SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q
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X    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes    X   No         

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act). Yes       No   X   

At April 30, 2003, the latest practicable date for determination, 177,932 shares of common stock, without par value, of the registrant were outstanding.

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

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

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial
    Statements at that date.

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

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial
    Statements at that date.

**Debt securities issued by Virginia Electric and Power Company constitute 100 percent of the trust's assets.

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

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Note 1. Nature of Operations

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

The Company manages its daily operations through two operating segments, Energy and Delivery. In addition, the Company also presents its corporate and other operations as a segment. See Note 14.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited Consolidated Financial Statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

In the opinion of the Company's management, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of March 31, 2003 and its results of operations and cash flows for the three-month periods ended March 31, 2003 and 2002.

The accompanying unaudited Consolidated Financial Statements represent the accounts of the Company and its subsidiaries, with all significant intercompany transactions and accounts eliminated in consolidation.

The accompanying unaudited Consolidated Financial Statements reflect certain estimates and assumptions made by management 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 revenue and expenses for the periods presented. Actual results may differ from those estimates.

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for more discussion of the Company's estimation techniques.

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

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Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

Depreciation

In 2002, the Company extended the estimated useful lives of most of its fossil fuel stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. These changes in estimated useful lives reduced depreciation expense by approximately $16 million for the first quarter of 2003.

In 2001, the Company extended the estimated useful lives of its nuclear facilities by 20 years. The impact of the change is fully reflected in depreciation expense for 2003 and 2002. The Company filed applications with the Nuclear Regulatory Commission (NRC) for 20-year life-extensions for its nuclear facilities in 2001 and received a renewed license for these units in March 2003.

Note 3. Accounting Changes

Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (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. The Company has identified certain asset retirement obligations that are subject to the standard. These obligations are primarily associated with the decommissioning of its nuclear generation facilities.

Under SFAS No. 143, asset retirement obligations will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Under the present value approach used to estimate the fair value of asset retirement obligations, accretion of the liabilities due to the passage of time will be recognized as an operating expense. In addition, the reporting of realized and unrealized earnings of external trusts available for funding decommissioning activities at the Company's nuclear plants will be recorded in other income and other comprehensive income, as appropriate. Through 2002, the Company recorded these trusts' earnings in other income with an offsetting charge to expense, also recorded in other income, for the accretion of the decommissioning liability.

The effect of adopting SFAS No. 143 for the three months ended March 31, 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $145 million. The increase reflects lower expenses under SFAS No. 143 compared to expenses that would have been recorded under the former accounting policies. The $145 million increase is comprised of a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle, described below, and an increase in income before the cumulative effect of a change in accounting principle of $6 million. Under the Company's accounting policy prior to the adoption of SFAS No. 143, $838 million had previously been accrued for future asset removal costs, primarily related to future nuclear decommissioning. Such amounts are included in the accumulated provision for depreciation and amortization as of December 31, 2002. With the adoption of SFAS No. 143, the Company calculated its ass et retirement obligations to be $697 million. In recording the cumulative effect of the accounting change, the Company recognized the reduction attributable to the remeasurement of asset retirement obligations and reclassified such amount from the accumulated provision for depreciation and amortization to other non-current liabilities. The cumulative effect of the accounting change also reflected a $175 million increase in property, plant and equipment for capitalized asset retirement costs and a $77 million increase in the accumulated provision for depreciation and amortization, representing the depreciation of such costs through December 31, 2002.

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The EITF 98-10 rescission was effective for all non-derivative energy trading contracts initiated after October 25, 2002. For those non-derivative energy trading contracts initiated prior to October 25, 2002, the Company reported the cumulative effect of this change in accounting principle as of January 1, 2003, resulting in an after-tax loss of $55 million.

The rescission of EITF 98-10, along with other provisions of EITF 02-03, also affects the classification of realized and unrealized gains and losses arising from derivative energy contracts, no longer considered to be held for trading purposes, on the Consolidated Statements of Income. As permitted by EITF 98-10, for periods prior to January 1, 2003, the Company presented all changes in fair value of derivative and non-derivative energy trading contracts, including amount realized upon settlement, in revenue on a net basis. Under the provisions of EITF 02-03, for those energy-related derivative instruments determined to be held for trading purposes, all changes in fair value, including amounts realized upon settlement, continue to be presented in revenue on a net basis. A derivative contract is held for trading purposes if the intent of the transaction is to generate profits on short-term differences in price. For non-trading derivatives not designated as hedges, all unrealized changes in fair value are pres ented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue, while gross purchase contract settlements are reported in expenses.

Note 4. Recently Issued Accounting Standards

On April 30, 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is evaluating SFAS No. 149 and has not yet determined the impact of adopting its provisions.

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Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation.

Nonregulated electric sales consist primarily of sales of electricity at market-based rates and net revenue from electric trading activities.

Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas and net revenue from gas trading activities.

Other revenue consists primarily of miscellaneous service revenue from rate-regulated electric distribution, sales of coal and brokered oil and other miscellaneous revenue.

The composition of revenue from nonregulated electric sales, nonregulated gas sales, and other revenue has changed since being described in Note 5 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The changes were effective January 1, 2003 and related to the impact of adopting EITF 02-03 on the reporting of revenue and expenses for energy trading activities, as described in Note 3.

The Company recognized costs and related liability associated with employee severances in 2001. The change in this liability during the three-month period ended March 31, 2003 is presented below:

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For additional information, see Note 6 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Total comprehensive income was $372 million and $152 million for the three months ended March 31, 2003 and March 31, 2002, respectively. Other comprehensive income for these periods related primarily to unrealized losses on investments held in decommissioning trusts and the effective portion of the changes in fair value of derivatives designated as hedging instruments in cash flow hedges (as described in Note 8). See Note 3 for a discussion of accounting for unrealized gains and losses on trust investments.

Note 8. Derivatives and Hedge Accounting

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in the Consolidated Balance Sheet at March 31, 2003:

The actual amounts that will be reclassified to earnings during the next 12 months will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Note 9. Significant Financing Transactions

In February 2003, the Company issued $400 million aggregate principal amount of its 2003 Series A 4.75 percent senior notes due March 1, 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

In February 2003, the Company repaid $10 million of maturing medium-term notes.

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The following table describes the changes to the Company's asset retirement obligations during the three months ended March 31, 2003:

The Company has established external trusts dedicated to funding the future decommissioning of its nuclear plants. At March 31, 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $819 million.

Had the provisions of SFAS No. 143 been adopted on January 1, 2000, the Company's net income would have been as follows:

Had the provisions of SFAS No. 143 been adopted on January 1, 2000, the asset retirement obligations would have been as follows:

In accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company will continue its practice of accruing for future costs of removal for its cost-of-service rate regulated transmission and distribution assets, even if no legal obligation to perform such activities exists. At March 31, 2003 and December 31, 2002, the Company's accumulated depreciation and amortization included $383 million and $375 million, representing the estimated future cost of such removal activities, respectively.

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Note 11. Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies disclosed in Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, nor have any significant new matters arisen during the first quarter of 2003.

As previously reported in Note 21 to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2002, the Company received a Notice of Violation in 2000 from the United States Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia. Thereafter, New York State filed a suit against the Company alleging similar violations, and the suit was stayed. The Company reached an agreement in principle with the federal government and the state of New York to resolve the matter, and the states of Virginia, West Virginia, Connecticut and New Jersey joined the United States and the state of New York in seeking to reach a final agreement with the Company. A settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003, by the U.S. Department of Justice and the U.S. Environmental Protection Agency for the United States of America, by the states of Virginia, West Virginia, Connecticut, New Jersey and New York and by the Company. In accordance with the settlement, the United States filed an action in the Eastern District of Virginia against the Company and the Consent Decree was lodged with that court to settle that action. Virginia and West Virginia also filed complaints in intervention in the Virginia federal district court. The New York State federal district court action has been transferred to the Virginia federal district court and it is anticipated that, in addition to New York, Connecticut and New Jersey will join as plaintiffs in that proceeding. After an EPA public comment period, the Virginia federal district court will be asked to enter the Consent Decree finalizing the settlement and resolving the underlying actions, but retaining jurisdiction pursuant to the terms of the Consent Decree. The settlement is consistent with the previously reported agreement in principle and includes payment of a $5 million civil penalty, an obligation to fund $14 million for environm ental projects and a commitment to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of March 31, 2003, the Company had accrued $18 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

At March 31, 2003, the Company had issued $66 million of surety bonds, of which $57 million is associated with the financial assurance requirements imposed by the NRC with respect to the decommissioning of the Company's nuclear units. Under the terms of the surety bonds, the Company is obligated to indemnify the respective surety bond company for any amounts paid.

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Note 12. Related Party Transactions

The Company, through an unregulated subsidiary, exchanges certain quantities of natural gas with affiliates at market prices in the ordinary course of business. The Company purchased approximately $123 million and $28 million of natural gas, gas transportation and storage services from other Dominion affiliates and sold approximately $144 million and $39 million of natural gas to affiliates in the first quarter of 2003 and 2002, respectively.

Through the same unregulated subsidiary, the Company is involved in facilitating Dominion's enterprise risk management strategy. In connection with this strategy, the Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by Dominion affiliates to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion's enterprise risk management strategy, the Company generally manages such risk exposures by entering into offsetting derivative instruments with non-affiliates. The Company reports both affiliated and non-affiliated derivative instruments at fair value, with related changes included in earnings. At March 31, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $85 million and $84 million and derivative liabilities with Dominion affiliates of $79 million and $90 million, respectively. The Company reported net realized losses of $5 million and net gains of $20 million during quarters ended March 31, 2003 and 2002, respectively, related to commodity derivative contracts with Dominion affiliates.

Dominion Resources Services, Inc. (Dominion Services) provides certain administrative and technical services to the Company. The cost of services provided by Dominion Services to the Company in the first quarters of 2003 and 2002 was approximately $72 million and $64 million, respectively. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of these services provided by the Company to Dominion Services and other Dominion affiliates in the first quarters of 2003 and 2002 was approximately $6 million and $5 million, respectively.

During the first quarter of 2003, unregulated subsidiaries of the Company repaid the $100 million that Dominion had advanced pursuant to a short-term demand note in 2002. Interest charges related to this note in the first quarter of 2003 were not material.

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

For information about the Company's agreement with Dominion Equipment II, Inc. to develop, construct, finance and lease a new power generation facility at its Possum Point station in Prince William County, Virginia, see Note 21 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

An unregulated subsidiary of the Company, at its sole discretion, has provided at March 31, 2003 and December 31, 2002, approximately $24 million and $31 million of cash collateral to third parties on behalf of several of its natural gas supply customers. For this and other financial support services, the unregulated subsidiary receives fees and has a security interest in the customers' assets. The arrangements terminate at various dates beginning in 2005 through 2007, subject to periodic renewal thereafter unless terminated by either party.

For additional information on transactions with related parties, see Note 24 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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Note 13.     Concentration of Credit Risk

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative and energy trading contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. In the calculation of net credit exposure, the Company's gross exposure is reduced by collateral made available by counterparties, including letters of credit and cash received by the Company and held as margin deposits. Presented below is a summary of the Company's gross and net credit exposure as of March 31, 2003. The amounts presented exclude accounts receivable for regulated electric retail distribution and regulated electric transmission services, amounts payable to affiliated companies and the Company's provision for credit losses. See Note 23 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a discussion of the nature of the Company's credit risk exposure s.

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The Company manages its operations through the following segments:

Energy manages the Company's portfolio of generating facilities and power purchase contracts. It also manages the Company's energy trading, marketing, hedging and arbitrage activities. Energy also manages the electric transmission business formerly managed by Delivery. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Delivery manages the Company's electric distribution as well as metering services and customer service. The segment continues to be subject to the requirements of SFAS No. 71. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Corporate and Other includes certain expenses which are not allocated to the Energy and Delivery segments, including those related to the following: 1) corporate operations and assets; 2) severance costs related to 2003 workforce reductions; and 3) the 2003 cumulative effect of changes in accounting principle (See Note 3).

See Note 26 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for more information about the Company's segments.

This report contains statements concerning the Company'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.

The Company 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 weather conditions; fluctuations in energy-related commodities prices and the effect these could have on the Company's earnings, liquidity position, and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; changes in rating agency requirements or ratings; changes in accounting standards; the risks of operating businesses in regulated industries that are becoming deregulated; transfer of control over the Company's transmis sion facilities to a regional transmission entity; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation rates). Some more specific risks are discussed below.

The Company bases its forward-looking statements on management's beliefs and assumptions using information available at the time the statements are made. The Company 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. The Company undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

The Company's operations are weather sensitive. The Company's results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. In addition, severe weather, including hurricanes, winter storms and droughts, can be destructive, causing outages, property damage and requiring the Company to incur additional expenses.

The Company is subject to complex government regulation which could adversely affect its operations. The Company's operations are subject to extensive regulation and require numerous permits, approvals and certificates from various federal, state and local governmental agencies. The Company must also comply with environmental legislation and other regulations. Management believes the necessary approvals have been obtained for the Company's existing operations and that its business is conducted in accordance with applicable laws. However, new laws or regulations or the revision or reinterpretation of existing laws or regulations may require the Company to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed the Company's estimates. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment and monitoring obligations. In addition, the Company may be a responsible party for environmental clean up at a site identified by a regulatory body. 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.

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Capped electric rates in Virginia may be insufficient to allow full recovery of stranded and other costs. Under the Virginia Utility Restructuring Act, the Company's base rates (excluding fuel costs and certain other allowable adjustments) remain unchanged until July 2007 unless modified or terminated consistent with that Act. The capped rates and wires charges that, where applicable, are being assessed to customers opting for alternative suppliers allow the Company to recover certain generation-related costs and fuel costs; however, the Company 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 Management's Discussion and Analysis of Financial Condition and Results of Operations-Future Issues and Outlook and Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ende d December 31, 2002.

The electric generation business is subject to competition. The generation portion of the Company's operations in Virginia is open to competition and is no longer subject to cost-based rate regulation. As a result, there is increased pressure to lower costs, including the cost of purchased electricity. Because the Company's generation 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 unknown. Therefore, it is difficult to predict the extent to which the Company will be able to operate profitably within this new environment.

There are inherent risks in the operation of nuclear facilities. The Company operates nuclear facilities that are subject to inherent risks. These include the threat of terrorist attack and ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and the Company's ability to maintain adequate reserves for decommissioning, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. The Company maintains decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses. The Company uses derivative instruments including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, the Company purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, the Company 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 involves 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 the Company's derivatives and commodity-based trading contracts, se e Management's Discussion and Analysis of Financial Condition and Results of Operations-Market Rate Sensitive Instruments and Risk Management and Notes 2 and 9 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

The Company is exposed to market risks beyond its control in its energy clearinghouse operations. The Company's energy clearinghouse and risk management operations are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. Many industry participants have experienced severe business downturns during the past year resulting in some being forced to exit or curtail their participation in the energy trading markets. This has led to a reduction in the number of trading partners and lower industry trading revenues. Declining credit worthiness of some of the Company's trading counterparties may limit the level of its trading activities with these parties and increase the risk that these counterparties may not perform under a contract.

An inability to access financial markets could affect the execution of the Company's business plan. The Company 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 flows of its operations. Management believes that the Company and its subsidiaries will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company's control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the

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bankruptcy of an unrelated energy company or changes to the Company's credit ratings. Restrictions on the Company's ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing rating agency requirements could negatively affect the Company's growth and business strategy. As of May 1, 2003, the Company's senior secured debt is rated A-, stable outlook, by Standard and Poors Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor's) and A2, stable outlook, by Moody's Investor Service (Moody's). Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company's credit ratings by either Standard & Poor's or Moody's could increase its borrowing costs and adversely affect operating results.

Potential changes in accounting practices may adversely affect the Company's financial results. The Company cannot predict the impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or in its operations specifically. New accounting standards could be issued by the Financial Accounting Standards Board (FASB) or the Securities and Exchange Commission (SEC) which could impact the way the Company is required to record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company's reported earnings or could increase reported liabilities.

In general, management's discussion of the Company's results of operations focuses on the contributions of its operating segments. However, the discussion of the Company's financial condition under Liquidity and Capital Resources is for the entire Company. The Company's two operating segments are Energy and Delivery. In addition, the Company presents its corporate and other operations, including certain expenses, which are not allocated to the Energy and Delivery segments, as a segment. For more information on the Company's operating segments, see Note 14 to the Consolidated Financial Statements.

Critical Accounting Policies

As of March 31, 2003, other than the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, there have been no significant changes with regard to critical accounting policies as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The policies disclosed included the accounting for risk management and energy trading contracts at fair value and accounting for regulated operations.

Effective January 1, 2003, the Company adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. At March 31, 2003, the Company's asset retirement obligations totaled $708 million, the majority of which relates to the decommissioning of its nuclear units.

Asset retirement obligations are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, the Company estimates the fair value of asset retirement obligations using present value techniques, involving discounted cash flow analysis. Measurement using such techniques is dependent upon many subjective factors, including the selection of discount and cost escalation rates, identification of planned retirement activities and related cost estimates and assertions of probability regarding the timing, nature and costs of such activities. Inputs and assumptions are based on the best information available at the time the estimates are made. However, estimates of future cash flows are highly uncertain by nature and may vary significantly from actual results.

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The Company's discussion of its results of operations includes a summary of contributions by the operating segments to net income, an overview of consolidated 2003 results of operations, as compared to 2002, and a more detailed discussion of the results of operations of the operating segments. The 2002 segment results have been restated to reflect the transfer of the electric transmission operations from the Delivery segment to the Energy segment.

The following table provides data on electricity supplied by Energy and delivered by Delivery:

Adoption of EITF 02-03

Effective January 1, 2003, the Company adopted EITF Issue 02-03. It rescinds EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Energy manages the Company's energy trading, hedging, arbitrage and power marketing activities through the Dominion Energy Clearinghouse (Clearinghouse). The implementation of EITF 02-03 primarily affects the timing of recognition in earnings for certain Clearinghouse energy-related contracts, as well as the presentation of gains and losses associated with energy-related contracts in the Consolidated Statement of Income. The adoption of EITF 02-03 did not require restatement of prior periods. See Note 3 to the Consolidated Financial Statements.

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The adoption of EITF 02-03 had the following initial and ongoing impact on the accounting for and presentation of Clearinghouse energy-related contracts in the Consolidated Financial Statements, effective January 1, 2003:

• Cumulative effect of adopting EITF 02-03: For all non-derivative energy contracts initiated prior to October 25, 2002, and previously designated as trading under EITF 98-10, the Company recognized a loss of $55 million (net of taxes of $35 million) as the cumulative effect of a change in accounting principle effective January 1, 2003, which is reflected in the Corporate and Other segment.
• Derivative Contracts: Energy-related derivative contracts continue to be subject to fair value accounting. Under fair value accounting, unrealized changes in fair value are recorded in earnings each reporting period, as well as amounts realized as settlements occur. For those derivatives determined to be held for trading purposes, all changes in fair value, including amounts realized upon settlement, are presented in revenue on a net basis. For non-trading derivatives not designated as hedges, all unrealized changes in fair value are presented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue, while gross purchase contract settlements are reported in expenses.
• Non-Derivative Contracts: Non-derivative energy-related contracts, previously subject to fair value accounting under EITF 98-10, are now subject to accrual accounting. Under accrual accounting, the Company recognizes revenue or expense on a gross basis at the time of contract performance, settlement or termination. These contracts will no longer be reported at fair value in the Company's Consolidated Financial Statements.

As noted above, the recognition and presentation requirements of EITF 02-03 described above were applied prospectively in 2003, and the Consolidated Statement of Income for the first quarter of 2002 was not restated.

Adoption of SFAS 143

The principal impact of the Company's implementation of SFAS No. 143 is a change in the method of accounting for nuclear decommissioning. As a result of the change, the Company's income before taxes increased in 2003, as compared to 2002, by approximately $3 million. However, when comparing SFAS No. 143 to the method of accounting used for nuclear decommissioning in 2002, the components of cost are presented differently in the income statement. For the comparative periods, depreciation expense decreased $8 million. Under SFAS No. 143, the Company also recorded $10 million in 2003, representing accretion of its asset retirement obligations, in other operations and maintenance expense. Under the 2002 accounting policy, the Company recorded $5 million in other income for accretion expense related to its accumulated provision for nuclear decommissioning. For more information, see Note 3 to the Consolidated Financial Statements.

Energy Segment

First Quarter 2003 Results

Energy's net income contribution increased $141 million to $242 million for the three months ended March 31, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $316 million increase in operating revenue and an $11 million increase in other income, offset by a $102 million increase in operating expenses and an $85 million increase in income tax expense. Comparably colder temperatures and customer growth contributed approximately $75 million and $10 million, respectively, to the $92 million increase in regulated electric sales. There were 27 percent more heating degree-days in the first quarter of 2003, as compared to 2002, and there were approximately 38,000 new electric customers added over the last twelve months. Fuel rate recoveries, which are generally offset by related increases in electric fuel expense and do not materially affect net income, increased $44 million for the first quarter of 2003. Partially offsetting these increases in regulated electric sales re venue was a

PAGE 22

net decrease of $18 million due to other factors. A reallocation of base rate revenue between the Delivery and Energy segments, effective January 1, 2003, decreased Energy's regulated electric sales revenue by $19 million.

Nonregulated electric sales decreased $26 million in the three months ended March 31, 2003, as compared to 2002. Clearinghouse electric revenue, net of applicable trading purchases, decreased by $33 million as compared to 2002. This decrease included the effects of unfavorable price changes on the fair value of derivative contracts held and not yet settled, lower margins and the impact of discontinuing fair value accounting for non-derivative contracts and the reclassification of purchases under derivative contracts no longer considered to be held for trading purposes after the adoption of EITF 02-03. Revenue from wholesale marketing of utility generation increased $7 million and was principally driven by higher electric prices.

Clearinghouse nonregulated gas revenue, net of applicable trading purchases, increased by $229 million, as compared to the first three months of 2002. This increase reflects the effect of favorable price changes on unsettled derivative contracts, increased volumes and impact of discontinuing fair value accounting for non-derivative contracts and the reclassification of purchases under derivative contracts no longer considered to be held for trading purposes after the adoption of EITF 02-03. Nonregulated gas revenue also reflects $18 million of realized and unrealized losses related to contracts held, by one of the Company's unregulated subsidiaries involved in Clearinghouse operations, as part of Dominion's consolidated price risk management strategy associated with anticipated sales of Dominion's 2003 natural gas production.

Other revenue increased over the same period in 2002, primarily reflecting the impact of adopting EITF 02-03. This increase included $16 million associated with oil trading revenue, net of applicable purchases, and revenue from sales of coal. Purchases of coal for this activity are reported in other purchased energy commodities expense in 2003 but were reported in other revenue in 2002.

Operating expenses increased $102 million to $807 million in the first quarter of 2003. Electric fuel and energy purchases, net increased $71 million. Energy costs increased $44 million due to higher fuel rate recoveries, $12 million for purchases not subject to fuel rate recoveries, and $6 million for expenses associated with increased wholesale marketing of utility generation. Electric fuel and energy purchases, net also increased due to the adoption of EITF 02-03, reflecting purchases under certain derivative contracts that are no longer considered held for trading purposes. Purchased electric capacity decreased $23 million, primarily due to scheduled rate reductions on certain supply contracts. Other purchased energy commodities increased $68 million reflecting the gross presentation of certain gas and coal contracts that are no longer considered held for trading purposes after the implementation of EITF 02-03.

Other operations and maintenance expense decreased $12 million primarily due to the adoption of EITF 02-03, reflecting changes in the fair value of certain derivative energy contracts that are no longer considered held for trading purposes. Increases in other operations and maintenance expense included a $27 million increase in general and administrative expenses and a $12 million increase in outage and maintenance costs at the generation stations. Also, as previously discussed, other operations and maintenance expense increased $10 million for the accretion of the nuclear decommissioning asset retirement obligation beginning in 2003.

Depreciation expense decreased $14 million, primarily reflecting a $8 million decrease related to a change in the presentation of expenses associated with asset retirement obligations pursuant to a change in accounting policy. As previously discussed, a significant component of such expenses is now reflected in other operations and maintenance beginning in 2003. The remaining decrease reflects the extension of estimated useful lives of most fossil fuel stations and electric transmission property during the second quarter of 2002, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements.

Other taxes increased $12 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues and the recognition of business and occupation tax credits. Similar benefits were not recognized in the first quarter of 2003.

Other income also increased approximately $11 million, reflecting increased earnings of $6 million from the Company's external decommissioning trusts and $5 million as a result of accretion expense related to the Company's provision for decommissioning being reported in other income in 2002. As previously discussed,

PAGE 23

accretion expense under SFAS No. 143 is reported in other operations and maintenance expense beginning in 2003.


Selected Information-Energy Trading Activities

See Selected Information-Energy Trading Activities in the MD&A of the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a detailed discussion of the energy trading, hedging and arbitrage
activities of the Clearinghouse and related accounting policies. For additional discussion of trading activities, see Market Rate Sensitive Instruments and Risk Management.

A summary of the changes in the unrealized gains and losses recognized for the Company's energy-related derivative instruments held for trading purposes during the first three months of 2003 follows:

The balance of net unrealized gains and losses recognized for the Company's energy-related derivative instruments held for trading purposes at March 31, 2003 is summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:

(2) Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.
(3) Values based on the Company's estimate of future commodity prices when information from external sources is not available and use of internally-developed models, reflecting option pricing theory, discounted cash flow concepts, etc.

Delivery Segment

First Quarter 2003 Results

Delivery's net income contribution increased $17 million to $69 million for the first quarter ended March 31, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $45 million increase in operating revenue partially offset by a $10 million increase in operating expenses and a $15 million increase in income tax expense. Comparably colder temperatures in 2003 and customer growth contributed approximately $32 million and $4 million, respectively, to the $46 million increase in regulated electric sales. Partially offsetting these

PAGE 24

increases in regulated electric sales revenue was a net decrease of $9 million due to other factors. A change in the allocation of the base rate revenues from Energy to Delivery increased Delivery's revenues by approximately $19
million. There were 27 percent more heating degree-days in the first quarter of 2003, as compared to 2002, and there were approximately 38,000 new electric customers added over the last twelve months.

Operations and maintenance expense increased $11 million, reflecting primarily an increase in general and administrative expenses and an increase in service restoration costs due to ice storms in the first quarter of 2003. Depreciation expense decreased by $3 million, reflecting primarily the effect of changes in the estimated useful lives of distribution property adopted in the second quarter of 2002. See Note 2 to the Consolidated Financial Statements for additional discussion of the change in estimated useful lives of the distribution property in 2002.

First Quarter 2003 Results

The change in the corporate segment's contribution to reported earnings is attributable primarily to the following items which impacted the first quarter of 2003, as compared to the same period last year: $8 million related to severance costs for workforce reductions; a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle from adoption of SFAS No. 143; and a $55 million after-tax charge, representing the cumulative effect of a change in accounting principle from adoption of EITF Issue No. 02-03. For more information on the cumulative effect of the changes in accounting principle, see Note 3 to the Consolidated Financial Statements.

Liquidity and Capital Resources

The Company depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash 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 financings.

Cash flow provided by operating activities totaled approximately $666 million and $321 million during the three months ended March 31, 2003 and 2002, respectively. The Company's management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain current dividends payable to Dominion. As noted above, the Company uses a combination of short-term borrowings and sales of securities to fund capital requirements not covered by the timing or amounts of operating cash flows.

The Company's operations are subject to risks and uncertainties that may negatively impact cash flows from operations. See the discussion of such factors in Internal Sources of Liquidity in the MD&A of the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

In the External Sources of Liquidity section of the MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, the Company discussed its use of capital markets as well as the impact of credit ratings on the accessibility and costs of using these markets. In addition, the Company discussed various covenants present in the enabling agreements underlying the Company's debt. As of March 31, 2003, there have been no downgrades of the Company's credit ratings. In addition, there have been no changes to or events of default under the Company's debt covenants.

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In February 2003, the Company issued $400 million aggregate principal amount of its 2003 Series A 4.75 percent senior notes due March 1, 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

In February 2003, the Company repaid $10 million of maturing medium-term notes.

Joint Credit Facilities

Dominion, Consolidated Natural Gas (CNG) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2003 and a $750 million three-year revolving credit facility that terminates in May 2005. The Company expects to renew the 364-day revolving credit facility prior to its maturity in May 2003. These joint credit

facilities are used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. At March 31, 2003, total outstanding letters of credit supported by the three-year facility were $106 million, which were issued by Dominion on behalf of its other subsidiaries.

At March 31, 2003, net borrowings under the commercial paper program were $43 million, a decrease of $400 million from December 31, 2002. Commercial paper borrowings are used primarily to fund working capital requirements and may vary significantly during the course of the year depending upon the timing and amount of cash requirements not satisfied by cash provided from operations.

Borrowings from Parent

During the first quarter of 2003, unregulated subsidiaries of the Company repaid the $100 million that Dominion had advanced pursuant to a short-term demand note in 2002.

Amounts Available under Shelf Registrations

At March 31, 2003, the Company had $1.325 billion of available capacity under currently effective shelf registrations with the SEC that would permit the Company to issue debt and preferred securities to meet future capital requirements.

Investing Activities

During the three months ended March 31, 2003, investing activities resulted in a net cash outflow of $236 million. These activities included plant construction and other property expenditures of $199 million and nuclear fuel expenditures of $28 million. The plant expenditures related to generation-related projects totaled approximately $110 million and included costs related to environmental upgrades, nuclear reactor head replacement expenditures and other capital improvements. The plant expenditures related to transmission and distribution projects totaled approximately $82 million, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled approximately $7 million. Investing activities also include $9 million of contributions to the Company's nuclear decommissioning trusts.

Contractual Obligations

As of March 31, 2003, other than scheduled maturities of new debt issued during the first quarter of 2003, there have been no significant changes to the contractual obligations disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to the Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Outlook in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Status of Electric Deregulation Legislation in Virginia

In an addendum to its status report on the development of a competitive retail market for electric generation within Virginia, the Virginia State Corporation Commission (Virginia Commission) recommended that state policymakers should decide promptly whether to proceed with or delay implementation of the Virginia Electric Utility Restructuring Act, in light of recent developments impacting electric industry restructuring in Virginia, including the Federal Energy Regulatory Commission's (FERC) issuance of a notice of proposed rule making on Standard Market Design. The Virginia General Assembly and Governor elected not to act on these recommendations.

In April 2003, Virginia enacted legislation that requires the Company to file an application with the Virginia Commission by July 1, 2003 to join a regional transmission organization (RTO) and delays entry into a RTO until on or after July 1, 2004. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its electric transmission assets to a RTO by January 1, 2005.

In March 2003, the Company filed an application with the Virginia Commission for approval of three proposed new electric retail access pilot programs. The pilots will make available to competitive service providers up to 500 MW of load, with expected participation of more than 65,000 customers from a variety of customer classes. If approved by the Virginia Commission, the proposed pilots will run from January 1, 2004 through December 31, 2005. To encourage participation by competitive suppliers and customers, the Company has proposed a significant reduction in the wires charges applicable to the pilot programs in 2004 and 2005. The Virginia Commission issued a procedural order in April 2003 establishing a schedule for interested parties to file comments or to request a hearing.

See Status of Electric Deregulation Legislation in Virginia above regarding recently enacted Virginia legislation regarding entry into a RTO.

In December 2002, American Electric Power (AEP), Commonwealth Edison Company (ComEd), Dayton Power and Light Company (collectively, the New PJM Companies), PJM Interconnection, LLC (PJM) and the Company tendered a joint filing with FERC. The joint filing proposes to (1) include the New PJM Companies' transmission facilities within PJM functional control; (2) establish a transmission rate for the existing PJM region, the Company and the New PJM Companies; (3) adopt a transitional rate method to maintain transmission revenue for the Company and the New PJM Companies and (4) amend certain agreements on file with FERC concerning the PJM energy market, planning processes and system operations as related to the integration of the New PJM Companies into PJM.

In April 2003, FERC issued an order accepting AEP's and ComEd's proposal to transfer control of their respective transmission facilities to PJM and set a hearing for the proposed transmission rates which would be effective as of the date of the transfer. FERC also directed AEP and ComEd to recalculate and refile the proposed rates due to the rejection of the Company's filing noted below.

In April 2003, FERC issued an order rejecting the Company's proposed amendment to its open access transmission tariff to establish a transitional transmission rate method that would apply from the time AEP and ComEd would begin to participate under the PJM transmission tariff until the Company joins PJM.

As previously reported in Note 21 to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2002, the Company received a Notice of Violation in 2000 from the United States Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia. Thereafter, New York State filed a suit against the Company alleging similar violations, and the suit was stayed. The Company reached an agreement in principle with the federal government and the state of New York to resolve the matter, and the states of Virginia, West Virginia, Connecticut and New Jersey joined the United States and the state of New York in seeking to reach a final agreement with the Company. A settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003, by the U.S. Department of Justice and the U.S. Environmental Protection Agency for the United States of America, by the states of Virginia, West Virginia, Connect icut, New Jersey and New York and by the Company. In accordance with the settlement, the United States filed an action in the Eastern District of Virginia against the Company and the Consent Decree was lodged with that court to settle that action. Virginia and West Virginia also filed complaints in intervention in the Virginia federal district court. The New York State federal district court action has been transferred to the Virginia federal district court and it is anticipated that, in addition to New York, Connecticut and New Jersey will join as plaintiffs in that proceeding. After an EPA public comment period, the Virginia federal district court will be asked to enter the Consent Decree finalizing the settlement and resolving the underlying actions, but retaining jurisdiction pursuant to the terms of the Consent Decree. The settlement is consistent with the previously reported agreement in principle and includes payment of a $5 million civil penalty, an obligation to fund $14 million for environmental pr ojects and a commitment to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of March 31, 2003, the Company had accrued $18 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

Accounting Matters

On April 30, 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. See Note 4 to the Consolidated Financial Statements for a discussion of the impact of adopting this new accounting standard and information about other standard-setting activities.

In 2001, the Company filed application for 20-year license extensions with the Nuclear Regulatory Commission (NRC) for the North Anna and Surry units. The NRC renewed the Company's operating licenses for those plants in the first quarter of 2003. See Note 2 to the Consolidated Financial Statements for more information.

PAGE 28

The matters discussed in this Item may contain "forward-looking statements" as described in the introductory paragraphs under Part I, Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The reader's attention is directed to those paragraphs for discussion of various risks and uncertainties that may affect the future of the Company.

The Company's financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates, equity security prices, foreign currency exchange rates, and commodity prices, as described below. Interest rate risk generally is related to the Company's outstanding debt. The Company is exposed to foreign exchange risk associated with purchases of certain nuclear fuel services denominated in foreign currencies. Commodity price risk is present in the Company's electric 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. The Company uses derivative instruments to manage price risk exposures for these operations. The Company is exposed to equity price risk through various portfolios of equity securities.

The Company'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 commodity prices, interest rates and foreign exchange rates.

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based financial derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. The Company uses established policies and procedures to manage the risks associated with these price fluctuations and uses various derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions. In addition, the Company 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 $50 million in the fair value of its commodity-based financial derivative contracts held for trading purposes as of March 31, 2003. A hypothetical 10 percent unfavorable change in commodity prices, as determined at December 31, 2002, would have resulted in a decrease of approximately $26 million in the fair value of its commodity-based financial derivative contracts held for trading purposes.

PAGE 29

The Company is subject to investment price risk due to marketable equity securities held as investments in its nuclear decommissioning trusts. In accordance with current accounting standards, these marketable equity securities are reported on the balance sheet at fair value. The Company recognized net realized and unrealized losses on decommissioning trust investments of $28 million for the three-month period ended March 31, 2003 and $56 million for the year-ended December 31, 2002.

Dominion also sponsors employee pension and other postretirement benefit plans, in which the Company's employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in the Company's recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans.

PAGE 30

Senior management, including the Chief Executive Officers and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures during the month of April and in early May of 2003. Based on this evaluation process, the Chief Executive Officers and Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective. Since that evaluation process was completed, there have been no significant changes in internal controls or in other factors that could significantly affect these controls.

PAGE 31

PART II. - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, the Company and its subsidiaries are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by Dominion and its subsidiaries, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there also may be administrative proceedings on these matters pending. In addition, in the normal course of business, the Company and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company's financial position, liquidity or results of operations. See Future Issues in Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for discussion on various regulatory proceedings to which the Company and its subsidiaries are a party.

In March 2003, Triad Energy Resources Corporation and other parties filed a class action antitrust suit against a number of defendants, including the Company and Cove Point LNG Limited Partnership, an affiliate of CNG, in the United States District Court for the District of Columbia. The complaint seeks compensatory damages for alleged violations of the Sherman Act and tortious interference with contractual and business relationships as a result of activities involving the storage and transportation of natural gas. No trial date has been set. The outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

In connection with the Notice of Violation received in 2000 from the Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia, a settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003 by the U.S. government, the Company and the five states involved. See Environmental Matters in the MD&A of this Form 10-Q for further information relating to this development.

On April 25, 2003, by consent in lieu of a meeting, Dominion Resources, Inc., the sole holder of all the voting common stock of the Company, elected the following persons to serve as Directors: Thos. E. Capps, Thomas F. Farrell, II, and Thomas N. Chewning.

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I, Thomas F. Farrell, II certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

I, Jay L. Johnson, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

I, Paul D. Koonce, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

I, Mark F. McGettrick, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

I, G. Scott Hetzer, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and