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 September 30, 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 October 31, 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.

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

⁽²⁾ 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 the "Company" refers to the entirety of Virginia Electric and Power Company, including its Virginia and N orth Carolina operations, and all of its subsidiaries.

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

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 for the year ended December 31, 2002 as well as the quarterly reports for previous interim periods of 2003 filed on Form 10-Q. On May 9, 2003, the Company filed a current report on Form 8-K that included its Consolidated Financial Statements and Notes for the year ended December 31, 2002, which were reformatted to reflect the transfer of electric transmission operations to the Energy segment from the Delivery segment effective Jan uary 1, 2003. References to the Consolidated Financial Statements and Notes for the year ended December 31, 2002 refer to those included in the May 9, 2003 current report on Form 8-K.

In the opinion of 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 September 30, 2003 and its results of operations for the three and nine months and cash flows for the nine months ended September 30, 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 Consolidated Financial Statements and the reported amounts of revenues 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 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, timing of electric fuel and energy purchases and other factors.

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

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.

The effect of adopting SFAS No. 143 for the three and nine months ended September 30, 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $5 million and $153 million for those periods, respectively. The $153 million increase for the nine months ended September 30, 2003 is comprised of a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle and an increase in income before the cumulative effect of a change in accounting principle of $14 million.

In October 2002, the Emerging Issues Task Force (EITF) reached consensus on EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. As a result, certain energy-related commodity contracts that are held in connection with the Company's energy trading activities are no longer subject to fair value accounting. The affected contracts are those energy-related contracts that are not considered to be derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Energy-related contracts affected by this change are now subject to accrual accounting and recognized as revenue or expense at the time of contract performance, settlement or termination. The new rules were effective for energy-related contracts initiated prior to October 25, 2002 as of January 1, 2003, and required that the Company record a cumulative effect of a change in accounting principle r esulting in an after-tax loss of $55 million.

EITF 02-3 also affects the classification of gains and losses arising from derivative energy contracts no longer considered to be held for trading purposes. Under the provisions of EITF 02-3, 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 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.

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Effective July 1, 2003, the Company adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. The standard requires an issuer to classify certain financial instruments with characteristics of both liabilities and equity as a liability if the issuer is obligated to redeem such instruments. As a result, beginning July 1, 2003, the Company presents the mandatorily redeemable preferred securities issued by a subsidiary trust as long-term debt and related distributions as interest expense. These securities are described in Note 16 to the Consolidated Financial Statements for the year ended December 31, 2002.

Amendment of SFAS No. 133

During the second quarter of 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 reflects decisions made by the FASB and its Derivatives Implementation Group in connection with issues raised about the application of SFAS No. 133. Generally, changes resulting from SFAS No. 149 apply to contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although industry efforts to interpret SFAS No. 149 are ongoing, the Company believes that SFAS 149 will not have a material impact on its results of operations and financial position based on an assessment of currently available information.

Note 4.     Recently Issued Accounting Standards and Other Accounting Matters

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, (FIN 46) which addresses the consolidation of "variable interest entities"(VIEs). VIEs are entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. In October 2003, the FASB decided to permit more time for the implementation of FIN 46 and now requires adoption as of December 31, 2003.

Leases with Special Purpose Entities

The Company has entered into agreements with another Dominion subsidiary (lessor) in order to finance and lease a new power generation facility. Under existing accounting guidance, neither the project assets nor related debt would be reported on the Company's Consolidated Balance Sheets upon inception of the lease. The project was completed on July 1, 2003, at which time the facility was put into service and the lease agreement became effective. Under FIN 46, the lessor is considered a VIE and the Company has been determined to be the primary beneficiary and will therefore consolidate it in the preparation of its Consolidated Financial Statements.

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Other SFAS No. 133 Guidance

In connection with a request to reconsider an interpretation of SFAS No. 133, the FASB issued Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of 'Not Clearly and Closely Related' in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. Under C20, criteria are established to determine if a contract's pricing terms that contain broad market indices (e.g., the consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has several contracts that are subject to the C20 guidance. The Company estimates the cumulative effect of adopting C20 to be an after-tax charge of approximately $101 million, representing the fair value of the contracts as of October 1, 2003. Price adjustments in these contracts satisfy the normal purchase and sale criteria as defined under C20.

The Company adopted SFAS No. 143 on January 1, 2003. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.

In accordance with applicable regulatory uniform system of accounts and as permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company's electric utility operations recognize a provision for the cost of future asset removal activities subject to cost-of service rate regulation, even if no legal obligation to perform such activities exists. The periodic provision is recorded as a component of depreciation expense on the income statement, resulting in a credit being recorded in accumulated depreciation and amortization on the balance sheet. At September 30, 2003 and December 31, 2002, the Company's accumulated depreciation and amortization included $356 million and $375 million, respectively, representing regulatory liabilities for the estimated amounts collected from customers for the future cost of such asset removal activities.

A question has recently arisen about whether these regulatory liabilities should continue to be classified in accumulated depreciation and amortization or be reported as liabilities on the balance sheet. If, as a result of the resolution of this issue, reclassification of this accumulated provision for future removal costs is required, the Company's accumulated depreciation would decrease and its regulatory liabilities would increase. While resolution of this issue may affect the balance sheet classification of these items, there would be no impact on the Company's results of operations or cash flows.

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The composition of revenue from non-regulated electric sales, non-regulated gas sales and other revenue has changed effective January 1, 2003. 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.

Note 6. Comprehensive Income

The following table presents total comprehensive income:

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The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income in the Consolidated Balance Sheet at September 30, 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 interest rates and foreign exchange rates. The effect of amounts being reclassified from other comprehensive income 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.

Dominion, Consolidated Natural Gas Company (CNG) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion: a $1.25 billion 364-day revolving credit facility executed in May 2003 and terminates in May 2004; and a $750 million 3-year revolving credit facility executed in May 2002 and terminates in May 2005. The 3-year facility can also be used to support up to $200 million of letters of credit. The remaining joint credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the Company; and for other general corporate purposes.

At September 30, 2003, outstanding commercial paper under the companies' combined commercial paper programs was $875 million and total outstanding letters of credit supported by the 3-year facility were $88 million: $17 million issued on behalf of an unregulated subsidiary of the Company and $71 million issued on behalf of other Dominion subsidiaries. At September 30, 2003, capacity available under the two credit facilities was $1.0 billion.

In the first quarter of 2003, the Company issued $400 million of 4.75 percent senior notes due March 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

The Company repaid $10 million of medium-term notes in the first quarter of 2003, $200 million of 6.625 percent mortgage bonds in the second quarter of 2003 and $16 million of medium-term notes in the third quarter of 2003.

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Note 9. Asset Retirement Obligations

The following table describes the changes to the Company's asset retirement obligations during the nine months ended September 30, 2003:

The Company has established external trusts dedicated to funding the future decommissioning of its nuclear plants. At September 30, 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $945 million.

Had the provisions of SFAS No. 143 been applied for the following periods in 2003 and 2002, the Company's net income would have been as follows:

Note 10. 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 for the year ended December 31, 2002, nor have any significant new matters arisen during the nine months ended September 30, 2003.

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In relation to a Notice of Violation received by the Company in 2000 from the U.S. Environmental Protection Agency (EPA) and related proceedings, the Company, the U.S. Department of Justice, the EPA, the states of Virginia, West Virginia, Connecticut, New Jersey and New York agreed to a settlement in April 2003 in the form of a proposed Consent Decree. The Virginia federal district court entered the final Consent Decree in October 2003, resolving the underlying actions. The settlement includes payment of a $5 million civil penalty, an obligation to fund $14 million for environmental 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 Conse nt Decree. As of September 30, 2003, the Company had accrued $19 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

The Company enters into long-term purchase commitments for fuel used in electric generation. As of September 30, 2003, estimated fuel purchase commitments are as follows: 2004-$360 million; 2005-$220 million; 2006-$160 million; and 2007-$80 million. The Company recovers the costs of these purchases in regulated rates through June 30, 2007.

At September 30, 2003, the Company had issued $67 million of surety bonds, of which $57 million is associated with the financial assurance requirements imposed by the Nuclear Regulatory Commission 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.

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

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Through the same unregulated subsidiary, the Company is involved in facilitating Dominion's enterprise risk management strategy. In connection with this strategy, the Company's unregulated subsidiary 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's unregulated subsidiary 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 September 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $80 million and $84 million, respectively and de rivative liabilities with Dominion affiliates of $63 million and $90 million, respectively. The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

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 for the three months ended September 30, 2003 and 2002 was approximately $70 million and $67 million, respectively, and for the nine months ended September 30, 2003 and 2002 was approximately $217 million and $198 million, respectively. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of services provided by the Company to Dominion Services and other Dominion affiliates was approximately $7 million and $8 million for the three months ended September 30, 2003 and 2002, respectively, and, for the nine months ended September 30, 2003 and 2002, was approximately $21 million and $22 million, respectively.

The Company and its subsidiaries have made certain borrowings from Dominion pursuant to a short-term demand note. At September 30, 2003 and December 31, 2002, net outstanding borrowings under this note totaled $142 million and $100 million, respectively. Interest charges related to this note during the three and nine months ended September 30, 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.

An unregulated subsidiary of the Company, at its sole discretion, has provided at September 30, 2003 and December 31, 2002, approximately $8 million and $31 million, respectively, 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.

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After receiving regulatory approval, on October 1, 2003, the Company assigned energy contracts with counterparties to another Dominion subsidiary in connection with Dominion's plan to transfer certain wholesale power marketing activities that occur outside of the Company's service territory. In exchange for the transfer of the contracts, the Company will receive $13 million representing the net fair value of the contracts. The transferred contracts involve the delivery of electric energy in the following years:

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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 operations formerly managed by Delivery. Amounts for 2002 have been restated to reflect the transfer of electric transmission operations to Energy effective January 1, 2003. The transmission operations continue to be subject to the requirements of SFAS No. 71.

Delivery manages the Company's electric distribution 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 transfer of electric transmission operations to Energy effective January 1, 2003.

On May 9, 2003, the Company filed a current report on Form 8-K that included its Consolidated Financial Statements and Notes for the year ended December 31, 2002, as well as certain portions of MD&A, which were reformatted to reflect the transfer of electric transmission operations to the Energy segment from the Delivery segment effective January 1, 2003. References to the Consolidated Financial Statements and Notes for the year ended December 31, 2002 refer to those included in the May 9, 2003 current report on Form 8-K.

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; governmental regulations; cost of environmental compliance; inherent risk in the operation of nuclear facilities; 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; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting s tandards; the risks of operating businesses in regulated industries that are becoming deregulated; transfer of control over the Company's transmission facilities to a regional transmission entity; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation and deflation). 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 and property damage that require the Company to incur additional expenses.

The Company is subject to complex governmental 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.

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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.

Capped electric rates in Virginia may be insufficient to allow full recovery of stranded and other costs. Under the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act), the Company's base rates (excluding, generally, 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 in the Company's Annual Report on Form 10-K for the y ear ended December 31, 2002 and Note 21 to the Consolidated Financial Statements for the year ended 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 risks include the cost of and the Company's ability to maintain adequate reserves for decommissioning, plant maintenance costs, terrorism, spent nuclear fuel disposal costs 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 contracts 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, see Management's Discussion and Analysis of Financial Condition and Results of Operations-Market Rate Sensitive Instruments and Risk Management in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 and Notes 2 and 9 to the Consolidated Financial Statements for the year ended December 31, 2002.

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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 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 creditworthiness 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.

Changing rating agency requirements could negatively affect the Company's growth and business strategy. As of November 3, 2003, the Company's senior secured debt was rated A-, stable outlook, by Standard & Poor's and A2, stable outlook, by 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 future changes in accounting standards or practices may have on public companies in general or the energy industry or in its operations specifically. New accounting standards could be issued by the FASB or the SEC which could impact the way the Company records 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.

Critical Accounting Policies

As of September 30, 2003, other than the adoption of SFAS No. 143, 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.

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Asset Retirement Obligations

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 September 30, 2003, the Company's asset retirement obligations totaled $728 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.

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 effective January 1, 2003. All variances are stated as actual results for the three and nine months ended September 30, 2003, as compared to the actual results for the same periods of 2002.

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The impact of Hurricane Isabel and milder weather decreased net income for the three months ended September 30, 2003, as compared to the same period in 2002. Regulated electric sales decreased, reflecting 11 percent fewer cooling degree days in the third quarter of 2003 and lost revenue due to hurricane-related outages, partially offset by revenue from serving approximately 38,000 new electric customers over the last twelve months. This decrease in regulated electric sales revenue was offset by increases in other revenue categories.

Total operating expenses increased, compared to the third quarter of 2002, reflecting primarily the impact of Hurricane Isabel on operations and maintenance expense in the third quarter of 2003. In addition, operating expenses increased as a result of the recognition of previously deferred fuel costs in connection with a proposed settlement of the 2003 Virginia fuel rate case and the effect of reclassifying purchases of other energy commodities as a result of implementing EITF 02-3, beginning in 2003.

Other income increased primarily due to the adoption of SFAS 143. The decrease in interest and related charges primarily included the impact of comparably lower interest rates in 2003 and a reduction in interest accrued, resulting from the favorable resolution of previously outstanding income tax issues.

Nine Months Ended September 30, 2003

Net income increased for the nine months ended September 30, 2003, as compared to the same period in 2002. The increase includes a net $84 million after-tax gain for changes in accounting principles, reflecting the adoption of SFAS No. 143 and EITF 02-3. Income before the cumulative effect of changes in accounting principle decreased slightly, reflecting the impact of Hurricane Isabel and milder weather. Regulated electric sales increased for the first nine months of 2003, primarily as a result of comparably colder weather during the first quarter, partially offset by milder weather in the second and third quarters. Customer growth and higher fuel rate recoveries also contributed to the increase in regulated electric sales. The Company's non-regulated electric revenue decreased, and non-regulated gas revenue and other revenue increased for the first nine months of 2003.

Total operating expenses increased reflecting primarily the impact of Hurricane Isabel on operations and maintenance expense in the third quarter of 2003. Higher electric fuel and energy purchases are due primarily to higher costs reflected in fuel rate recoveries, certain reclassifications required by the adoption of EITF 02-3 and a charge to recognize previously deferred fuel costs in connection with a proposed settlement of the 2003 Virginia fuel rate case. In addition, other purchased energy commodities are reported as expenses in 2003 due to implementing EITF 02-3.

Changes in other income and interest and related charges were attributable to the same factors impacting the third quarter.

Adoption of EITF 02-3

The adoption of EITF 02-3 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:

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• Cumulative effect of adopting EITF 02-3: For non-derivative energy-related contracts initiated prior to October 25, 2002 in connection with the Company's energy trading activities and previously designated as trading under prior accounting guidance, the Company recognized an after-tax loss of $55 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 prior accounting guidance, 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.

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. 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. Under SFAS No. 143, the Company records accretion expense related to its asset retirement obligations in other operations and maintenance expense. Under its former accounting policy in 2002, the Company recorded accretion expense related to its accumulated provision for nuclear decommissioning in other income.

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Energy's net income contribution decreased $28 million to $189 million for the three months ended September 30, 2003, as compared to the same period in 2002.

The overall increase in operating revenue reflects the following:

• A decrease in regulated electric sales revenue, primarily resulting from milder temperatures ($56 million), a reallocation of base rate revenue between Energy and Delivery, effective January 1, 2003 ($25 million) and loss of base rate revenue during outages caused by Hurricane Isabel, offset by customer growth.
• An increase in non-regulated electric sales revenue, reflecting primarily higher margins on settled contracts, the effects of favorable changes in the fair value of unsettled derivative contracts and the impact of adopting EITF 02-3.
• An increase in non-regulated gas sales revenue, net of applicable trading purchases, primarily reflecting the effect of higher margins on settled contracts and favorable changes in the fair value of unsettled derivative contracts and the impact of adopting EITF 02-3. The increase includes $36 million related to financial derivative 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 natural gas production.
• An increase in other revenue, primarily reflecting revenue from sales of coal. This increase largely reflects the impact of adopting EITF 02-3.

The overall increase in operating expenses primarily reflects the following:

• An increase in electric fuel and energy purchases, net, reflecting the recognition of $14 million of previously deferred fuel costs in connection with a proposed settlement of the 2003 Virginia fuel rate case and $8 million associated with the reclassification of purchases under certain derivative contracts that are no longer considered held for trading purposes under EITF 02-3.
• A decrease in purchased electric capacity, reflecting scheduled rate reductions on certain utility supply contracts ($13 million) and lower purchased capacity for utility operations ($8 million).
• An increase in other purchased energy commodities, reflecting the reclassification of purchases under certain gas and coal contracts that are no longer considered held for trading purposes after the implementation of EITF 02-3.
• An increase in other operations and maintenance expense reflecting an increase in general and administrative expenses such as wages and benefit costs ($8 million) and an increase for the accretion of the nuclear decommissioning asset retirement obligation beginning in 2003 ($10 million). It also reflects an increase due to the change in fair value of unsettled derivative contracts related to adopting EITF 02-3 ($13 million).

Other income increased reflecting net realized gains from the Company's decommissioning trusts in 2003 and as a result of accretion expense related to the Company's provision for decommissioning being reported in other income in 2002.

Energy's net income contribution increased $63 million to $505 million for the nine months ended September 30, 2003, as compared to the same period in 2002.

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The overall increase in operating revenue primarily reflects the following:

• A decrease in regulated electric sales revenue, primarily resulting from a reallocation of base rate revenue between Energy and Delivery ($63 million), milder summer temperatures ($28 million), the loss of base rate revenue during outages caused by Hurricane Isabel ($13 million) and other factors ($17 million). These decreases were partially offset by increased fuel rate recoveries ($49 million) and customer growth ($30 million). Fuel rate recoveries are generally offset by a comparable increase in fuel expense and do not materially affect net income.
• A decrease in non-regulated electric sales, net of applicable trading purchases, reflecting a decrease primarily due to the effects of unfavorable changes in the fair value of derivative contracts held and not yet settled, lower margins and the impact of adopting EITF 02-3.
• An increase in non-regulated gas revenue, reflecting an increase due to higher margins on settled contracts, the effect of favorable changes in fair value of unsettled derivative contracts and the impact of adopting EITF 02-3. The increase includes $48 million related to financial derivative 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 natural gas production.
• An increase in other revenue, primarily reflecting revenue from sales of coal. This increase largely reflects the impact of adopting EITF 02-3.

The overall increase in operating expenses primarily reflects the following:

• An increase in electric fuel and energy purchases, net, reflecting the recognition of $14 million of previously deferred fuel costs in connection with a proposed settlement of the 2003 Virginia fuel rate case; $49 million due to higher fuel rate recoveries; $19 million for increased purchases not subject to fuel rate recoveries; and $34 million reflecting the reclassification of purchases under certain derivative contracts that are no longer considered held for trading purposes under EITF 02-3.
• A decrease in purchased electric capacity, reflecting scheduled rate reductions on certain utility supply contracts ($35 million) and lower purchased capacity for utility operations ($19 million).
• An increase in other purchased energy commodities, reflecting the reclassification of purchases under certain gas and coal contracts that are no longer considered held for trading purposes after the implementation of EITF 02-3.
• An increase in other operations and maintenance expense, primarily reflecting an increase in general and administrative expenses ($36 million), including higher wages and benefit costs, and an increase in outage and maintenance costs primarily at the nuclear power stations ($31 million) and an increase for the recognition of accretion expense related to nuclear decommissioning asset retirement obligations beginning in 2003 ($29 million). Partially offsetting these items was a decrease due to the adoption of EITF 02-3 ($65 million), which now reflects changes in the fair value of certain derivative energy contracts no longer considered held for trading purposes under EITF 02-3.
• A decrease in depreciation expense, primarily reflecting a change in the presentation of expenses associated with asset retirement obligations. 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.
• An increase in other taxes, primarily reflecting 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 nine months of 2003.

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Other income increased reflecting net realized gains from the Company's decommissioning trusts in 2003 and as a result of accretion expense related to the Company's provision for decommissioning being reported in other income in 2002.

Selected Information-Energy Trading Activities

See Selected Information-Energy Trading Activities in the reformatted portion of MD&A included in the current report on Form 8-K filed on May 9, 2003 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 nine months ended September 30, 2003 follows:

The balance of net unrealized gains and losses recognized for the Company's energy-related derivative instruments held for trading purposes at September 30, 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.

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Third Quarter 2003 Results

Delivery's net income contribution decreased $6 million to $93 million for the third quarter ended September 30, 2003, as compared to the same period in 2002.

The increase in regulated electric sales revenue primarily reflects a reallocation of base rate revenue between Energy and Delivery, effective January 1, 2003 ($25 million) and customer growth. These increases were partially offset by the effects of milder temperatures ($24 million) and loss of base rate revenue during outages caused by Hurricane Isabel.

The increase in operating expenses primarily reflects an increase in other operations and maintenance expense, reflecting primarily higher expenditures for contractors and service restoration costs for storms other than Hurricane Isabel.

Delivery's net income contribution increased $20 million to $222 million for the nine months ended September 30, 2003, as compared to the same period in 2002.

The overall increase in operating revenue primarily reflects an increase in regulated electric sales revenue, primarily resulting from a reallocation of base rate revenue between Energy and Delivery, effective January 1, 2003 ($63 million) and customer growth ($13 million). These increases were partially offset by comparably milder temperatures in the second and third quarters ($12 million), the loss of base rate revenue during outages caused by Hurricane Isabel ($6 million) and other factors ($5 million). The decrease in other revenue primarily reflects a change in allocation of late payment fees and lower miscellaneous service revenues.

The increase in operating expenses primarily reflects an increase in other operations and maintenance expense, primarily reflecting higher expenditures for contractors and service restoration costs for storms other than Hurricane Isabel.

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Net expense for the first nine months of 2003 includes the following:

• $129 million of operations and maintenance expense ($80 million after tax), representing the cost of restoration activities following Hurricane Isabel.
• $8 million ($5 million after tax) related to severance costs for workforce reductions, including $3 million attributable to the Energy segment and $5 million attributable to the Delivery segment.
• $139 million after-tax gain, representing the cumulative effect of a change in accounting principle from adoption of SFAS No. 143, including $140 million after-tax gain attributable to the Energy segment and $1 million after-tax loss attributable to the Delivery segment.
• $55 million after-tax loss, representing the cumulative effect of a change in accounting principle from adoption of EITF 02-3, all of which was related to Energy's operations.

For more information on the cumulative effect of the changes in accounting principles, see Note 3 to the Consolidated Financial Statements.

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.

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As presented on the Company's Consolidated Statements of Cash Flows, net cash flow provided by operating activities totaled approximately $1.1 billion and $870 million during the nine months ended September 30, 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 to 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.

External Sources of Liquidity

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 September 30, 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.

In the first quarter of 2003, the Company issued $400 million of 4.75 percent senior notes due March 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

The Company repaid $10 million of medium-term notes in the first quarter of 2003, $200 million of 6.625 percent mortgage bonds in the second quarter of 2003 and $16 million of medium-term notes in the third quarter of 2003.

Dominion, Consolidated Natural Gas Company (CNG) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion: a $1.25 billion 364-day revolving credit facility executed in May 2003 and terminates in May 2004; and a $750 million 3-year revolving credit facility executed in May 2002 and terminates in May 2005. The 3-year facility can also be used to support up to $200 million of letters of credit. The remaining joint credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the Company; and for other general corporate purposes.

At September 30, 2003, outstanding commercial paper under the companies' combined commercial paper programs was $875 million and total outstanding letters of credit supported by the 3-year facility were $88 million: $17 million issued on behalf of an unregulated subsidiary of the Company and $71 million issued on behalf of other Dominion subsidiaries. At September 30, 2003, capacity available under the two credit facilities was $1.0 billion.

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At September 30, 2003, net borrowings of the Company under the commercial paper program were $336 million, a decrease of $107 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

The Company and its subsidiaries have made certain borrowings from Dominion pursuant to a short-term demand note. At September 30, 2003 and December 31, 2002, net outstanding borrowings under this note totaled $142 million and $100 million, respectively. Interest charges related to this note for the three and nine months ended September 30, 2003 were not material.

Amounts Available under Shelf Registrations

At September 30, 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.

During the nine months ended September 30, 2003, investing activities resulted in a net cash outflow of $771 million. These activities included plant construction and other property expenditures of $656 million and nuclear fuel expenditures of $75 million. The plant expenditures related to generation-related projects totaled approximately $358 million and included costs related to environmental upgrades, nuclear reactor vessel head replacement expenditures and other capital improvements. The plant expenditures related to transmission and distribution projects totaled approximately $271 million, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled approximately $27 million. Investing activities also include $36 million of contributions to the Company's nuclear decommissioning trusts.

Contractual Obligations

As of September 30, 2003, other than scheduled maturities of new debt issued during the first nine months of 2003, and increased fuel commitments described in Note 10 to the Consolidated Financial Statements, 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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Future Issues

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.

Regional Transmission Organization (RTO)

In June 2003, the Company submitted an application to the Virginia State Corporation Commission (Virginia Commission), as required by the Virginia Restructuring Act, requesting authorization to become a transmission owning member of PJM Interconnection, LLC (PJM) and transfer operational control of the Company's electric transmission facilities to PJM on November 1, 2004. The Virginia Commission issued an order in September 2003 that directed the Company to provide additional information concerning its application and stated that it will not fully consider the application and make a final determination until the Federal Energy Regulatory Commission (FERC) has issued a final order addressing Standard Market Design. It is uncertain at this time when FERC will issue a final order on Standard Market Design. The Company has requested that the Virginia Commission eliminate the requirement to provide the additional information and establish a schedule to rule on its application without a FERC final order on Standar d Market Design.

Virginia Rate Matters

In July 2003, the Company filed its 2004 fuel factor application with the Virginia Commission, requesting a total fuel factor increase of $442 million that included a projected $308 million under-recovery balance as of December 31, 2003. The under-recovery balance was attributed to nuclear plant outages for reactor vessel head replacements, increased fuel prices and an unusually cold winter. The Company also suggested for consideration a cost recovery mechanism that would amortize the under-recovery balance over two years.

In October 2003, the Company reached a tentative settlement of its 2004 fuel factor application with the Virginia Attorney General's Office, the Virginia Commission Staff and other parties. If approved by the Virginia Commission, the settlement would reduce the total proposed increase by $56 million to $386 million. The reduction includes $42 million attributed to updated projected fuel cost forecasts and the recognition of $14 million of previously deferred fuel costs which would now not be recovered. The settlement includes a recovery period for the under-recovery balance over three and a half years. About $171 million of the $386 million would be recovered in 2004, $85 million in 2005, $87 million in 2006 and $43 million in the first six months of 2007. The proposed settlement addressed neither the extent to which the Company's trading activities may be taken into account by the Virginia Commission in future fuel factor determinations nor a party's recommended delay in the effective dat e of increased fuel rates to allow the General Assembly an opportunity to consider issues raised in this fuel factor proceeding.

The Company is still permitted under the Virginia Restructuring Act to request adjustments to its fuel rates until July 1, 2007.

In August 2003, the Virginia Commission issued its annual report on the status of the development of a competitive retail market for electric generation in Virginia. In the report, the Virginia Commission renewed its recommendation that the General Assembly suspend key portions of the Virginia Restructuring Act through the re-bundling of retail rates and suspension of the Act's retail choice provisions. The report also recommended extending the moratorium on Virginia utilities' participation in RTOs. In October 2003, the offices of the Governor and the Attorney General recommended that the Commission on Electric Utility Restructuring consider legislation that would extend the existing capped rates under the Virginia Restructuring Act for three years, until July 1, 2010, and phase out or eliminate wires charges.

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Proposed Pilot Programs

In September 2003, the Virginia Commission issued a final order approving three proposed electric retail access pilot programs, subject to several specified modifications. The pilot programs will run through the remainder of the capped rate period and make available to competitive service providers up to 500 megawatts of load, with expected participation of more than 65,000 customers from a variety of customer classes. Enrollment in the pilot programs is scheduled to begin in February 2004.

Environmental Matters

In relation to a Notice of Violation received by the Company in 2000 from the EPA and related proceedings, the Company, the U.S. Department of Justice, the EPA, the states of Virginia, West Virginia, Connecticut, New Jersey and New York agreed to a settlement in April 2003 in the form of a proposed Consent Decree. The Virginia federal district court entered the final Consent Decree in October 2003, resolving the underlying actions. The settlement includes payment of a $5 million civil penalty, an obligation to fund $14 million for environmental 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 September 30, 2003, the Company had accrued $19 m illion for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

In July 2003, the Company reached an agreement, pending regulatory approvals, to pay approximately $150 million for the termination of a long-term power purchase contract and the purchase of the related generating facility used by a non-utility generator to provide electricity to the Company. The Company expects the transaction to be completed in the fourth quarter of 2003, resulting in an after-tax charge in the range of $65 million to $85 million for the purchase and termination of the long-term power purchase contract. The transaction is part of an ongoing program which seeks to achieve competitive cost structures at the Company's power generating business.

Accounting Matters

Recently Issued Accounting Standards

The following new accounting standards will be adopted during the fourth quarter of 2003, as described in Note 4 to the Consolidated Financial Statements:

• FASB Interpretation No. 46, Consolidation of Variable Interest Entities, and
• SFAS No. 133 Implementation Issue No. C20, Interpretation of the Meaning of 'Not Clearly and Closely Related' in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.

PAGE 33

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. 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 processing 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. In addition, 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 currency 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 $32 million and $26 million in the fair value of its commodity-based financial derivative contracts held for trading purposes as of September 30, 2003 and December 31, 2002, respectively.

The Company's interest rate risk exposure does not differ materially from that discussed under Item 7A of its Annual Report on Form 10-K for 2002.

Foreign Exchange Risk

The Company's foreign exchange risk exposure does not differ materially from that discussed under Item 7A of its Annual Report on Form 10-K for 2002.

The Company is subject to investment price risk due to marketable securities held as investments in nuclear decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. The Company recognized a net realized gain (including investment income) of $25 million and a net unrealized gain of $46 million on decommissioning trust investments for the first nine months of 2003. For the year ended December 31, 2002, the Company recognized a net realized gain (including investment income) of $11 million and an unrealized loss of $67 million.

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Senior management, including the Chief Executive Officers and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. 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. There were no changes in the Company's internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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VIRGINIA ELECTRIC AND POWER COMPANY
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 the Company 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 June 2002, Wiley Fisher, Jr. and John Fisher filed a purported class action lawsuit against the Company and Dominion Telecom, Inc. (Dominion Telecom) in the U.S. District Court in Richmond, Virginia. The plaintiffs claim that the Company and Dominion Telecom strung fiber-optic cable across their land, along a Virginia Power electric transmission corridor without paying compensation. The plaintiffs are seeking damages for trespass and "unjust enrichment," as well as punitive damages from the defendants. The named plaintiffs purport to "represent a class . . . consisting of all owners of land in North Carolina and Virginia, other than public streets or highways, that underlies Virginia Power's electric transmission lines and on or in which fiber optic cable has been installed." In August 2003, the federal district court issued an order granting the named plaintiffs' motion for class certification. The U.S. Court of Appeals for the Fourth Circuit denied Dominion's petition for appeal and its petition for reh earing on the class certification issue. The outcome of the proceeding, including an estimate as to any potential exposure, cannot be predicted at this time.

In connection with a Notice of Violation received by Virginia Power in 2000 from the U.S. Environmental Protection Agency and related proceedings, the Virginia federal district court entered the final Consent Decree in October 2003 involving Dominion, the U.S. government and five states. See Environmental Matters in the MD&A of this Form 10-Q for further information relating to this development.

At a special meeting of shareholders held on October 23, 2003, Dominion Resources, Inc., the sole holder of all of the common stock of the Company, voted to amend the Company's Articles of Incorporation to delete obsolete sections and amendments concerning various series of preferred stock that are no longer outstanding and will not be reissued.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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