SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

____________

FORM 10-Q
____________

X    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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 July 31, 2003, the latest practicable date for determination, 177,932 shares of common stock, without par value, of the registrant were outstanding.

PAGE 2

_______________

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

PAGE 4

  _______________

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.

PAGE 5

_______________

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.

PAGE 6

_______________

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

PAGE 7

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 for the year ended December 31, 2002. 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 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.

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 June 30, 2003 and its results of operations for the three and six months and cash flows for the six months ended June 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 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 and other factors.

PAGE 8

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

Depreciation

In the second quarter of 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 $8 million and $24 million for the three and six months ended June 30, 2003, respectively.

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.

PAGE 9

The EITF 98-10 rescission was effective for non-derivative energy-related contracts initiated after October 25, 2002. For those non-derivative energy-related contracts initiated prior to October 25, 2002 in connection with the Company's energy trading activities, 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 02-3, 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-related contracts that are held in connection with the Company's energy trading activities, including amounts realized upon settlement, in revenue on a net basis. 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.

As described more fully in Note 4 to the Consolidated Financial Statements for the year ended December 31, 2002, in January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46 addresses consolidation by business enterprises of entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. The initial adoption of the provisions of FIN 46 on July 1, 2003 by the Company will not impact its results of operations. A description of the Company's involvement with variable interest entities follows:

PAGE 10

As previously discussed in Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002, the Company 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 variable interest entity and the Company has been determined to be the primary beneficiary and will therefore consolidate it in the preparation of its Consolidated Financial Statements. Based upon total project costs expected to be incurred for the project, consolidation of this variable interest entity, beginning July 1, 2003, will result in an additional $370 million in property, plant and equipment and related debt.

Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

As described more fully in Note 16 to the Consolidated Financial Statements for the year ended December 31, 2002, the Company established Virginia Power Capital Trust II (trust) which sold trust preferred securities to third party investors. The Company received the proceeds from the sale of the trust preferred securities in exchange for junior subordinated notes issued by the Company to be held by the trust. Under existing accounting guidance, the Company consolidates the trust in the preparation of its Consolidated Financial Statements because it has a majority voting interest in the trust. Under FIN 46, the trust is considered a variable interest entity. Based on the trust structure as of July 1, 2003, the Company is not considered the primary beneficiary of the trust and thus will cease consolidating the trust beginning on July 1, 2003. Under these circumstances, the Company's Consolidated Balance Sheets will no longer reflect the trust preferred securities, but instead will report the junior subordinate d instruments held by the trust as long-term debt. The Company is currently evaluating changes to the trust structure that, if implemented, could possibly result in a determination that the Company is the primary beneficiary of the trust, thus requiring the Company to resume the consolidation of the trust in the preparation of its Consolidated Financial Statements. If the trust were to be consolidated subsequent to July 1, 2003, the trust preferred securities would be presented as liabilities as described under the Liabilities and Equity Classification section below.

In May 2003, FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The standard requires an issuer to classify and measure certain freestanding financial instruments with characteristics of both liabilities and equity as a liability if that financial instrument embodies an obligation requiring the issuer to redeem the financial instruments by transferring its assets. Under this standard, obligated mandatorily redeemable preferred securities would be reported as liabilities. However, as described under the Consolidation of Variable Interest Entities section above, consolidation of the underlying trust must be evaluated under FIN 46 before application of this Statement.

PAGE 11

On April 30, 2003, 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 presently evaluating the potential impact of SFAS No. 149 on its results of operations and financial position.

In connection with the January 2003 EITF meeting, FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the DIG's C11 guidance, relates to contracts with pricing terms that include broad market indices. In particular, that guidance discusses whether a contract's pricing terms that contain broad market indices (e.g., consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has certain power purchase and sale contracts subject to this guidance. On June 25, 2003, 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, to clarify the guidance applicable to these circumstances. Under C20, criteria are established to determine if the price adjustment is not clearly and closely related to the underlying asset being purchased or sold under the contract, including whether the price adjustment is extraneous or disproportionate to the fair value of the underlying asset or direct component thereof. Under C20, the assessment should include both qualitative and quantitative considerations and should be performed only at inception of the contract. The provisions of C20 should be applied prospectively for all new and existing contracts beginning the first fiscal quarter after July 10, 2003. The Company has several power contracts that are subject to this guidance but has not completed its assessment of whether those contracts meet the provisions of C20. Assuming such contracts qualify as normal purchase or sale contracts under the new guidance, the Company will record these power contracts at estimated fair value, determined at the time of implementing C20, and will report the change as the cumulative effect of a change in accounting principle.

EITF 01-8

In May 2003, the EITF reached a consensus on Issue No. 01-8, Determining Whether an Arrangement Contains a Lease (EITF 01-8). Under the provisions of EITF 01-8, arrangements conveying the right to control the use of specific property, plant or equipment must be evaluated to determine whether they contain a lease. The Company enters into contracts for the long-term purchase and sale of electric generation capacity and energy that, depending on the facts and circumstances, could be subject to EITF 01-8. The new rules will be applied prospectively to contracts entered into or modified after July 1, 2003.

PAGE 12

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.

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

Non-regulated 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 non-regulated electric sales, non-regulated gas sales and other revenue has changed since being described in Note 5 to the Consolidated Financial Statements for the year ended December 31, 2002. The changes were effective January 1, 2003 and related to the impact of adopting EITF 02-3 on the reporting of revenue and expenses for energy trading activities, as described in Note 3 and as follows:

For derivative contracts previously 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 for non-regulated electric sales, non-regulated gas sales and other revenue, as applicable, while gross purchase contract settlements are reported in expenses.

For non-derivative contracts previously presented in revenue on a net basis: Non-derivative energy-related contracts, previously subject to fair value accounting under EITF 98-10, are now subject to accrual accounting. Revenue for non-regulated electric sales, non-regulated gas sales and other revenue now include settlements of sales contracts at the time of contract performance, settlement or termination, on an accrual basis. These contracts will no longer be reported at fair value in the Company's Consolidated Financial Statements.

PAGE 13

Note 6.     Liability for 2001 Severance Costs

The Company recognized costs and the related liability associated with employee severances in 2001. The change in this liability during the six months ended June 30, 2003 is presented below:

For additional information, see Note 6 to the Consolidated Financial Statements for the year ended December 31, 2002.

The following table presents total comprehensive income:

________________

Note 8. Derivatives and Hedge Accounting

PAGE 14

The following table presents selected information related to cash flow hedges included in Accumulated Other Comprehensive Income (AOCI) in the Consolidated Balance Sheet at June 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 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.

Dominion, Consolidated Natural Gas (CNG) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion. In May 2003, Dominion, CNG and the Company entered into a joint credit facility that allows aggregate borrowings of up to $1.25 billion. This credit facility replaced the $1.25 billion 364-day credit facility that matured during the second quarter of 2003. In May 2002, Dominion, CNG and the Company entered into a $750 million 3-year revolving credit facility that terminates in May 2005. The credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the Company; and other general corporate purposes.

The 3-year facility can also be used to support up to $200 million of letters of credit. At June 30, 2003, total outstanding letters of credit supported by the 3-year facility were $199 million, which were issued on behalf of CNG and other Dominion subsidiaries.

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 and repaid $10 million of maturing medium-term notes.

In April 2003, the Company repaid $200 million of 1993 Series B, 6.625 percent mortgage bonds.

See Note 4 for a discussion of the impact of FIN 46 on reported debt amounts, effective July 1, 2003, related to assets leased from another Dominion subsidiary and preferred securities issued by a subsidiary trust.

PAGE 15

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

The Company has established external trusts dedicated to funding the future decommissioning of its nuclear plants. At June 30, 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $928 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:

Had the provisions of SFAS No. 143 been applied for the following periods, the asset retirement obligations would have been as follows:

As permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company accrues 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 June 30, 2003 and December 31, 2002, the Company's accumulated depreciation and amortization included $390 million and $375 million, respectively, representing the estimated future cost of such removal activities.

See Note 3 for further discussion of the adoption of SFAS No. 143.

PAGE 16

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 for the year ended December 31, 2002, nor have any significant new matters arisen during the six months ended June 30, 2003.

As previously reported in Note 21 to the Consolidated Financial Statements 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. The EPA public comment period has now closed. It is anticipated that in the near future 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 f or 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 June 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.

At June 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 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.

PAGE 17

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 affiliated commodity transactions are presented below:

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 June 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $120 million and $84 million and derivative liabilities with Dominion affiliates of $87 million and $90 mil lion, 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 in the second quarter of 2003 and 2002 was approximately $75 million and $67 million, respectively, and in the first six months of 2003 and 2002 was approximately $147 million and $131 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 $8 million and $10 million for the three months ended June 30, 2003 and 2002, respectively, and, for the six months ended June 30, 2003 and 2002, was approximately $14 million and $15 million, respectively.

The Company and its subsidiaries have made certain borrowings from Dominion pursuant to a short-term demand note. At June 30, 2003 and December 31, 2002, net outstanding borrowings under this note totaled $215 million and $100 million, respectively. Interest charges related to this note in the second quarter and the first six months 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 the Company's Possum Point station in Prince William County, Virginia, see Note 21 to the Consolidated Financial Statements for the year ended December 31, 2002. Also, see Note 4 for a discussion of the impact of FIN 46 on this lease arrangement.

PAGE 18

An unregulated subsidiary of the Company, at its sole discretion, has provided at June 30, 2003 and December 31, 2002, approximately $17 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.

For additional information on transactions with related parties, see Note 24 to the Consolidated Financial Statements for the year ended December 31, 2002.

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. However, to the extent a counterparty has fully prepaid transactions by transferring cash or posting letters of credit, the Company has excluded such amounts from its gross credit exposure. 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, made available by counterparties as a result of exceeding agreed-upon credit limits. Presented below is a summary of the Company's gross and net credit exposure as of June 30, 2003. The amounts presented exclude accounts receivable for regulated electric retail distribution and regulated electric transmission services, amounts receivable from affiliated companies and the Company's provision for credit losses. See Note 23 to the Consolidated Financial Statements for the year ended December 31, 2002 for a discussion of the nature of the Company's credit risk exposures.

_______________________

PAGE 19

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 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 reduction; and 3) the 2003 cumulative effect of changes in accounting principle (see Note 3).

See Note 26 to the Consolidated Financial Statements for the year ended December 31, 2002 for more information about the Company's segments.

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; 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 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, property damage and requiring 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.

PAGE 21

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 Utility 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 year ended December 31, 2002 and Not e 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 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 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.

PAGE 22

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 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.

Changing rating agency requirements could negatively affect the Company's growth and business strategy. As of August 1, 2003, the Company's senior secured debt is 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 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 June 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. See Note 3 and Adoption of EITF 02-3 below for new accounting requirements associated with the accounting for energy trading contracts.

In addition, see Note 4 to the Consolidated Financial Statements for a discussion of other new accounting standards that will be adopted after June 30, 2003 and their impact on the Company.

PAGE 23

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 June 30,
2003, the Company's asset retirement obligations totaled $719 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. All variances are stated as actual results for the three and six months ended June 30, 2003, as compared to the actual results for the same periods of 2002.

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

PAGE 24

Net income decreased $42 million to $133 million for the three months ended June 30, 2003, as compared to the same period in 2002. Regulated electric sales decreased, reflecting milder weather conditions, partially offset by customer growth. This decrease in regulated electric sales revenue was partially offset by higher other revenue.

Total operating expenses increased, compared to the second quarter of 2002, reflecting higher electric fuel and energy purchases and higher other taxes. In addition, as a result of implementing EITF 02-3, $74 million of other purchased energy commodities are reported as expenses in 2003. These increases were partially offset by decreases in purchased electric capacity and depreciation expenses, as compared to the second quarter of 2002. There was no significant change in the Company's effective income tax rate.

Six Months Ended June 30, 2003

Net income increased $195 million to $524 million for the six months ended June 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. Regulated electric sales increased for the first six months of 2003, as a result of comparably colder weather during the first quarter, customer growth and higher fuel rate recoveries. The Company's non-regulated electric revenue decreased, and non-regulated gas revenue and other revenue increased for the first six months of 2003.

Total operating expenses increased, compared to the first six months of 2002, primarily due to higher electric fuel and energy purchases and higher other taxes. In addition, as a result of implementing EITF 02-3, $142 million of other purchased energy commodities are reported as expenses in 2003. These increases were partially offset by decreases in purchased electric capacity and depreciation expenses, as compared to the first six months of 2002. There was no significant change in the Company's effective income tax rate.

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:

• 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 EITF 98-10, 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.

PAGE 25

• 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.

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 income taxes increased for the three and six months ended June 30, 2003, as compared to the same period in 2002, by approximately $3 million and $7 million, respectively. 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 and $16 million for the three and six months ended June 30, 2003, respectively. Under SFAS No. 143, the Company also recorded $10 million and $19 million in three and six months ended June 30, 2003, respectively, representing accretion of its asset retirement obligations, in other operations and maintenance expense. Under its former accounting policy in 2002, the Company recorded $5 million and $10 million for th e three and six-month periods 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

Second Quarter 2003 Results

Energy's net income contribution decreased $51 million to $72 million for the three months ended June 30, 2003, as compared to the same period in 2002. The decrease in net income primarily reflects an $87 million increase in operating expenses and a $33 million decrease in income tax expense. The decrease also reflects a $4 million decrease in operating revenue and a $7 million increase in other income.

Regulated electric sales revenue decreased $60 million. Comparably milder weather during the second quarter of 2003 effectively decreased regulated electric sales $48 million, partially offset by the contribution of customer growth of $9 million. A reallocation of base rate revenue between the Delivery and Energy segments, effective January 1, 2003, decreased Energy's regulated electric sales revenue by approximately $20 million. Other factors decreased regulated electric sales by $1 million. There were 42 percent fewer cooling degree days in the second quarter of 2003, as compared to 2002. There were approximately 37,000 new electric customers added over the last twelve months.

Non-regulated electric sales revenue, net of applicable trading purchases, decreased $4 million as compared to the second quarter of 2002. This decrease included the effects of unfavorable price changes on the fair value of derivative contracts held and not yet settled and lower margins. Clearinghouse non-regulated gas sales revenue, net of applicable trading purchases, increased by $6 million, as compared to the second quarter of 2002. This increase reflects the effect of favorable price changes on unsettled derivative contracts and higher margins. In addition, the changes in both Clearinghouse non-regulated electric and gas revenue reflect the impact of adopting EITF 02-3. The impact included 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.

Other revenue increased $54 million over the same period in 2002, primarily reflecting the impact of adopting EITF 02-3. This increase included $49 million associated with oil trading revenues, net of applicable purchases and revenues from sales of coal. Purchases of coal are reported in other purchased energy commodities expense in 2003 but were reported on a net basis with the related revenue in other revenue in 2002.

PAGE 26

Operating expenses increased $87 million to $815 million in the second quarter of 2003. Electric fuel and energy purchases, net increased $21 million which included an increase of $5 million for purchases not subject to recovery through fuel rates. Electric fuel and energy purchases, net also increased due to the adoption of EITF 02-3, reflecting purchases under certain derivative contracts that are no longer considered held for trading purposes. Purchased electric capacity decreased $10 million, primarily due to scheduled rate reductions on certain supply contracts. Other purchased energy commodities increased $74 million, 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.

Other operations and maintenance expense increased $7 million. The increase reflects a $17 million increase in outage and maintenance costs primarily at the nuclear power stations, partially offset by a $6 million decrease in general and administrative expenses. Other operations and maintenance expense also reflected decreases due to the adoption of EITF 02-3, now reflecting changes in the fair value of certain derivative energy contracts no longer considered held for trading purposes. 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 $10 million, primarily reflecting a decrease related to a change in the presentation of expenses associated with asset retirement obligations. As previously discussed, a significant component of such expenses is now reflected in other operations and maintenance beginning in 2003. Depreciation expense also reflects the extension of estimated useful lives of most fossil fuel stations and electric transmission property during the second quarter of 2002, substantially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements.

Other taxes increased $5 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues. Similar benefits were not recognized in the second quarter of 2003.

See Adoption of SFAS 143 above for a discussion of the increase in other income.

Energy's net income contribution increased $91 million to $316 million for the six months ended June 30, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $311 million increase in operating revenue and an $18 million increase in other income, partially offset by a $190 million increase in operating expenses and a $52 million increase in income tax expense.

Colder weather during the first quarter and customer growth contributed approximately $28 million and $19 million, respectively, to the $32 million increase in regulated electric sales. Fuel rate recoveries, which are generally offset by related increases in electric fuel expense and do not materially affect net income, increased $46 million for the first six months of 2003. A reallocation of base rate revenue between the Delivery and Energy segments, effective January 1, 2003, decreased Energy's regulated electric sales revenue by $38 million. Other factors decreased regulated electric sales revenue by $23 million.

Non-regulated electric sales decreased $30 million in the six months ended June 30, 2003, as compared to 2002. Clearinghouse electric revenue, net of applicable trading purchases, decreased by $34 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 adopting EITF 02-3. The impact included 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. Revenue from wholesale marketing of utility generation increased $4 million and was principally driven by higher electric volumes.

PAGE 27

Clearinghouse non-regulated gas revenue, net of applicable trading purchases, increased by $236 million, as compared to the first six months of 2002. This increase reflects the effect of favorable price changes on unsettled derivative contracts, higher margins and the impact of adopting EITF 02-3. The impact included 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. Non-regulated gas revenue also reflects $32 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 $73 million over the same period in 2002, primarily reflecting the impact of adopting EITF 02-3. This increase included $64 million associated with oil trading revenue, net of applicable purchases, and revenue from sales of coal. Purchases of coal are reported in other purchased energy commodities expense in 2003 but were reported on a net basis with the related revenue in other revenue in 2002.

Operating expenses increased $190 million to $1.6 billion in the first six months of 2003. Electric fuel and energy purchases, net increased $92 million which included an increase of $46 million due to higher fuel rate recoveries, $17 million for purchases not subject to fuel rate recoveries and $3 million for expenses associated with increased wholesale marketing of utility generation. Electric fuel and energy purchases, net also increased $26 million due to the adoption of EITF 02-3, reflecting purchases under certain derivative contracts that are no longer considered held for trading purposes. Purchased electric capacity decreased $33 million, primarily due to scheduled rate reductions on certain supply contracts. Other purchased energy commodities increased $142 million, 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.

Other operations and maintenance expense decreased $5 million reflecting a $77 million decrease due to the adoption of EITF 02-3, which now reflects changes in the fair value of certain derivative energy contracts no longer considered held for trading purposes. Increases in other operations and maintenance expense included a $24 million increase in general and administrative expenses and a $29 million increase in outage and maintenance costs primarily at the nuclear power stations. Also, as previously discussed, other operations and maintenance expense increased $19 million for the accretion of the nuclear decommissioning asset retirement obligation beginning in 2003.

Depreciation expense decreased $22 million, primarily reflecting a $16 million decrease related to a change in the presentation of expenses associated with asset retirement obligations. 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 $16 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 six months of 2003.

Other income increased approximately $18 million, reflecting net realized gains of $6 million from the Company's decommissioning trusts and $10 million as a result of accretion expense related to the Company's provision for decommissioning being reported in other income in 2002. Accretion expense under SFAS No. 143 is reported in other operations and maintenance expense beginning in 2003.

PAGE 28

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 six months ended June 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 June 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.

PAGE 29

Second Quarter 2003 Results

Delivery's net income contribution increased $9 million to $61 million for the second quarter ended June 30, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $7 million increase in other income offset by a $2 million decrease in operating revenue and a $5 million decrease in operating expenses. Regulated electric sales increased $3 million over the comparable period. Comparably milder weather during the second quarter of 2003 decreased regulated electric sales $20 million. Customer growth of $4 million partially offset this decrease. In addition, a reallocation of the base rate revenues between Energy and Delivery, effective January 1, 2003, increased Delivery's regulated electric sales revenue by approximately $20 million. There were 42 percent fewer cooling degree days in the second quarter of 2003, as compared to 2002. There were approximately 37,000 new electric customers added over the last twelve months. Other revenue decreased by $5 million over the same pe riod in 2002 primarily due to the change in allocation of late payment fees and lower miscellaneous service revenues. Other income increased $7 million primarily due to interest income on a favorable resolution of tax audit issues.

Operating expenses decreased $5 million primarily due to decreases in other operation and maintenance expense offset by increases in other taxes. Other operations and maintenance expense decreased $10 million, reflecting primarily a decrease in general and administrative expenses. Other taxes increased $6 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues. Similar benefits were not recognized in the second quarter of 2003.

Six Months Ended June 30, 2003 Results

Delivery's net income contribution increased $25 million to $129 million for the six months ended June 30, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $42 million increase in operating revenue, partially offset by a $5 million increase in operating expenses and a $16 million increase in income tax expense. Colder weather in the first quarter of 2003 and customer growth contributed approximately $12 million and $8 million, respectively, to the $50 million increase in regulated electric sales, partially offset by $8 million due to other factors. A change in the allocation of the base rate revenues from Energy to Delivery, effective January 1, 2003, increased Delivery's revenues by approximately $38 million. Other revenue decreased by $8 million over the same period in 2002 primarily due to the change in allocation of late payment fees and lower miscellaneous service revenues. Other income increased by $3 million, reflecting $7 million of interest income on the favorable resolution of tax audit issues, offset by other insignificant items.

The increase in operating expenses is primarily due to increases in other taxes and other operations and maintenance expense, offset by a decrease in depreciation expense. Other taxes increased $7 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues. Similar benefits were not recognized in the first six months of 2003. A $5 million increase in service restoration costs due to ice storms and severe weather in the first quarter of 2003 was substantially offset by lower general and administrative expenses, materials and supplies and expenditures for contractors. See Note 2 to the Consolidated Financial Statements for a discussion of the change in estimated useful lives of the Company's distribution property in 2002.

PAGE 30

The Corporate and Other segment had no material impacts on net income for the three months ended June 30, 2003, as compared to the same period in 2002.

The change in the corporate segment's contribution to reported earnings, for the first six months of 2003, as compared to the same period last year, is primarily attributable to the following:

• $8 million ($5 million after tax) related to severance costs for workforce reduction, 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; and
• $55 million after-tax charge, 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.

As presented on the Company's Consolidated Statements of Cash Flows, net cash flow provided by operating activities totaled approximately $766 million and $430 million during the six months ended June 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.

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 June 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.

PAGE 31

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.

In April 2003, the Company repaid $200 million of 1993 Series B, 6.625 percent mortgage bonds.

Joint Credit Facilities

Dominion, CNG and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion. In May 2003, Dominion, CNG and the Company entered into a joint credit facility that allows aggregate borrowings of up to $1.25 billion. This credit facility replaced the $1.25 billion 364-day credit facility that matured during the second quarter of 2003. In May 2002, Dominion, CNG and the Company entered into a $750 million 3-year revolving credit facility that terminates in May 2005. The credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the Company; and other general corporate purposes.

The 3-year facility can also be used to support up to $200 million of letters of credit. At June 30, 2003, total outstanding letters of credit supported by the 3-year facility were $199 million, which were issued on behalf of CNG and other Dominion subsidiaries.

At June 30, 2003, net borrowings under the commercial paper program were $90 million, a decrease of $353 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 June 30, 2003 and December 31, 2002, net outstanding borrowings under this note totaled $215 million and $100 million, respectively. Interest charges related to this note for the three and six months ended June 30, 2003 were not material.

Amounts Available under Shelf Registrations

At June 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.

Investing Activities

During the six months ended June 30, 2003, investing activities resulted in a net cash outflow of $556 million. These activities included plant construction and other property expenditures of $458 million and nuclear fuel expenditures of $58 million. The plant expenditures related to generation-related projects totaled approximately $262 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 $179 million, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled approximately $17 million. Investing activities also include $36 million of contributions to the Company's nuclear decommissioning trusts.

PAGE 32

As of June 30, 2003, other than scheduled maturities of new debt issued during the first six months 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.

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.

Proposed Pilot Programs

In March 2003, the Company filed an application with the Virginia State Corporation Commission (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 megawatts 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 begin January 1, 2004. 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.

In June 2003, as the result of meetings with interested parties and the Virginia Commission Staff, the Company filed revisions to certain provisions of the pilot programs. The revisions include, among other items, a proposal to reduce the wires charges under the pilot through the remainder of the capped rate period, as well as a request for the opportunity to modify the pilot programs as necessary to more successfully transition to the period after capped rates have expired or have been terminated. The Company also offered to consider an increase in the wires charge reduction with a corresponding decrease in the size (megawatts) of the pilots as a means to stimulate activity in the pilot programs.

In July 2003, the Virginia Commission's Staff recommended approval of the pilot programs, with certain modifications.

In July 2003, the Company filed its 2004 fuel factor application with the Virginia Commission. If approved, the application would result in a fuel factor of 2.331cents per kWh for 2004. The application requests a total fuel factor increase of $441 million, which includes a projected $308 million under-recovery balance as of December 31, 2003. The under-recovery balance is 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. Representatives of some of the Company's largest industrial customers have asked the Virginia Commission to deny the application. A hearing on the fuel factor request has been set for October 2003.

PAGE 33

Monitoring the Recovery of Stranded Costs

In July 2003, the Virginia Commission submitted its report on the activities of the stranded cost work group. The report addressed definitions for "stranded costs" and "just and reasonable net stranded costs," discussed methodologies for monitoring the over-recovery or under-recovery of stranded costs, and discussed administrative and legislative recommendations. The Virginia Commission's Staff analyzed the recommendations of the work group participants and provided recommendations for consideration by the Commission on Electric Utility Restructuring.

Regional Transmission Organization (RTO)

In June 2003, the Company submitted an application to the 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 transmission facilities to PJM on November 1, 2004. The application stated that the integration of the Company's transmission facilities into PJM will provide increased access to competitively priced wholesale power which will provide savings to the Company's retail customers and ensure reliable service to the Company's retail customers. In addition, the proposed transfer is expected to facilitate the development of competitive wholesale and retail electricity markets. The application contained a cost-benefit study of the Company's integration into PJM, as required by the Virginia Restructuring Act, that supported the expected savings to customers. It is uncertain when the Virginia Commission will act on the application. The Company intend s to file an application to join PJM with the North Carolina Public Utilities Commission and FERC.

FERC Standard Market Design Proposal

In April 2003, FERC issued a discussion document addressing several issues raised by state regulatory commissions and market participants in FERC's proposed Standard Market Design (SMD). The document proposes certain changes to SMD and to hold technical conferences to work with the states and market participants to develop reasonable timetables for moving forward on the formation of RTOs. FERC also stated that it would not use the SMD rulemaking to overturn prior RTO orders where there is overlap. It is uncertain what impact, if any, these matters may have on the Company's efforts to join PJM.

Environmental Matters

As previously reported in Note 21 to the Consolidated Financial Statements 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. The EPA public comment period has now closed. It is anticipated that in the near future 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 f or environmental projects and a commitment to improve air quality under the Consent Decree estimated to involve

PAGE 34

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 June 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.

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 relating to 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

See Note 4 to the Consolidated Financial Statements for a description of the following new accounting standards which were issued during 2003, and generally become effective after June 30, 2003:

• FASB Interpretation No. 46, Consolidation of Variable Interest Entities;
• SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities;
• SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity ;
• SFAS 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; and
• EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease.

PAGE 35

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 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 $35 million in the fair value of its commodity-based financial derivative contracts held for trading purposes as of June 30, 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 36

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 net realized and unrealized gains on decommissioning trust investments of $54 million for the first six months of 2003 and net realized and unrealized losses of $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 37

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 and that there have been 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. 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 38

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 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.

ITEM 5. OTHER INFORMATION

As previously reported, the Virginia Commission adopted rules in August 2002 regarding consolidated billing by competitive service providers. In June 2003, the Company implemented system changes that were required in order to accommodate the consolidated billing. To date, no supplier has expressed any interest in this billing option.

In July 2003, the Company filed its 2004 fuel factor application with the Virginia Commission. See Rate matters in MD&A of this Form 10-Q for further information on this matter.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

PAGE 39