may represent the recognition of liabilities that ultimately will be settled at some future time. At December 31, 2001, approximately $130 million of Dominion’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of unrecovered gas costs, customer bad debts and a portion of deferred fuel costs. Unrecovered gas and deferred fuel costs are recovered within two years; recovery of these customer bad debts is expected to be addressed in the next base rate case.

Note 19    Short-Term Debt and Credit Agreements

        Dominion and its subsidiaries have credit agreements with various expiration dates and pay fees in lieu of compensating balances in connection with these agreements. These agreements provided for maximum borrowing capacity of $2.5 billion and $4.4 billion at December 31, 2001 and December 31, 2000, respectively. In 2000, $295 million was borrowed under these agreements. There were no borrowings as of December 31, 2001.

These credit agreements also supported $1.9 billion and $2.7 billion of commercial paper at December 31, 2001 and 2000, respectively. These borrowings were used primarily to fund working capital requirements, bridge financing of acquisitions and operational needs at Dominion and its subsidiaries. At December 31, 2000, a total of $250 million of the commercial paper was classified as long-term debt since a portion of the commercial paper was supported by credit agreements that had expiration dates extending beyond one year.

At December 31, 2001, Dominion had commercial paper programs with an aggregate amount of $2.05 billion supported by a $1.75 billion 364-day revolving credit facility and a $300 million multi-year facility. Dominion expects to renew these credit facilities after their maturities in the second quarter of 2002.

A summary of the amounts that are classified as short-term debt at December 31 follows:

	2001				2000
	Amount Outstanding		Weighted Average Interest Rate		Amount Outstanding		Weighted Average Interest Rate
	(millions except percentages)
Commercial paper	$	1,859	4.23	%	$	2,414	6.50	%
Term notes		—	—			823	7.02	%
Total	$	1,859			$	3,237

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Note 20    Long-Term Debt

	At December 31,
	2001			2000
	(millions)
First and Refunding Mortgage Bonds:
6.0% to 8.75%, due 2001 to 2025 (1)	$	2,121		$	2,321
Senior Subordinated Debt, 9.25%, due 2004		94			—
Senior and Medium-Term Notes:
Variable rates, due 2002 to 2012		690			470
5.375% to 9.85%, due 2001 to 2038 (2)		8,275			5,133
Commercial Paper (see Note 19)		—			250
Tax-Exempt Financings (3):
Variable rates, due 2007 to 2027		489			489
4.0% to 5.45%, due 2022 to 2031		110			60
Secured Revolving Lines of Credit:
Variable rates, due 2002 to 2004		—			297
Revolving Lines of Credit:
Variable rates, due 2001 to 2004 (4)		241			145
Term Note:
Variable rate, due 2002		675			900
Nonrecourse Debt:
Variable rates, due 2004 to 2009		40			59
4.49% to 12.5%, due 2001 to 2020 (4)		353			367
		13,088			10,491
Fair value hedge valuation (5)		43			—
Amount due within one year		(1,309	)		(336	)
Unamortized discount and premium, net		(25	)		(54	)
		11,797			10,101
Notes Payable—Affiliates (see Note 29):
6.0%, due 2005		175			—
Variable rates, due 2006		192			—
		367			—
Amount due within one year		(45	)		—
		322			—
Total long-term debt	$	12,119		$	10,101

(1) Substantially all of Virginia Power’s property is subject to the lien of the mortgage, securing its First and Refunding Mortgage Bonds (Mortgage Bonds). In 2001, Virginia Power retired $100 million of its 1993-E, 6% Mortgage Bonds and redeemed $100 million of its 1991-A, 8.75% Mortgage Bonds due April 1, 2021. In January 2002, Virginia Power called its $200 million, 6.75% 1997-A Mortgage Bonds due February 1, 2007 for redemption in February 2002 at a price of 102.74 plus accrued interest. In January 2002, Virginia Power issued $650 million of 5.375% Senior Notes (2002 Senior Notes) maturing in February 2007.

(2) In 2001, CNG redeemed the remaining $84 million of 8.75% Senior Notes due October 1, 2019. At the exercised option of holders, CNG will be required on October 15, 2006 to purchase the $150 million, 6.875% Senior Notes due October 15, 2026 at 100% of the principal amount plus accrued interest. In January 2002, Dominion Resources, Inc. issued $250 million of 3.875 percent medium-term notes due 2004.

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

(4) $76 million of variable rate debt under revolving lines of credit and $12 million of 6.34% to 6.5% nonrecourse debt were retired in 2001.

(5) Represents changes in fair value of certain fixed rate long-term debt associated with fair value hedging relationships, as described in Note 15.

Note:  Coupon rate for variable rate debt is a weighted average of the interest rates for 2001, ranging from 2.52% to 5.17%.

The scheduled principal payments of long-term debt at December 31, 2001 were as follows (in millions):

2002	2003	2004	2005	2006	Thereafter	Total
$1,354	$2,112	$1,459	$889	$1,445	$6,196	$13,455

Dominion’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions.

Note 21    Subsidiary Dividend Restrictions

The 1935 Act prohibits registered holding companies and their subsidiaries from paying dividends out of capital or unearned surplus except when they have received specific SEC authorization. In January 2002, Dominion filed an application with the SEC for relief from the restriction on paying dividends out of unearned surplus of the subsidiary into which Louis Dreyfus was merged. The request was for relief up to an amount equal to Louis Dreyfus’ retained earnings before the merger.

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate, if found not to be in the public interest. At December 31, 2001, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2001.

Note 22    Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

From 1995 through 2001, Dominion established five subsidiary capital trusts that sold trust preferred securities that represented preferred beneficial interests and 97 percent beneficial ownership in the assets held by the capital trusts. In exchange for the funds realized from the sale of the trust preferred securities and common securities that represent the remaining 3 percent beneficial ownership interest in the assets held by the capital trust, Dominion issued various junior subordinated debt instruments. The junior subordinated debt instruments constitute

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100 percent of each capital trust’s assets. The following table provides summary information about the capital trusts and junior subordinated debt instruments:

Date Established	Capital Trusts	Trust Preferred Securities			Common Securities
		(Millions)
August, 1995	Virginia Power Capital Trust I (1)	$	135		$	4
December, 1997	Dominion Resources Capital Trust I (2)		250			8
January, 2001	Dominion Resources Capital Trust II (3)		300			9
January, 2001	Dominion Resources Capital Trust III (4)		250			8
October, 2001	Dominion CNG Capital Trust I (5)		200			6
			1,135
	Unamortized discount		(3	)
	Total at December 31, 2001	$	1,132

Junior subordinated notes/debentures assets for each capital trust were as follows:

(1) $139 million—Virginia Power 8.05% Series A Notes due 9/30/2025—The maturity date, subject to certain conditions, may be extended for up to an additional 10 years from date of original maturity.

(2) $258 million—Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(3) $309 million—Dominion Resources, Inc. 8.4% Debentures due 1/30/2041.

(4) $258 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

(5) $206 million—CNG 7.8% Debentures due 10/31/2041.

Note 23    Preferred Stock

Dominion is authorized to issue up to 20 million shares of preferred stock. See Note 29 for a discussion of Dominion’s issuance of 665,000 shares of Series A Mandatorily Convertible Preferred Stock, liquidation preference $1,000 per share (Preferred Stock), to Piedmont Share Trust (Piedmont Trust). Dominion is the beneficial owner of the Piedmont Trust which is consolidated in the preparation of Dominion’s consolidated financial statements, thus eliminating the Preferred Stock.

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

During the fourth quarter of 2001, Virginia Power purchased and redeemed, at par, all shares of its January 1987 and June 1987 series of money market preferred stock for $125 million.

As of December 31, 2001 and 2000, there were no outstanding issues of Virginia Power preferred stock subject to mandatory redemption. Shown below are the series of Virginia Power preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2001.

	Issued and Outstanding Dividend 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)
MMP 10/88 (4)	750		100.00
MMP 6/89 (4)	750		100.00
MMP 9/92, Series A (4)	500		100.00
MMP 9/92, Series B (4)	500		100.00
Total	3,840

(1) Shares are presented in thousands.

(2) Through 7/31/03; amounts decline in steps thereafter to $100.00 after 7/31/13. (3) Through 8/31/03; amounts decline in steps thereafter to $100.00 after 8/31/13. (4) Money Market Preferred (MMP) dividend rates are variable and are set every 49 days via an auction process. The combined weighted average rates for all series outstanding during 2001, 2000, and 1999, including fees for broker/dealer agreements, were 4.32 percent, 5.71 percent and 4.82 percent, respectively.

Note 24    Common Stock

Dominion is authorized by its Board of Directors to repurchase up to $650 million of Dominion common stock outstanding. As of December 31, 2001, Dominion had repurchased approximately 11 million shares for $471 million. Dominion has not repurchased any shares since January 2000.

Immediately before the CNG merger in January 2000, Dominion concluded a first step transaction in which 33 million shares of Dominion common stock were exchanged for approximately $1.4 billion. Dominion also repurchased approximately 3.2 million shares of stock in 2000 through a total return swap facility at a cost of approximately $145 million. The transactions were independent of the general repurchase authority described above.

Note 25    Stock Compensation Plans

Dominion sponsors two stock plans that provide stock-based awards to directors, executives and other key employees. Under the plans, Dominion grants stock options and restricted stock awards that vest from three to five years, and in the case of options, have contractual terms that range from seven to 10 years. Forty million shares of common stock may be issued

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under the plans and 15 million of those are available for new grants as of December 31, 2001.

Dominion recognized compensation expense of $13 million, $8 million, and $2 million in 2001, 2000, and 1999, respectively, for the issuance of stock-based awards, primarily restricted stock. If compensation cost associated with the stock-based awards had been measured based on the fair market value of the options at the date of grant, 2001 net income, basic EPS, and diluted EPS would have been $520 million, $2.08 and $2.06, respectively; 2000 net income, basic EPS, and diluted EPS would have been $430 million, $1.82 and $1.82, respectively; and 1999 net income, basic EPS, and diluted EPS would have been $277 million, $1.45 and $1.38.

The adjacent table provides a summary of changes in amounts of Dominion stock options outstanding as of and for the years ended December 31, 2001, 2000, and 1999. In connection with the acquisition of Louis Dreyfus, employee stock options of Louis Dreyfus were converted into employee stock options of Dominion. Based on the conversion formula, certain converted stock options had exercise prices that either exceeded or were less than the market price of Dominion common stock on the date of grant. The fair value of all converted stock options were included in the purchase price of Louis Dreyfus, see Note 5. Generally, the exercise price of Dominion employee stock options equals the market price of Dominion common stock on the date of grant.

	Stock Options		Weighted- average Exercise Price			Weighted- average Fair Value
	(thousands)
Outstanding at December 31, 1998	2		$	29.49
Granted—1999	7,146		$	41.38		$	4.35	(2)
Exercised, cancelled and forfeited	(1	)	$	29.37
Outstanding at December 31, 1999	7,147		$	41.37
Exercisable at December 31, 1999	7,147		$	41.37
Granted—2000	5,389		$	43.87		$	6.86	(2)
Exercised, cancelled and forfeited	(2,205	)	$	40.07
Outstanding at December 31, 2000	10,331		$	41.77
Exercisable at December 31, 2000	6,967		$	41.51
Granted—2001	480	(1)	$	33.21	(1)	$	23.69	(1)
	11,471	(2)	$	61.20	(2)	$	11.24	(2)
	194	(3)	$	62.27	(3)	$	9.43	(3)
Exercised, cancelled and forfeited	(1,484	)	$	41.23
Outstanding at December 31, 2001	20,992		$	52.90
Exercisable at December 31, 2001	7,955		$	42.68

(1), (2), (3)  The exercise price for these stock options (1) was less than, (2) equaled, or (3) exceeded the market price on the date of grant.

The following table provides certain information about stock options outstanding as of December 31, 2001:

	Options Outstanding				Options Exercisable
Exercise Price	Shares Outstanding	Weighted-average Remaining Contractual Life	Weighted-average Exercise Price		Shares Exercisable	Weighted-average Exercise Price
	(thousands)				(thousands)
$ 0-$19.99	13	7.0	$	19.15	13	$	19.15
$20-$30.99	186	5.8	$	25.76	186	$	25.76
$31-$40.99	266	7.5	$	38.42	165	$	38.16
$41-$50.99	8,537	7.5	$	42.40	7,070	$	41.87
$51-$60.99	9,546	7.1	$	59.91	216	$	58.83
$61-$69	2,444	9.3	$	66.00	305	$	63.90
Total	20,992	7.5	$	52.90	7,955	$	42.68

The fair value of the options was estimated on the dates of grant using the Black-Scholes option pricing model with the following weighed-average assumptions for 2001, 2000, and 1999, respectively: expected dividend yield of 4.22 percent, 5.22 percent, 6.25 percent; expected volatility of 22.19 percent, 21.54 percent, 15.14 percent; contractual life of 10 years (all periods); risk free interest rate of 5.15 percent, 5.18 percent, 6.52 percent; and expected lives of six years (all periods).

In the fourth quarter of 2001, Dominion modified the stock options of certain executives in connection with the restructuring activities discussed in Note 7. The options were modified to extend the period, after separation from employment, that the executives may exercise their options but not beyond the options’ original contractual lives. Dominion remeasured compensation expense associated with these options on the modification date and recognized a pre-tax charge of $18 million included in restructuring charges in 2001.

During 2001, 2000, and 1999, respectively, Dominion awarded 332,884 shares, 169,886 shares and 24,758 shares of restricted stock with weighted-average fair values of $63.49, $41.88 and $43.51.

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Note 26    Employee Benefit Plans

Dominion and its subsidiaries provide certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion and its subsidiaries reserve the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion and its subsidiaries maintain qualified noncontributory defined benefit retirement plans covering virtually all employees. Retirement benefits are based primarily on years of service, age, and compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The pension program also provides benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. Certain of these nonqualified plans are funded through contributions to a grantor trust.

Dominion and its subsidiaries provide retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date, and years of service.

In 2000, Dominion offered an early retirement program (ERP). The ERP provided up to three additional years of age and three additional years of employee service for benefit formula purposes, subject to age and service maximums under Dominion and its subsidiaries’ postretirement medical and pension plans. Certain employees who satisfied certain minimum age and years of service requirements were eligible under the ERP. The effect of the ERP on Dominion’s pension plan and post retirement benefit expenses was $81 million and $33 million, respectively. These expenses were offset, in part, by curtailment gains of approximately $20 million and $6 million from pension plans and other postretirement benefit plans, respectively, attributable to reductions in expected future years of service as a result of ERP participation and involuntary employee terminations.

In November 2001, Dominion eliminated certain senior management positions. Dominion paid these individuals special termination benefits and accelerated the payment of benefits under Dominion’s nonqualified pension plans. Dominion recognized special termination benefits expense of $15 million, a loss of $7 million related to the settlement of the related non-qualified pension obligation and a curtailment loss of $2 million.

In addition, effective January 1, 2000, Dominion adopted a change in the method of calculating the market-related value of pension plan assets. The change was reported as a change in accounting principle. See Note 3.

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The following tables summarize the changes in Dominion’s pension and other postretirement benefit plan obligations and plan assets for each of the years ended December 31, 2001 and 2000, and a statement of the plans’ funded status as of December 31, 2001 and 2000:

	Year Ended December 31,
	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
	(millions)
Expected benefit obligation at beginning of year	$	2,304		$	1,097		$	799		$	401
Acquisition of CNG		—			1,002			—			297
Acquisition of Millstone		66			—			21			—
Actual benefit obligation at beginning of year		2,370			2,099			820			698
Additional benefit obligation due to change in control		—			10			—			—
Service cost		71			65			39			30
Interest cost		173			161			63			52
Benefits paid		(153	)		(141	)		(51	)		(43	)
Actuarial loss during the year		114			112			107			82
ERP benefit costs		—			81			—			33
Change in benefit obligation		(5	)		—			—			—
Special termination benefits		15			—			—			—
Sale of VNG		—			(45	)		—			(20	)
Change in APBO due to curtailment		—			(20	)		—			(6	)
Plan amendments		8			(18	)		18			(27	)
Expected benefit obligation at end of year		2,593			2,304			996			799
Fair value of plan assets at beginning of year		3,557			1,305			417			272
Acquisition of CNG		—			2,332			—			128
Actual return on plan assets		(91	)		64			(11	)		3
Contributions		39			34			65			45
Benefits paid from plan assets		(153	)		(141	)		(25	)		(20	)
Sale of VNG		—			(37	)		—			(11	)
Fair value of plan assets at end of year		3,352			3,557			446			417
Funded status		759			1,253			(550	)		(382	)
Unrecognized net actuarial loss		698			177			164			13
Unrecognized prior service cost		3			(1	)		11			(7	)
Unrecognized net transition (asset) obligation		(5	)		(9	)		115			125
Prepaid (accrued) benefit cost		1,455			1,420			(260	)		(251	)
Amounts recognized in the consolidated balance sheets at December 31:
Prepaid benefit cost		1,511			1,455			—			—
Accrued benefit liability		(89	)		(77	)		(260	)		(251	)
Intangible asset		12			14			—			—
Accumulated other comprehensive income		21			28			—			—
Net amount recognized	$	1,455		$	1,420		$	(260	)	$	(251	)

        Dominion has nonqualified pension and supplemental pension plans which do not have ‘‘plan assets’’ as defined by generally accepted accounting principles. The total projected benefit obligation for these plans was $103 million and $93 million at December 31, 2001 and 2000, respectively, and is included in the table above. The additional minimum liability recognized relating to these plans was $33 million and $42 million at December 31, 2001 and 2000. The related intangible asset recognized as of those dates amounted to $12 million and $14 million, respectively. Adjustments of the additional minimum liability and intangible asset due to changes in assumptions or the financial status of these plans resulted in a pre-tax credit to other comprehensive income of $7 million for 2001 and a pre-tax charge to other comprehensive income of $24 million for 2000.

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The components of the provision for net periodic benefit cost were as follows:

	Year Ended December 31,
	2001			2000			1999
	(millions)
Pension Benefits
Service cost	$	71		$	65		$	40
Interest cost		173			161			76
Expected return on plan assets		(331	)		(298	)		(93	)
Recognized loss		3			6			—
Amortization of prior service cost		2			3			—
Amortization of transition obligation		(4	)		(4	)		—
Curtailment gains		—			(20	)		—
ERP benefit costs		—			81			—
Settlement loss		7			—			—
Special termination benefits		15			—			—
Curtailment loss		2			—			—
Net periodic benefit cost	$	(62	)	$	(6	)	$	23
Other Postretirement Benefits
Service cost	$	40		$	30		$	17
Interest cost		63			52			28
Expected return on plan assets		(32	)		(31	)		(20	)
Amortization of prior service cost		(1	)		—			—
Amortization of transition obligation		10			13			12
Curtailment gains		—			(6	)		—
ERP benefit costs		—			33			—
Net amortization and deferral		—			(2	)		—
Net periodic benefit cost	$	80		$	89		$	37

Significant assumptions used in determining net periodic pension cost, the projected benefit obligation, and postretirement benefit obligations were:

	Pension Benefits				Other Benefits
	2001		2000		2001		2000
Discount rates	7.25	%	7.50	%	7.25	%	7.50	%
Expected return on plan assets	9.50	%	9.50	%	7.88	%	6.50	%
Rate of increase for compensation	4.60	%	5.00	%	4.60	%	5.00	%
Medical cost trend rate					9.00	%	9.00	%
					Decreasing to 4.75% in 2006 and years thereafter

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Other Postretirement Benefits

	One percentage point increase		One percentage point decrease
	(millions)
Effect on total service and interest costs components for 2001	$	15	$	(12	)
Effect on postretirement benefit obligation at December 31, 2001	$	118	$	(97	)

In addition, Dominion sponsors defined contribution thrift-type savings plans. During 2001, 2000 and 1999, Dominion recognized $27 million, $30 million and $29 million, respectively, as contributions to these plans.

The funds collected for other postretirement benefits in regulated utility rates, in excess of other postretirement benefits actually paid during the year, are contributed to external benefit trusts.

Note 27    Commitments and Contingencies

As the result of issues generated in the course of daily business, Dominion and its subsidiaries are 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 an adverse material effect on its operations or the financial position, liquidity or results of operations.

Utility Rate Regulation

Dominion’s retail gas distribution companies are subject to price regulation in the states of Ohio, Pennsylvania and West Virginia. Dominion’s gas transmission business is subject to federal rate regulation.

Dominion currently faces competition as a result of utility industry deregulation. Under Virginia’s electric utility industry deregulation legislation, Dominion’s base rates will remain capped until July 2007 unless Dominion petitions for, and the Virginia Commission approves, an earlier termination any time after January 1, 2004. The capped rates will provide recovery of certain generation-related costs. Dominion 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, 2001, Dominion’s exposure to potentially stranded costs was comprised of the following: long-term purchased power contracts that could ultimately be determined to be above market (see Power Purchase Contracts below); 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 16 and 26).

Capital Expenditures

Dominion has made substantial commitments in connection with its capital expenditures program. Those expenditures are estimated to total approximately $2.4 billion, $3.1 billion and $3.2 for 2002, 2003 and 2004 respectively. Purchases of nuclear fuel are included in Fuel Purchase Commitments below. Dominion expects that these expenditures will be met through

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cash flow from operations and through a combination of sales of securities and short-term borrowings.

Power Purchase Contracts

Dominion has entered into contracts for the long-term purchases of capacity and energy from other utilities, qualifying facilities and independent power producers. As of December 31, 2001, Dominion had 43 non-utility purchase contracts with a combined dependable summer capacity of 3,770 megawatts. The table below reflects Dominion’s minimum commitments as of December 31, 2001 under these contracts.

	Commitment
	Capacity		Other
	(millions)
2002	$	688	$	33
2003		635		20
2004		634		17
2005		627		12
2006		613		12
Later years		5,856		128
Total	$	9,053	$	222
Present value of the total	$	5,094	$	116

In addition to the minimum commitments in the table above, under some of these contracts Dominion may purchase, at its option, energy as needed. Purchased power expenditures, subject to cost of service rate regulation, (including economy, emergency, limited term, short-term and long-term purchases) for the years 2001, 2000 and 1999 were $1.1 billion, $1.1 billion, and $1.2 billion, respectively.

In 2001, Dominion completed the purchase of three generating facilities and the termination of seven long-term power purchase contracts with non-utility generators (NUG). Dominion recorded an after-tax charge of $136 million in connection with the purchase and termination of long-term power purchase contracts. Cash payments related to the purchase of 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 contracts which were terminated and resulted in a charge included in operation and maintenance expense.

See Note 9 for additional disclosure regarding the evaluation of Dominion’s potential exposure under its long-term power purchase commitments.

Fuel Purchase Commitments

Dominion enters into long-term purchase commitments for fuel used in electric generation and natural gas for purposes other than trading. Estimated payments under these commitments for the next five years are as follows: 2002—$549 million; 2003—$321 million; 2004—$212 million; 2005—$241 million; 2006—$143 million and years beyond 2006—$288 million. These purchase commitments include those required for regulated operations. Dominion recovers the costs of those purchases through regulated rates. The natural gas purchase commitments of Dominion’s field services operations are also included, net of related sales commitments. In addition, Dominion has committed to purchase certain volumes of natural gas at market index prices determined in the period the natural gas is delivered. These transactions have been designated as normal purchases and sales under SFAS No. 133.

Natural Gas Pipeline and Storage Capacity Commitments

Dominion enters into long-term commitments for the purchase of natural gas pipeline and storage for purposes other than trading. Estimated payments under these commitments for the next five years are as follows: 2002—$43 million; 2003—$38 million; 2004—$23 million; 2005—$6 million; and 2006—$1 million. There were no commitments beyond 2006.

Leases

Dominion leases various facilities, vehicles, aircraft, and equipment under both operating and capital leases. Future minimum lease payments under operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2001 are: 2002—$70 million; 2003—$95 million; 2004—$100 million; 2005—$91 million; 2006—$72 million; and years after 2006—$166 million. Rental expense included in other operations and maintenance expense was $63 million, $107 million, and $31 million for 2001, 2000, and 1999, respectively.

As of December 31, 2001, Dominion, through certain subsidiaries, has entered into agreements with special purpose entities (Lessors) in order to finance and lease several new power generation projects, as well as its corporate headquarters and aircraft. The Lessors have an aggregate financing commitment from equity and debt participants (Investors) of $2.2 billion, of which $817 million has been used for total project costs to date. Dominion, in its role as construction agent for the Lessors, is responsible for completing construction by a specified date. In the event a project is terminated before completion, Dominion has the option to either purchase the project for 100 percent of project costs or terminate the project and make a payment to the Lessor of approximately but no more than 89.9 percent of project costs. Upon completion of each individual project, Dominion has use of the project assets subject to an operating lease. Dominion’s lease payments to the Lessors are sufficient to provide a return to the Investors. At the end of each individual project’s lease term, Dominion may renew the lease at negotiated amounts based on project costs and current market conditions, subject to Investors’ approval; purchase the project at its original construction cost; or sell the project, on behalf of the Lessor, to

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an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Investors, Dominion may be required to make a payment to the Lessor, ranging from 81 percent to 85 percent of the project cost depending on the individual project and applicable agreement. Dominion has guaranteed a portion of the obligations of its subsidiaries to the Lessors during the construction and post-construction periods. These transactions do not contain any type of credit rating or stock price trigger events.

As noted above, as of December 31, 2001, amounts subject to these agreements totaled $817 million, and the total amount, upon completion of all projects, is projected to be approximately $2.2 billion. The projects are accounted for as operating leases for financial accounting purposes. Accordingly, neither the project assets nor related obligations are reported on Dominion’s balance sheets. The future minimum lease payments described above include annual payments of approximately $6 million associated with these projects representing minimum payments under leases for which the leased assets are currently in use. Projects currently under development are scheduled for completion during the period 2002 through 2004. Annual lease payments for the projects are estimated to be $33 million in 2002, increasing to $133 million by 2004.

Energy Trading

Subsidiaries of Dominion 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 15 for a discussion of Dominion’s energy trading activities and risk management policies.

Environmental Matters

Dominion is subject to rising 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, Dominion 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, Dominion’s results of operations will decrease. After that date, Dominion may seek recovery from customers through utility rates of only those environmental costs related to transmission and distribution operations.

Superfund Sites —In 1987, the Environmental Protection Agency (EPA) identified Dominion 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 $153 million. Dominion’s proportionate share of the total cost is expected to be in the range of $2 million to $3 million, based upon 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. Dominion 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, Dominion has determined that it is probable that the PRPs will fully pay their share of the costs. Dominion generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2001, any pending or possible claims were not recognized as an asset or offset against such obligations.

Other EPA Matters —In 1999, the Department of Justice (DOJ) notified Dominion of an alleged noncompliance with the EPA’s oil spill prevention, control and countermeasures (SPCC) plans and facility response plan (FRP) requirements at one of Dominion’s power stations. In December 2001, Dominion reached a settlement agreement with the DOJ and EPA covering all alleged noncompliance issues. The settlement will not have a material impact on Dominion’s financial condition or results of operations. Dominion also identified matters at other power stations that the EPA might view as not in compliance with the SPCC and FRP requirements and reported these matters to the EPA. Dominion also reported its plans for correcting the issues. Dominion does not believe that the settlement of these self-reported matters, if any, will be material to its results of operations or financial conditions.

        During 2000, Virginia Power 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 Virginia Power alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. Virginia Power also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. Management believes that Virginia Power has obtained the necessary permits for its generating facilities. Virginia Power 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

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Jersey and New York, and a 12-year, $1.2 billion capital investment program for environmental improvements at Virginia Power’s coal-fired generating stations in Virginia and West Virginia. Dominion 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, 2001, Dominion has recorded, on a discounted basis, $18 million for the civil penalty and environmental projects.

Other—Before being acquired by Dominion, Louis Dreyfus was one of numerous defendants in several lawsuits pending in the Texas 93rd Judicial District Court in Hildago County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus and facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits as a result of the plume. Although the results of litigation are inherently unpredictable, Dominion does not expect the ultimate outcome of the case to have a material adverse impact on its financial position or results of operations.

Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, Dominion 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 by Dominion’s contract with the DOE. Dominion will continue to safely manage its spent fuel until accepted by the DOE.

Retrospective Premium Assessments

Under several of Dominion’s nuclear insurance policies, Dominion 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 16.

Related Party Transactions

For a discussion of Dominion’s commitments to related parties, see Note 29.

Note 28    Fair Value of Financial Instruments

Substantially all of Dominion’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. Dominion 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 were as follows:

	2001				2000
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(millions)
Long-term debt(1)	$	13,455	$	13,725	$	10,491	$	10,555
Preferred securities of subsidiary trusts(2)(3)	$	1,132	$	1,154		385	$	383
Loan commitments(4)		—		—		—	$	230
Unrecognized financial instruments(5):
Interest rate swaps(6)		—		—		—	$	17
Swaps, collars and options–hedging(7)		—		—		—	$	(277	)

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

(2) Fair value is based on market quotations.

(3) The 2001 carrying value of $1,132 million represents principal outstanding of $1,135 million less an unamortized discount of $3 million.

(4) The fair value of commitments was estimated using the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements and the present creditworthiness of the counterparties.

(5) Upon adoption of SFAS No. 133 on January 1, 2001, all derivatives are reported at fair value. The fair value of unrecognized financial instruments at December 31, 2000 was recognized as a component of the January 1, 2001 SFAS No. 133 transition adjustment. See Note 15 for discussion of Dominion’s derivatives and hedge accounting activities.

(6) Fair value was based upon the present value of all estimated net future cash flows, taking into account current interest rates and the creditworthiness of the swap counterparties.

(7) Fair value reflected Dominion’s best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.

Note 29    Related Party Transactions

Dominion Fibers Ventures, LLC

In December 2000, Dominion formed Dominion Fiber Ventures, LLC (DFV). In 2001, Dominion contributed all of the outstanding shares of its telecommunications subsidiary, Dominion Telecom, Inc. (DTI), with an equity value of $110 million, in exchange for 100 percent of Class B managing membership interests in DFV. A third-party investor trust contributed $60 million for 100 percent of the Class A membership interests in DFV. DFV is the sole owner of DTI. As a result of the Class A membership interests having substantive minority veto rights, DTI is no longer consolidated, and Dominion’s investment in DFV is accounted for using the equity method and is reported in investment in affiliates on the 2001 consolidated balance sheet.

In 2001, DFV issued $665 million of 7.05 percent Senior Secured Notes due March 2005 (DFV Senior Notes). The DFV Senior Notes are redeemable at any time at the option of DFV or upon occurrence of certain events. DFV contributed $712 million net cash proceeds from the issuance of DFV Senior Notes and the sale of the Class A membership interests to DTI and Monument Overfund Trust (Overfund Trust), approximating $518 million and $194 million, respectively. Overfund Trust

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

is owned by DFV. The DFV Senior Notes are secured by the stock of DTI, the Overfund Trust, and certain rights with respect to the Dominion Preferred Stock held by Piedmont Share Trust (Piedmont Trust) as described below. Pending the need for cash to fund capital expenditures in the expansion of its telecommunications network, the unused cash was loaned to Dominion and was used by it to repay commercial paper. The amount in Overfund Trust will be invested in Dominion debt securities or other financial investments. The interest and principal payments on such investments are expected to generate amounts sufficient to make interest payments on the DFV Senior Notes through maturity and make return requirements payments on Investor Trust’s membership interests in DFV. At the end of 2001, Dominion owed $367 million under these affiliated loans. This amount is reported as notes payable — affiliates and securities due within one year on the consolidated balance sheet. In 2001, Dominion paid $22 million of interest on the loans and approximately $1 million for rental charges for use of fiber lines owned by DTI.

As a result of the formation of DFV and the issuance of the DFV Senior Notes, Dominion issued 665,000 shares of its Series A Mandatorily Convertible Preferred Stock, liquidation preference $1,000 per share, (Preferred Stock) to Piedmont Trust at closing. Dominion is the beneficial owner of the Piedmont Trust which is consolidated in the preparation of the consolidated financial statements of Dominion. The right to cause remarketing of the Preferred Stock is part of the security for the DFV Senior Notes. Piedmont Trust is established with the intention of allowing for the remarketing of the Preferred Stock in an amount sufficient to retire the DFV Senior Notes if those notes are not otherwise paid at maturity, or in the event there is a downgrade of Dominion Resources, Inc. senior unsecured debt to BBB – or Baa3 and the closing price of Dominion’s common stock is below $45.97 for ten consecutive trading days. If the remarketing of the Preferred Stock were to occur, the Preferred Stock, as convertible securities, would be considered in the calculation of diluted earnings per share of Dominion’s common stock or could result in the issuance of additional shares of Dominion common stock, if converted. At March 1, 2001, Dominion Resources, Inc. senior unsecured debt was rated BBB+ by Standard & Poor’s Corporation and Baa1 by Moody’s Investors Service.

Amounts Due from Affiliates

Dominion’s equity method investments include its 50 percent interest in both Elwood Energy and Morgantown Energy Associates, each of which operates independent power generating facilities. As of December 31, 2001 and 2000, amounts due from affiliates totaled $13 million and $122 million, respectively. The balance at December 31, 2000, included an advance to Elwood Energy of $121 million which was repaid in 2001. The remainder of these receivables generally relates to services provided to Elwood Energy, Morgantown Energy Associates and DTI. Revenues recognized for these services for 2001, 2000, and 1999 were not material. In addition, Dominion leases fiber optic capacity to DTI. During 2001, Dominion received approximately $4 million under the lease and related support and maintenance services. Balances due to or from affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.

Related Party Guarantees

Dominion has issued guarantees to various third parties in relation to payment obligations by certain of its subsidiaries and officers. At December 31, 2001, Dominion had issued $3.3 billion of guarantees, subsidiary debt subject to such guarantees totaled $1.1 billion and officers’ borrowings under the executive stock loan program totaled $84 million.

Note 30    Operating Segments

Dominion manages its operations along three primary business lines:

Dominion Energy manages Dominion’s generation portfolio, consisting primarily of generating units and power purchase agreements. It also manages Dominion’s generation growth strategy; energy trading, marketing, hedging and arbitrage activities; and gas pipeline and certain gas production and storage operations.

Dominion Delivery manages Dominion’s electric and gas distribution systems, as well as customer service and electric transmission.

Dominion Exploration & Production manages Dominion’s onshore and offshore gas and oil exploration, development and production operations. Operations are located on the outer continental shelf and deep water areas of the Gulf of Mexico and in selected regions in the lower 48 states and Canada.

In addition, Dominion also reports the operations of DCI and Dominion’s corporate and other operations as operating segments. Amounts included in the Corporate and Other category include:

1. corporate expenses of the Dominion and CNG holding companies (including interest not allocated to other segments);

2. the operations of Corby (UK), prior to its sale on September 29, 2000 (see Note 6); and

3. the following unusual or extraordinary items:

• 2001 restructuring costs and 2000 restructuring and acquisition-related costs (see Note 7);

• 2001 costs associated with restructuring long-term NUG contracts (see Note 27);

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• 2001 provision for credit exposure in connection with Enron bankruptcy (see Note 15);

• 2001 and 2000 impairment and re-valuation of DCI’s assets (see Note 8);

• 2000 cumulative effect of a change in accounting principle (see Note 3); and

• 1999 extraordinary item—discontinuance of SFAS No. 71 (see Note 9).

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

	Dominion Energy			Dominion Delivery			Dominion E&P			Dominion Capital			Corporate and Other			Eliminations			Consolidated Total
	(millions, except total assets)
2001
Revenue from external customers:
Regulated electric sales	$	3,475		$	1,144			—			—			—			—		$	4,619
Regulated gas sales		—			1,409			—			—			—			—			1,409
Nonregulated electric sales		680			—			—			—		$	21			—			701
Nonregulated gas sales		1,047			4		$	65			—			—			—			1,116
Gas transportation and storage		404			298			—			—			—			—			702
Gas and oil production		—			—			1,118			—			—			—			1,118
Other revenue		395			93			171		$	234			—			—			893
Total revenue from external customers		6,001			2,948			1,354			234			21			—			10,558
Intersegment revenue		143			15			106			—			626		$	(890	)		—
Total operating revenue		6,144			2,963			1,460			234			647			(890	)		10,558
Interest expense		275			208			64			83			474			(205	)		899
Depreciation, depletion, and amortization		379			339			364			28			135			—			1,245
Equity in earnings of equity method investees		39			(3	)		5			—			2			—			43
Income tax expense (benefit)		477			200			145			(19	)		(433	)		—			370
Net Income		723			366			320			(14	)		(851	)		—			544
Investment in equity method investees		135			103			71			105			76			—			490
Capital expenditures		793			435			898			—			42			—			2,168
Total assets (billions)		13.2			8.5			7.4			1.3			18.4			(14.4	)		34.4
2000
Revenue from external customers:
Regulated electric sales		3,341			1,151			—			—			—			—			4,492
Regulated gas sales		—			1,374			—			—			—			—			1,374
Nonregulated electric sales		317			—			—			—			1			—			318
Nonregulated gas sales		614			(9	)		66			—			—			—			671
Gas transportation and storage		290			197			—			—			(1	)		—			486
Gas and oil production		(13	)		—			870			—			—			—			857
Other revenue		182			85			343			433			5			—			1,048
Total revenue from external customers		4,731			2,798			1,279			433			5			—			9,246
Intersegment revenue		163			28			51			—			398			(640	)		—
Total operating revenue		4,894			2,826			1,330			433			403			(640	)		9,246
Interest expense		225			204			83			192			379			(125	)		958
Depreciation, depletion, and amortization		340			318			352			34			132			—			1,176
Equity in earnings of equity method investees		23			—			12			6			6			—			47
Income tax expense (benefit)		262			187			97			12			(375	)		—			183
Net Income		489			339			255			11			(658	)		—			436
Investment in equity method investees		223			—			71			111			66			—			471
Capital expenditures		330			457			751			5			22			—			1,565
Total assets (billions)		10.5			8.5			3.2			2.0			14.2			(9.1	)		29.3
1999
Revenue from external customers:
Regulated electric sales		3,121			1,109			—			—			—			—			4,230
Nonregulated electric sales		346			—			—			—			—			—			346
Gas and oil production		—			—			251			—			—			—			251
Other revenue		178			28			5			473			9			—			693
Total revenue from external customers		3,645			1,137			256			473			9			—			5,520
Intersegment revenue		—			23			—			—			—			(23	)		—
Total operating revenue		3,645			1,160			256			473			9			(23	)		5,520
Interest expense		173			141			39			152			28			(26	)		507
Depreciation, depletion, and amortization		313			246			84			32			32			—			707
Equity in earnings of equity method investees		14			—			5			4			10			—			33
Income tax expense (benefit)		161			109			(29	)		35			(17	)		—			259
Net Income		271			175			44			78			(271	)		—			297
Capital expenditures		461			317			86			9			21			—			894

81

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of December 31, 2001 and 2000, and for the years ended December 31, 2001, 2000, and 1999, approximately 2 percent of Dominion’s total long-lived assets and revenue, respectively, were associated with international operations. As of December 31, 1999, approximately 8 percent of Dominion’s total long-lived assets were associated with international operations. Long-lived assets at December 31, 1999 included Dominion’s investments in Latin America and in the U.K., which were divested in 2000.

Note 31    Gas and Oil Producing Activities (unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation and amortization, follow:

	At December 31
	2001		2000
	(millions)
Capitalized costs of:
Proved properties	$	7,303	$	5,210
Unproved properties		1,689		550
		8,992		5,760
Accumulated depreciation of:
Proved properties		3,043		2,959
Unproved properties		301		233
		3,344		3,192
Net capitalized costs	$	5,648	$	2,568

Total Costs Incurred

The following costs were incurred in gas and oil producing activities during the years 1999 through 2001:

	Year Ended December 31,
	2001						2000						1999
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
	(millions)
Property acquisition costs:
Proved properties	$	1,586	$	1,586		—	$	1,475	$	1,459	$	16	$	280	$	121	$	159
Unproved properties		908		897	$	11		125		125		—		33		3		30
		2,494		2,483		11		1,600		1,584		16		313		124		189
Exploration costs		305		305		—		159		115		44		4		2		2
Development costs(1)		512		395		117		261		236		25		85		34		51
Total	$	3,311	$	3,183	$	128	$	2,020	$	1,935	$	85	$	402	$	160	$	242

(1) Development costs incurred for proved undeveloped reserves were $133 million and $82 million for 2001 and 2000, respectively. Dominion did not incur development costs for proved undeveloped reserves in 1999.

Results of Operations

Dominion cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.

	Year Ended December 31,
	2001						2000						1999
	Total		United States		Canada		Total		United States		Canada		Total			United States			Canada
	(millions)
Revenue (net of royalties) from:
Sales to nonaffiliated companies	$	1,144	$	920	$	224	$	861	$	691	$	170	$	229		$	142		$	87
Transfers to other operations		114		114		—		93		93		—		—			—			—
Total		1,258		1,034		224		954		784		170		229			142			87
Less:
Production (lifting) costs		220		162		58		158		133		25		77			47			30
Depreciation, depletion
and amortization		358		307		51		345		294		51		84			47			37
Income tax expense (benefit)		208		162		46		134		93		41		(10	)		(19	)		9
Results of operations	$	472	$	403	$	69	$	317	$	264	$	53	$	78		$	67		$	11

82

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 1999 through 2001, and changes in the reserves during those years, are shown in the two schedules which follow.

	2001						2000						1999
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
	(billion cubic feet)
Proved developed and undeveloped reserves — Gas
At January 1	2,337		1,858		479		1,114		600		514		591		473		118
Changes in reserves:
Extensions, discoveries and other additions	480		393		87		274		232		42		156		94		62
Revisions of previous estimates	(210	)	(134	)	(76	)	(89	)	(59	)	(30	)	(18	)	25		(43	)
Production	(273	)	(230	)	(43	)	(269	)	(222	)	(47	)	(97	)	(60	)	(37	)
Purchases of gas in place	1,577		1,575		2		1,322		1,322		—		512		98		414
Sales of gas in place	(9	)	(9	)	—		(15	)	(15	)	—		(30	)	(30	)	—
At December 31	3,902		3,453		449		2,337		1,858		479		1,114		600		514
Proved developed reserves — Gas
At January 1	1,954		1,593		361		1,005		600		405		591		473		118
At December 31	3,294		2,962		332		1,954		1,593		361		1,005		600		405

	2001						2000						1999
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
	(thousands of barrels)
Proved developed and undeveloped reserves — Oil
At January 1	75,342		51,072		24,270		20,808		659		20,149		4,204		2,661		1,543
Changes in reserves:
Extensions, discoveries and other additions	44,489		37,402		7,087		14,213		12,813		1,400		2,051		118		1,933
Revisions of previous estimates	29,349		11,647		17,702		(5,082	)	(2,443	)	(2,639	)	8,339		(552	)	8,891
Production	(11,220	)	(7,267	)	(3,953	)	(7,694	)	(6,436	)	(1,258	)	(2,057	)	(595	)	(1,462	)
Purchases of oil in place	34,702		34,603		99		54,977		48,359		6,618		9,244		—		9,244
Sales of oil in place	(789	)	(789	)	—		(1,880	)	(1,880	)	—		(973	)	(973	)	—
At December 31	171,873		126,668		45,205		75,342		51,072		24,270		20,808		659		20,149
Proved developed reserves — Oil
At January 1	36,236		21,709		14,527		6,102		659		5,443		4,204		2,661		1,543
At December 31	92,615		57,152		35,463		36,236		21,709		14,527		6,102		659		5,443

83

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities owned by Dominion.

	Year Ended December 31,
	2001							2000						1999
	Total		United States		Canada			Total		United States		Canada		Total		United States		Canada
	(millions)
Future cash inflows	$	12,350	$	11,161	$	1,189		$	23,602	$	19,117	$	4,485	$	2,401	$	1,282	$	1,119
Less:
Future development cost(1)		845		770		75			503		405		98		110		—		110
Future production cost		3,571		3,091		480			2,055		1,540		515		987		497		490
Future income tax expense		1,917		2,026		(109	)		7,145		5,591		1,554		209		125		84
Future cash flows		6,017		5,274		743			13,899		11,581		2,318		1,095		660		435
Less annual discount (10% a year)		2,804		2,513		291			5,723		4,622		1,101		546		310		236
Standardized measure of discounted future net cash flows(2)	$	3,213	$	2,761	$	452		$	8,176	$	6,959	$	1,217	$	549	$	350	$	199

(1) Estimated future development costs, excluding abandonment, for proven undeveloped reserves are estimated to be $241 million, $272 million and $85 million for 2002, 2003, and 2004, respectively.

(2) Amounts exclude the effect of contracts designated as hedges of future sales of production at year end.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, or permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of Dominion’s proved reserves. Dominion cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, present costs and prices are used in the determinations and no value may be assigned to probable or possible reserves.

The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.

	Year Ended December 31,
	2001			2000			1999
	(millions)
Standardized measure of discounted future net cash flows at January 1	$	8,176		$	549		$	382
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(1,038	)		(796	)		(152	)
Prices and production and development costs related to future production		(9,793	)		9,544			(110	)
Extensions, discoveries and other additions, less production and development costs		767			1,602			103
Previously estimated development costs incurred during the year		134			82			57
Revisions of previous quantity estimates		62			(778	)		34
Accretion of discount		1,117			259			44
Income taxes		2,949			(3,309	)		(44	)
Acquisition of Louis Dreyfus and CNG		1,347			1,322			—
Other purchases and sales of proved reserves in place		102			994			245
Other (principally timing of production)		(610	)		(1,293	)		(10	)
Standardized measure of discounted future net cash flows at December 31	$	3,213		$	8,176		$	549

84

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 32    Quarterly Financial and Common Stock Data (unaudited)

A summary of the quarterly results of operations for the years 2001 and 2000 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals (except as discussed below), 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. Amounts for 2000 reflect certain reclassifications to conform to the 2001 presentation.

	First Qtr.		Second Qtr.			Third Qtr.		Fourth Qtr.			Total
	(millions, except per share amounts)
2001
Operating revenue	$	3,198	$	2,309		$	2,544	$	2,507		$	10,558
Income from operations		496		518			780		(9	)		1,785
Net income (loss)		162		155			344		(117	)		544
Earnings per share—basic
Net income (loss)		0.66		0.63			1.38		(0.45	)		2.17
Earnings per share—diluted
Net income (loss)		0.65		0.62			1.37		(0.45	)		2.15
Dividends paid per share		0.645		0.645			0.645		0.645			2.58
Common stock price range (high-low)		68-55.31		69.99-59.47			64.15-55.13		62.97-55.30
2000
Operating revenue		2,069		2,051			2,344		2,782			9,246
Income from operations		418		71			660		366			1,515
Income (loss) before cumulative effect of a change in accounting principle		147		(98	)		260		106			415
Cumulative effect of a change in accounting principle		21		—			—		—			21
Net income (loss)		168		(98	)		260		106			436
Earnings per share—basic
Income (loss) before cumulative effect of a change in accounting principle		0.66		(0.41	)		1.09		0.44			1.76
Net income (loss)		0.75		(0.41	)		1.09		0.44			1.85
Earnings per share—diluted
Income (loss) before cumulative effect of a change in accounting principle		0.66		(0.41	)		1.09		0.44			1.76
Net income (loss)		0.75		(0.41	)		1.09		0.44			1.85
Dividends paid per share		0.645		0.645			0.645		0.645			2.58
Common stock price range (high-low)		43.13-34.81		47.50-38.06			59.81-42.81		67.94-50.75

85

REPORT OF MANAGEMENT’S RESPONSIBILITIES

The management of Dominion Resources, Inc. is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the annual report. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with generally accepted accounting principles. Other financial information in the annual report is consistent with that in the Consolidated Financial Statements.

Management maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that Dominion’s and its subsidiaries’ assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal accounting control, and therefore cannot provide absolute assurance that the objectives of the established internal accounting controls will be met.

This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel, and internal audits. Management believes that during 2001 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who were designated by the Board. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and include a review of Dominion’s and its subsidiaries’ accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.

The Audit Committee of the Board of Directors of Dominion Resources, Inc., composed entirely of directors who are not officers or employees of Dominion Resources, Inc. or its subsidiaries, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

Management recognizes its responsibility for fostering a strong ethical climate so that Dominion’s affairs are conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in Dominion’s Code of Ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information, and full disclosure of public information.

DOMINION RESOURCES, INC.
	/s/    THOS. E. CAPPS	/s/    STEVEN A. ROGERS
	Thos. E. Capps Chairman, President and Chief Executive Officer	Steven A. Rogers Vice President, Controller and Principal Accounting Officer

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. 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 Dominion Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 15 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 22, 2002