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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2002

OR

For the transition period from                to

Commission File Number 1-2255

VIRGINIA ELECTRIC AND POWER COMPANY

(Exact name of registrant as specified in its charter)

(804) 819-2000

(Registrant’s telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is an accelerated filer.  Yes  ¨  No  x

The aggregate market value of the voting stock held by non-affiliates as of February 28, 2003, was zero.

As of February 28, 2003, there were issued and outstanding 177,932 shares of the registrant’s common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

DOCUMENTS INCORPORATED BY REFERENCE.

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Virginia Electric and Power Company.

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Part I

The Company

Virginia Electric and Power Company (the Company) is a regulated public utility that generates, transmits and distributes power for sale in Virginia and northeastern North Carolina. In Virginia, the Company conducts business under the name “Dominion Virginia Power.” The Virginia service area comprises about 65 percent of Virginia’s total land area, but accounts for over 80 percent of its population. In North Carolina, the Company conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, the Company sells electricity at wholesale to rural electric cooperatives, power marketers, municipalities and other utilities. Within this document, “the Company” refers to the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and all of its subsidiaries.

All of the Company’s common stock is owned by its parent company, Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company.

Operating Segments

The Company manages its business through two principal segments: Energy and Delivery.

Energy—Energy manages the Company’s portfolio of generating facilities and power purchase agreements and its energy trading and marketing, hedging and arbitrage activities. Effective January 1, 2003, the Company’s electric transmission operations became a part of the Energy segment.

Delivery—Delivery manages the Company’s electric distribution and transmission systems as well as customer service. Effective January 1, 2003, the Company’s electric transmission operations became a part of the Energy segment.

The majority of the Company’s revenue is provided through bundled rate tariffs. This revenue is allocated between the Energy and Delivery segments for internal reporting purposes and discussion in this document. While the Company manages its daily operations as described above, its assets remain wholly owned and operated by the Company. For additional financial information on business segments, see Note 26 to the Consolidated Financial Statements.

As of December 31, 2002, the Company had approximately 7,600 full-time employees. Approximately 3,600 employees are subject to collective bargaining agreements.

Virginia Electric and Power Company was incorporated in 1909 as a Virginia public service corporation. Its principal office is located at 701 East Cary Street, Richmond, Virginia 23219-3932. The telephone number is (804) 819-2000.

Seasonality

Sales of electricity in the Delivery segment typically vary seasonally based on increased demand for electricity by residential and commercial customers for cooling and heating use based on changes in temperature. The Energy segment is also impacted by seasonal changes in the prices of commodities, primarily electricity and natural gas, that it actively markets and trades.

Competition

Various factors are currently affecting the electric utility industry, including increasing competition and related regulatory changes, costs to comply with environmental regulations, and the potential for new business opportunities outside of traditional rate-regulated operations. To meet the challenges of this new competitive environment, the Company continues to consider new business opportunities, particularly those which allow the Company to use its existing expertise and resources.

The Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure Virginia’s electric utility industry and provide for the phase-in of choice for retail customers from January 1, 2002 through January 1, 2004. As ordered by the Virginia State Corporation Commission (Virginia Commission), the Company made retail choice available for all of its Virginia regulated electric customers as of January 1, 2003.

Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia jurisdictional operations is no longer subject to cost-based rate regulation effective January 1, 2002. Base rates (excluding fuel costs and certain other allowable adjustments) are capped and will remain unchanged until July 2007, unless modified or terminated sooner,

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as provided by the Virginia Restructuring Act. Under the Virginia Restructuring Act, the Company may request a termination of the capped rates at any time after January 1, 2004, and the Virginia Commission may grant the Company’s request to terminate capped rates, if it finds that a competitive generation services market exists in the Company’s service area. Recovery of generation-related costs will continue to be provided through capped rates and a wires charge. A wires charge, where applicable, will be assessed to those customers opting for alternative suppliers. The Virginia Restructuring Act also requires the Company to join or establish a regional transmission organization (RTO), phase-in retail choice beginning January 1, 2002, and functionally separate its electric generation from its electric transmission and distribution operations.

Recently, the Virginia Commission recommended that state policymakers decide promptly whether to proceed with or delay implementation of the Virginia Restructuring Act, in light of recent developments impacting electric industry restructuring in Virginia, including the Federal Energy Regulatory Commission’s (FERC) issuance of a notice of proposed rule making on Standard Market Design. Legislation that would delay entry into a RTO until on or after July 1, 2004 was approved by the Virginia General Assembly in February 2003 and is now awaiting action by the Governor. The proposed legislation also would require the Company to file an application with the Virginia Commission by July 1, 2003 to join a RTO. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its transmission assets to a RTO by January 1, 2005.

For additional information on electric deregulation in Virginia, see Electric Deregulation Legislation in Future Issues and Outlook in Item 7. Management’s Discussion and Analysis and Results of Operations (MD&A).

In North Carolina, regulators and legislators continue to explore the issues related to electric industry restructuring, the development of a competitive, wholesale market and retail competition. However, to date, there has been no significant activity.

The Company plans to continue to participate actively in both the legislative and regulatory processes to ensure an orderly transition from a regulated environment.

Regulation

General

The Company is subject to regulation by the Virginia Commission, the North Carolina Utilities Commission (North Carolina Commission), Securities and Exchange Commission (SEC), FERC, the Environmental Protection Agency (EPA), Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, and other federal, state and local authorities.

State Regulation

In Virginia, the Company’s retail service is subject to regulation by the Virginia Commission. The Virginia Commission approved a Virginia fuel factor of 1.613 cents per kWh in effect through December 31, 2003.

In North Carolina, retail service is subject to cost of service regulation by the North Carolina Commission. In connection with the North Carolina Commission approval of Dominion’s acquisition of Consolidated Natural Gas Company (CNG), the Company agreed not to request an increase in North Carolina retail electric base rates until 2006, except for certain events that would have a significant financial impact on the Company. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. The North Carolina Commission has approved a fuel factor of 1.402 cents per kWh, effective January 1, 2003.

The Company holds certificates of public convenience and necessity authorizing it to construct and operate its electric facilities now in operation and to sell electricity to customers. However, it may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies.

In August 2002, the Virginia Commission adopted rules relating to competitive electric metering services and consolidated billing by competitive suppliers. The Company must provide its Virginia electric customers with access to meter functionality and interval meter data beginning January 1, 2003 and implement consolidated billing by competitive suppliers no later than July 1, 2003.

For additional information on deregulation in the electric industry, the Virginia Restructuring Act and current rate matters, see above in Competition and Future Issues and Outlook in MD&A.

Public Utility Holding Company Act of 1935  

When Dominion completed the acquisition of CNG in January 2000, it became a registered public utility

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holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern the activities of Dominion and its subsidiaries, including the Company, with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates engaging in business activities not directly related to the utility or energy business and other matters. The Company’s activities in these areas may also be regulated at the state level by the Virginia Commission and the North Carolina Commission. In some cases, the SEC’s rules under the 1935 Act provide that the obtaining of state approvals will suffice for the 1935 Act purposes also, subject to the fulfillment of certain post-transaction reporting requirements.

Federal Energy Regulatory Commission

Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities. The Company sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service territory. For additional discussion on this matter, see Wholesale Competition in Future Issues and Outlook in MD&A.

The Virginia Restructuring Act requires that the Company join a RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. FERC Order No. 2000 requires each public utility that owns or operates transmission facilities to make certain filings with respect to RTO formation, but will rely on voluntary formation of RTOs to advance its energy policies. By joining a RTO, the Company would transfer operational control of its transmission assets to a RTO, a third party.

In September 2002, the Company and PJM Interconnection, LLC (PJM) entered into the PJM South Implementation Agreement. The agreement provides that, subject to regulatory approval and certain provisions, the Company will become a member of PJM, transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region, integrate its control area into the PJM energy markets and otherwise facilitate the establishment and operation of PJM as the RTO with respect to the Company’s transmission facilities. The agreement also contemplates additional agreements and transmission tariff provisions to be negotiated by the parties and allocates costs of implementation of the agreement among the parties.

The Company intends to file for FERC approval to join PJM in the future. The Company will also seek authorization from the Virginia Commission and the North Carolina Commission to become a member of PJM at that time. The Company will incur integration and operating costs associated with joining a RTO. The Company has deferred certain of those costs for future recovery and is giving further consideration to seeking regulatory approval to defer the balance of such costs.

For additional discussion on this matter, see Regional Transmission Organization in Future Issues and Outlook in MD&A.

Legislation that would delay entry into a RTO until on or after July 1, 2004 was approved by the Virginia General Assembly in February 2003 and is now awaiting action by the Governor. The proposed legislation also would require the Company to file an application with the Virginia Commission by July 1, 2003 to join a RTO. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its transmission assets to a RTO by January 1, 2005.

In the spring of 2003, FERC expects to issue new rules governing standards of conduct between interstate electric transmission, gas transportation and storage providers and their energy related affiliates. One goal of FERC is to eliminate the separate code of conduct regulations for natural gas pipelines and electric transmission utilities and replace these requirements with uniform standards applicable to interstate “Transmission Providers” of both natural gas and electricity. For additional discussion on this matter, see FERC Policy Developments in Future Issues and Outlook in MD&A.

Environmental Matters

Each operating segment of the Company faces substantial regulation and compliance costs with respect to environmental matters. For discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Environmental Matters in Future Issues and Outlook in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 21 to the Consolidated Financial Statements.

From time to time the Company may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial

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investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.

The EPA amended its oil pollution prevention regulations in July 2002. The total projected cost of compliance with the new regulations is estimated to range from $10 to $15 million, representing primarily capital expenditures.

The EPA is also considering issuing new regulations that govern existing utilities that employ a cooling water intake structure, and whose flow levels exceed a minimum threshold. As currently written, EPA’s proposed rule presents several control options under consideration for the final rule. The Company is evaluating facility information from Bremo, Chesapeake, Chesterfield, Mt. Storm, North Anna, Possum Point, Surry, and Yorktown Power Stations. Given the uncertainties of future action by EPA on this issue, the Company cannot predict the future impact on its operations at this time.

The Company has applied for or obtained the necessary environmental permits material to the operation of its electric generating stations. Many of these permits are subject to re-issuance and continuing review.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of the Company’s nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

The Company filed applications for a 20 year life-extension for the North Anna and Surry units in May 2001. The NRC has completed its review of the applications and the Company expects to receive a renewed license for these units in 2003. For more information on this matter, see Note 8 to the Consolidated Financial Statements.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining the Company’s nuclear generating units.

The NRC also requires the Company to decontaminate nuclear facilities once operations cease. This process is referred to as decommissioning, and the Company is required by the NRC to prepare for it financially. For information on compliance with the NRC financial assurance requirements, see Note 8 to the Consolidated Financial Statements.

Disposal of spent nuclear fuel is a significant issue associated with the operation and decommissioning of nuclear facilities. The Nuclear Waste Policy Act (NWPA) of 1982 requires a permanent, federal repository for high-level radioactive waste and spent nuclear fuel to be made available by January 31, 1998. In February 2002, the Secretary of Energy recommended that Yucca Mountain located in the state of Nevada be developed as the permanent repository. Final congressional approval was received in July 2002. The DOE is currently in the process of seeking approval of a NRC license to begin construction of the repository.

The Company and other utilities have petitioned the U.S. Court of Appeals for the 11th Circuit to review a matter involving the DOE and PECO Energy Company (PECO). The petitioners challenged the DOE’s action that allowed PECO to take credits against payments PECO would have been making into the Nuclear Waste Fund (NWF). The credits are part of the DOE’s settlement of PECO’s claim regarding the DOE’s failure to provide a permanent repository for spent nuclear fuel as required by the NWPA. The petition stated that the credits violated the NWPA by depleting the NWF and releasing PECO from a portion of its NWF obligation. The petition also sought injunction of the DOE’s settlement agreement with PECO and as well as an injunction against DOE entering into similar agreements. In September 2002, the court issued its decision on the matter declaring the fee adjustment aspect of the settlement between PECO and DOE “null and void.” The decision does not prevent DOE from settling claims related to DOE’s breach of its contractual obligation to begin disposing of spent nuclear fuel, but precludes DOE from using the NWF to compensate utilities for damages incurred by utilities owing to DOE’s breach of its NWF obligation to dispose of spent nuclear fuel.

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Interconnections

The Company maintains major interconnections with Progress Energy, American Electric Power Company, Inc., Allegheny Energy, Inc., PJM–West and PJM. Through this major transmission network, the Company has arrangements with these entities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy. See also Regional Transmission Organization in Future Issues and Outlook in MD&A.

Capital Requirements and Financing Program

See Liquidity and Capital Resources in MD&A for details about the Company’s capital requirements and financing program including material estimated capital expenditures for environmental control facilities.

Sources of Energy

Virginia Electric and Power Company’s Power Generation

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle

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Power Purchase Contracts

The Company purchases electricity under contracts with other suppliers to meet a portion of its system capacity requirements. As of December 31, 2002, the Company has 42 power purchase contracts with a combined dependable summer capacity of 3,758 Mw. For information on the financial obligations under these agreements, see Note 21 to the Consolidated Financial Statements.

Fuel for Electric Generation

The Company uses a variety of fuels to power its electric generation. These include a mix of both nuclear fuel and fossil fuel as described further below.

Nuclear Fuel Supply

The Company utilizes both long-term contracts and short-term purchases to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimum cost and inventory levels.

Fossil Fuel Supply

The Company utilizes coal, oil and natural gas in its fossil fuel operations. The Company’s coal supply is obtained through long-term contracts and spot purchases. Oil and oil-fired generation are used primarily to support heavier system generation loads during very cold or very hot weather periods. System requirements are purchased mainly under short-term spot agreements.

Firm natural gas transportation contracts (capacity) exist that allow delivery of gas to our facilities. The Company’s capacity portfolio allows flexible natural gas deliveries to its gas turbine fleet, while minimizing costs.

The Company owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of the Company’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds.

The Delivery segment has approximately 6,000 miles of electric transmission lines. Portions of transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line if any exists.

The Delivery segment has obtained right-of-way grants from the apparent owners of real estate for most of the Company’s electric lines, but underlying titles have not been examined except for transmission lines of 69 Kv or more. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly owned property, where permission to operate can be revoked.

The Company leases its headquarters facility from Dominion. In addition, the Energy and Delivery segments share certain leased buildings and equipment.

See Virginia Electric and Power Company’s Power Generation under Item 1. Business for a list of the principal facilities utilized by the Energy segment.

From time to time, the Company is alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there may be administrative proceedings on these matters pending. In addition, in the ordinary course of business, the Company is 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 Regulation under Item 1. Business, Rate Matters in Future Issues and Outlook in MD&A and Note 21 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

During 2000, the Company received a Notice of Violation from the EPA, alleging that the Company failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power

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

In 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 the Company’s 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 the Company’s electric transmission lines and on or in which fiber optic cable has been installed.” The named plaintiffs have asked that the court allow the lawsuit to proceed as a class action. Discovery has begun and the court has granted a motion to add additional plaintiffs, Harmon T. Tomlinson, Jr. and Linda D. Tomlinson. The outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

None.

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Part II

Dominion Resources, Inc. (Dominion) owns all of the Company’s common stock.

The Company paid quarterly cash dividends on its common stock as follows:

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Introduction

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

Risk Factors and Cautionary Statements That May Affect Future Results

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

The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These factors include weather conditions; fluctuations in energy-related commodities prices and the effect these could have on the Company’s earnings, liquidity position, and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; changes in rating agency requirements or ratings; changes in accounting standards; the risks of operating businesses in regulated industries that are becoming deregulated; transfer of control over the Company’s transmission facilities to a regional transmission entity; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation rates). Some more specific risks are discussed below.

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

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

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

Costs of environmental compliance, liabilities and litigation could exceed the Company’s estimates—Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment and monitoring obligations. In addition, the Company may be a responsible party for environmental clean up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because

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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 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 Future Issues and Outlook in MD&A and Note 21 to the Consolidated Financial Statements.

The electric generation business is subject to competition—Effective January 1, 2002, the generation portion of the Company’s operations in Virginia is open to competition and is no longer subject to cost-based rate regulation. As a result there is increased pressure to lower costs, including the cost of purchased electricity. Because the Company’s generation business has not previously operated in a competitive environment, the extent and timing of entry by additional competitors into the electric market in Virginia is unknown. Therefore, it is difficult to predict the extent to which the Company will be able to operate profitably within this new environment.

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

The use of derivative instruments could result in financial losses—The Company uses derivative instruments including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, the Company purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. For additional information concerning the Company’s derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2 and 9 the Consolidated Financial Statements.

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

An inability to access financial markets could affect the execution of the Company’s business plan—The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows of its operations. Management believes that the Company and its subsidiaries will maintain sufficient access to these financial markets based upon

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current credit ratings. However, certain disruptions outside of the Company’s control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to the Company’s credit ratings. Restrictions on the Company’s ability to access financial markets may affect its ability to execute its business plan as scheduled.

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

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

Operating Segments

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 primary operating segments are:

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

Effective January 1, 2003, the Company’s electric transmission operations became a part of the Energy segment instead of the Delivery segment. For more information on the Company’s operating segments, see Note 26 to the Consolidated Financial Statements.

Critical Accounting Policies

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

Accounting for risk management and energy trading contracts at fair value—The Company uses derivatives to manage its commodity, financial market and currency exchange risks. In addition, the Company purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. The accounting requirements for derivatives and hedging activities are complex and interpretation of these requirements by standard-setting bodies is

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ongoing. All derivatives, other than specific exceptions, are reported on the Consolidated Balance Sheets at fair value, beginning in 2001. Energy trading contracts are also reported on the Consolidated Balance Sheets at fair value. Changes in fair value, except those related to derivative instruments designated as cash flow hedges, are generally included in the determination of the Company’s net income at each financial reporting date until the contracts are ultimately settled. The measurement of fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies deemed appropriate by the Company’s management. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition of changes in fair value of certain hedging derivatives. See Selected Information—Energy Trading Activities and Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2, 9, and 21 to the Consolidated Financial Statements.

Accounting for regulated operations—Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition used for accounting purposes, the Company’s Consolidated Financial Statements may recognize a regulatory asset for expenditures that otherwise would be expensed. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through rates. Regulatory liabilities represent probable future reductions in revenue associated with expected customer credits through rates. Management makes assumptions regarding the probability of regulatory asset recovery through future rates approved by applicable regulatory authorities. The expectations of future recovery are generally based upon historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, they would be expensed in the period such assessment is made. See Notes 2 and 10 to the Consolidated Financial Statements.

Long-lived assets—In testing the Company’s long-lived assets and intangible assets with definite lives for potential impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company is required to estimate the future cash flows associated with individual assets or groups of assets. Although the cash flow estimates used by the Company are based on the best information available at the time the estimates are made, estimates of future cash flows are by nature highly uncertain and may vary significantly from actual results.

If the sum of the undiscounted estimated future cash flows exceeds the related asset’s carrying amount, no impairment exists. Otherwise, there is potential impairment that must be measured by comparing the fair value of the asset to its carrying amount. An asset’s fair value is determined by calculating the present value of its expected future cash flows, which requires management to select an appropriate discount rate. The recognition of an asset impairment would result in a charge to earnings, with a corresponding reduction of the carrying amount of the related property, plant and equipment or intangible asset.

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Results of Operations

The Company’s discussion of its results of operations includes an overview of its operating revenue and operating results for 2002 and 2001 on a consolidated basis. These sections are followed by a more detailed discussion of the results of operations of the operating segments. For additional information about the Company’s operating segments, see Note 26 to the Consolidated Financial Statements.

Overview of Operating Revenue—Consolidated

The following is a general discussion of factors that affect operating revenue for both the Energy and Delivery segments.

The majority of the Company’s operating revenue is provided through bundled rate tariffs. Regulated electric sales consist primarily of sales to retail customers at rates authorized by the Virginia Commission and the North Carolina Utilities Commission (North Carolina Commission), and sales to cooperatives and municipalities at wholesale rates authorized by the Federal Energy Regulatory Commission (FERC). Also included in regulated electric sales are amounts received from others for use of the Company’s transmission system to transport electric energy under tariffs authorized by FERC.

In addition, regulated electric sales include revenue from fuel rates which are subject to approval by regulatory authorities and are designed to recover the cost of fuel used in generating electricity from customers served under regulated tariffs.

Overview of 2002 Results—Consolidated

Net income increased $327 million to $773 million, as compared to 2001. Net income increased in 2002 due primarily to an after-tax charge of $136 million taken in the first quarter of 2001 in connection with the termination of certain long-term power purchase agreements under which the Company previously purchased electric energy. Comparably warmer temperatures in the summer of 2002 and customer growth in the Company’s regulated electric service territories resulted in higher regulated electric revenues for 2002. The increase in regulated electric revenue for 2002 included the effect of a $34 million decrease in revenues from wholesale customers served under requirements contracts. For further information, see Capacity below in MD&A. The contribution from the Company’s electric and gas trading and power marketing activities decreased for 2002. Total operating expenses decreased, compared to 2001, primarily due to lower depreciation and other operations and maintenance expense.

Operating revenue increased $28 million to $4.9 billion for 2002, as compared to 2001. Regulated electric sales increased $237 million, and other revenue decreased $209 million. Favorable weather conditions, reflecting increased cooling and heating degree-days, as well as customer growth, are estimated to have contributed approximately $195 million and $60 million, respectively, to the $237 million increase in regulated electric sales. Fuel rate recoveries increased approximately $65 million for 2002. These recoveries are generally offset by related increases in electric fuel expense and do not materially affect income. Partially offsetting these increases was a net decrease of $83 million due to other factors not separately measurable. These factors include the impact of economic conditions on customer usage, especially non-residential customers, as well as variations in seasonal rate premiums and discounts. There were 31 percent more cooling degree-days in 2002 and 2 percent more heating degree-days, as compared to 2001. The Company served, on average, 43,000 more retail customers during 2002.

Other revenue from energy trading activities decreased $218 million. For further information, see the Energy Segment below. Miscellaneous revenue increased by $9 million over the comparable period in 2001.

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Operating expenses decreased $433 million to $3.5 billion for 2002, as compared to 2001. Electric fuel and energy purchases, net and purchased electric capacity increased in 2002. The Company incurred restructuring costs in both 2001 and 2000, primarily associated with Dominion’s acquisition of Consolidated Natural Gas (CNG) and subsequent integration of the combined companies’ operations. Other operations and maintenance expenses were lower in 2002, primarily due to additional costs incurred in 2001 associated with the termination of certain long-term power purchase contracts. For further information on these restructuring costs and termination of the power purchase contracts, see the Corporate and Other Segment discussed below. Depreciation and amortization decreased, primarily due to changes in the estimated useful lives of the Company’s fossil-fueled generating plants and transmission and distribution properties, offset by the effect of routine property additions. These changes in the estimated useful lives reduced depreciation expense by approximately $40 million for 2002. See Note 2 to the Consolidated Financial Statements. Other taxes decreased, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.

Interest and related charges decreased, primarily as a result of lower interest rates on outstanding debt. Expenses associated with the preferred securities of subsidiary trusts increased, primarily due to the higher amount of outstanding trust preferred securities at December 31, 2002. In addition, the Company’s effective income tax rate decreased. See Note 7 to the Consolidated Financial Statements.

Overview of 2001 Results—Consolidated

Operating revenue increased $153 million to $4.9 billion for 2001, as compared to 2000. The increase was due primarily to higher fuel rate recoveries, growth in the number of retail customers and increased wholesale sales to cooperatives and municipalities under requirements contracts. These factors were offset by milder weather conditions in 2001. While there were 6 percent more cooling degree-days in the summer of 2001, as compared to 2000, the 10 percent decline in 2001 heating degree-days more than offset the benefit from the higher summer sales. The Company served, on average, 40,000 more retail customers during 2001.

The results of the Company’s electric and gas trading and marketing operations also contributed approximately $24 million to the increase in operating revenue.

Operating expenses increased $240 million to $3.9 billion for 2001, as compared to 2000. Higher prices for commodities consumed contributed to increased electric fuel and energy purchases, net. Purchased electric capacity expense decreased as the Company terminated certain contracts in early 2001. See Note 21 to the Consolidated Financial Statements. Depreciation and amortization decreased primarily due to a change in the estimated useful lives of the Company’s nuclear plants in connection with the expected re-licensing of those plants, offset by routine property additions. The change in useful lives of the nuclear facilities reduced depreciation expense by approximately $72 million for 2001. For further information, see the Energy Segment and Note 2 to the Consolidated Financial Statements. The Company incurred restructuring costs in both 2001 and 2000 primarily associated with Dominion’s acquisition of CNG and subsequent integration of the combined companies’ operations. Other operations and maintenance expenses increased primarily due to costs associated with the termination of certain long-term power purchase contracts. For further information on these restructuring costs and termination of the power purchase contracts, see the Corporate and Other Segment discussed below. The Company’s effective income tax rate increased and other taxes decreased in 2001 due to its utility operations in Virginia becoming subject to state income taxes in lieu of gross receipts taxes.

Segment Results

Energy Segment

The Company provides electricity primarily from the following fuel sources: nuclear, coal, oil and purchased power. System energy output by energy source and the

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average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt-hour.

2002 Results

Energy’s net income contribution increased $67 million to $447 million for 2002, as compared to 2001. The increase in net income primarily reflects a $88 million decrease in operating expenses, partially offset by a $25 million decrease in operating revenue.

Comparably warmer temperatures during the summer of 2002 and customer growth contributed approximately $133 million and $41 million, respectively, to the $179 million increase in the Energy’s segment regulated electric sales, partially offset by other factors as discussed above in Overview of 2002 Results—Consolidated.

In addition, Energy manages the Company’s energy trading, hedging, arbitrage and power marketing activities through the Dominion Energy Clearinghouse (the Clearinghouse). The Company’s electric trading revenue, representing net gains and losses from contract settlements and unrealized changes in the fair value of contracts not yet settled, decreased by approximately $32 million, as compared to 2001. This decrease reflects the effect of unfavorable price changes and lower trading margins. Power marketing sales decreased by approximately $74 million, as compared to 2001. Less generation was available for sale in the wholesale markets primarily due to the higher demand of the Company’s utility service territory customers during 2002. Gas trading revenue, net of cost of sales, decreased approximately $112 million. Approximately $70 million of this decrease relates to contracts held by one of the Company’s unregulated subsidiaries as part of Dominion’s consolidated price risk management strategy associated with anticipated sales of Dominion’s 2002 and 2003 natural gas production. Other miscellaneous revenue increased by approximately $14 million over the comparable period in 2001 primarily due to increases in sales of other commodities.

Operating expenses decreased $88 million for 2002, as compared to 2001. Electric fuel and energy purchases, net increased $29 million as a result of a $66 million increase in electric fuel and energy purchases subject to rate recovery, partially offset by a $37 million decrease in fuel expenses attributable to less wholesale marketing of utility plant generation. Purchased electric capacity costs increased by $11 million due to additional capacity acquired to serve utility demand in 2002. Depreciation expense decreased by $13 million, reflecting the effect of changes in the estimated useful lives of fossil-fired generation property, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements. Other operations and maintenance decreased $95 million in 2002, primarily reflecting a $68 million decrease in scheduled outages and routine maintenance costs at both nuclear and fossil plants and a $27 million decrease in general and administrative expenses. Other taxes decreased approximately $20 million, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.

2001 Results

Customer growth and the increase in fuel rate recoveries contributed to the increase in Energy’s regulated electric sales. See Overview of Operating Revenue—Consolidated and Overview of 2001 Results—Consolidated. The results of the Company’s electric and gas trading and marketing operations also contributed approximately $24 million to the increase in operating revenue for the Energy segment.

Operating expenses increased $53 million for 2001, as compared to 2000. Electric fuel and energy purchases, net were higher in 2001, reflecting higher fuel prices for coal and oil consumed. The effect of such expenses on net income was mitigated by increased fuel rate revenue, including higher levels of recovery for previously deferred fuel costs. Purchased electric capacity costs decreased as a result of the termination of long-term power purchase agreements in the first quarter of 2001. The decrease in depreciation and amortization expense primarily reflects a $72 million

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decrease from a change in the estimated useful lives of the Company’s nuclear plants. This change was based on the Company’s expectation that 20-year extensions of the operating licenses for its nuclear facilities will be granted. The application was filed with the Nuclear Regulatory Commission (NRC) in May 2001. The Company expects to receive a renewed license for these units in 2003. This decrease was partially offset by additional depreciation expense related to other recent generation-related capital expenditures. Other operations and maintenance increased due to scheduled outages at both nuclear and fossil plants. Other taxes decreased reflecting a change in Virginia whereby the Company became subject to state income taxes in lieu of gross receipts taxes effective January 2001.

Selected Information—Energy Trading Activities

As discussed earlier, Energy manages the Company’s energy trading, hedging and arbitrage activities through the Clearinghouse. The Company believes these operations complement its integrated energy business and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas, electricity and oil. Settlement of a contract may require physical delivery of the underlying commodity or, in some cases, an exchange of cash. These contracts are classified as energy trading contracts for financial accounting purposes, and are included in the Consolidated Balance Sheets as components of current and non-current derivative and energy trading assets and liabilities. Gains and losses from energy trading contracts, including both realized and unrealized amounts, are reported net in the Consolidated Statements of Income as revenue.

In accordance with generally accepted accounting principles, the Company reports energy trading contracts in its financial statements at fair value. For a discussion of how the Company determines fair value for its energy trading contracts, see Critical Accounting Policies presented earlier in MD&A. The Clearinghouse enters into contracts with the objective of benefiting from changes in the prices of energy commodities. Clearinghouse management continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity, seeking arbitrage opportunities. For example, after entering into a contract to purchase a commodity, the Clearinghouse typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or sometimes will pay a net cash margin(a realized loss).

Until the contracts are settled, however, the Company must record the changes in the fair value of both contracts. These changes in fair value represent unrealized gains and losses. To the extent purchase and sales contracts with identical or similar terms are held by the Clearinghouse, the changes in their fair values will generally offset one another. Although the Clearinghouse may hold purchase or sales contracts for delivery of commodities at particular locations and times that have not been offset, such exposures are monitored and actively managed on a daily basis. The Company’s risk management policies and procedures are designed to limit its exposure to commodity price changes.

For additional discussion, see Market Rate Sensitive Instruments and Risk Management and Notes 2, 9, and 23 to the Consolidated Financial Statements. Also, see Note 4 to the Consolidated Financial Statements, for a discussion of the Company’s implementation of new accounting requirements effective January 1, 2003 to reflect the decisions of the Emerging Issues Task Force (EITF) in Issue No. 02-3, Issues Involved in Accounting for Contracts under Issue No. 98-10. As a result, some energy-related contracts are no longer subject to fair value accounting.

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A summary of the changes in the unrealized gains and losses in the Company’s energy trading contracts during 2002 follows:

The balance of net unrealized gains and losses in the Company’s energy trading contracts at December 31, 2002 is summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:

Delivery Segment

2002 Results

Delivery’s net income contribution increased $92 million to $322 million for 2002, as compared to 2001. The increase in net income reflects a $51 million increase in operating revenue and a $75 million decrease in operating expenses. These amounts were partially offset by increases in income tax expense.

Comparably warmer temperatures during the summer of 2002 and customer growth contributed approximately $62 million and $19 million, respectively, to the $58 million increase in the Delivery segment’s regulated electric sales, partially offset by other factors as discussed above in Overview of 2002 Results—Consolidated. Miscellaneous revenue decreased $7 million from 2001.

Operating expenses were $638 million in 2002, as compared to $713 million in 2001. Operations and maintenance expense decreased approximately $57 million, reflecting a decrease in general and administrative salaries, materials and supplies and expenditures for contractors. Also, Delivery’s operating expenses can be impacted by severe weather. Hurricanes, major thunderstorms and ice storms can damage the Company’s distribution and transmission systems. There was an approximate $6 million increase in service restoration costs recorded in other operations and maintenance expense due to ice storms in late 2002. Depreciation expense decreased by $10 million, reflecting the effect of changes in the estimated useful lives of distribution property, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements. Other taxes decreased $7 million, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.

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2001 Results

Customer growth was the main contributor to the increase in the Delivery’s segment regulated electric sales. Also, see Overview of Operating Revenue—Consolidated and Overview of 2001 Results—Consolidated.

Operating expenses were $713 million in 2001, as compared to $718 million in 2000. During 2001 and 2000, there were no unusual levels of storm restoration activities. Depreciation and amortization increased slightly as a result of routine property additions. Other operations and maintenance expenses included a moderate increase in provisions for uncollectible customer accounts. Other taxes decreased, reflecting a change in Virginia whereby the Company’s utility operations became subject to state income taxes in lieu of gross receipts taxes effective January 2001.

Corporate and Other

2002 Results

Corporate and other operations reported income, net of related taxes, of $4 million in 2002, as compared to expenses, net of related taxes, of $164 million in 2001, primarily due to costs associated with the purchase of three non-utility generating plants and termination of certain long-term power purchase contracts in 2001. In addition, these results include a pre-tax adjustment of $7 million recorded in 2002 to adjust liabilities that resulted from restructuring activities initiated late in 2001. For further information, see Notes 6 and 21 to the Consolidated Financial Statements.

2001 Results

Corporate and other operations reported expenses, net of related taxes, of $164 million in 2001, an increase of $128 million, as compared to 2000. These results include pre-tax restructuring costs of $48 million and a pre-tax charge of $220 million related to costs associated with the purchase of three non-utility generating plants and termination of certain long-term power purchase contracts. See Notes 6 and 21 to the Consolidated Financial Statements.

Liquidity and Capital Resources

The Company depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash flow provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term debt financing.

Internal Sources of Liquidity

Cash flow from operating activities provided $1.3 billion in 2002 and $1.1 billion during each year in 2001 and 2000. The Company’s management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain current dividends payable to Dominion. As noted above, the Company uses a combination of short-term borrowings and sales of securities to fund capital requirements not covered by the timing or amounts of operating cash flows.

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

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

n  extreme weather events that could disrupt or cause catastrophic damage to the Company’s electric distribution and transmission systems;

n  exposure to unanticipated changes in prices for energy commodities purchased or sold, including the effect on derivative instruments that may require the use of funds to post margin deposits with counterparties;

n  effectiveness of Dominion’s risk management activities and underlying assessment of market conditions and related factors, including energy commodity prices, basis, counterparty credit risk, liquidity, volatility, availability of generation and transmission capacity, currency exchange rates and interest rates;

n  the cost of replacement electric energy in the event of longer-than- expected or unscheduled generation outages;

n  contractual or regulatory restrictions on transfers of funds among the Company and Dominion and the Company and its subsidiaries; and

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

External Sources of Liquidity

The Company relies on access to bank and capital markets as a significant source of liquidity for capital requirements not satisfied by the cash provided by the Company’s operations. As discussed further in the

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Credit Ratings section below, the Company’s ability to borrow funds or issue securities and the return demanded by investors are affected by the Company’s credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including the SEC and the Virginia Commission.

During 2002, the Company issued long-term debt (net of exchanged debt), trust preferred securities and preferred stock totaling approximately $1.1 billion. As discussed below, proceeds were used primarily to fund the repayment of short-term debt; the repayment of long-term debt maturities; and the Company’s capital expenditures.

Credit Facilities and Short-Term Debt

In May 2002, Dominion, CNG and the Company entered into two joint credit facilities that allow aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2003 and a $750 million three-year revolving credit facility that terminates in May 2005. The Company expects to renew the 364-day revolving credit facility prior to its maturity in May 2003. These joint credit facilities are used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. At December 31, 2002, total outstanding letters of credit supported by the three-year facility were $106 million, which were issued by Dominion on behalf of its other subsidiaries.

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

Long-Term Debt

In 2002, the Company redeemed its $200 million, 6.75 percent 1997-A mortgage bonds due February 1, 2007 with part of the proceeds from the issuance of $650 million, 5.375 percent senior notes due February 1, 2007 (Senior Notes). The redemption included a direct exchange of Senior Notes for $117 million of the mortgage bonds. The Company used the remaining cash proceeds from the issuance of the Senior Notes to redeem the remaining $83 million of the mortgage bonds and for general corporate purposes, including the repayment of other debt.

In 2002, the Company repaid the following long-term debt securities:

n  $280 million of medium-term notes, various series;

n  $83 million of 1997-A, 6.75 percent mortgage bonds, as described above;

n  $155 million of 1992-E, 7.375 percent mortgage bonds; and

n  $100 million 1993-F, 6 percent mortgage bonds.

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

Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust and Preferred Stock

During 2002, the Company, through Virginia Power Capital Trust II, issued $400 million of 7.375 percent trust preferred securities. The trust preferred securities must be redeemed when the trust’s sole assets, the junior subordinated notes due 2042 issued by the Company, are redeemed. The Company used the net proceeds from the sale of trust preferred securities primarily to redeem its June 1989 Series, September 1992A Series, September 1992B Series, and October 1988 Series variable rate preferred stock for $250 million and the 8.05 percent trust preferred securities of Virginia Power Capital Trust I for $135 million. See Note 16 to the Consolidated Financial Statements for additional discussion of the capital trust securities.

During 2002, the Company issued 1,250 units consisting of 1,000 shares per unit of cumulative preferred stock for $125 million. The preferred stock has a dividend rate of 5.50 percent until the end of the initial dividend period on December 20, 2007. The dividend rate for subsequent periods will be determined according to periodic auctions. The preferred stock has a liquidation preference of $100 per share plus accumulated and unpaid dividends. The Company used the proceeds for general corporate purposes and to repay debt. See Note 17 to the Consolidated Financial Statements.

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Common Stock

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

Borrowings from Parent

During 2002, Dominion advanced $100 million, net of repayments, to certain unregulated subsidiaries of the Company pursuant to a short-term demand note. Interest charges incurred by the Company were not material. See Note 24 to the Consolidated Financial Statements.

Amounts Available under Shelf Registrations

At March 1, 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.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However, disruptions in the bank and capital markets not specifically related to the Company may affect the Company’s ability to access these funding sources or cause an increase in the return required by investors.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing the Company’s credit ratings. Credit ratings are subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently. The credit ratings for the Company are most affected by the Company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, and changes in methodologies used by the rating agencies. Credit ratings for the Company as of March 1, 2003 follow:

These credit ratings reflect Standard & Poor’s downgrade of its credit ratings for the Company’s debt, preferred securities of subsidiary trust, preferred stock and commercial paper in October 2002. Based on its conclusions about regulatory insulation in Virginia being no better than in other states, Standard & Poor’s concluded that the Company’s ratings should be no more than one-notch above the ratings of its parent, Dominion Resources, Inc. Standard & Poor’s noted that the Company’s downgrade is not reflective of any diminished credit protection measures, as the Company’s credit protection measures on a stand-alone basis remain strong.

Generally, a downgrade in the Company’s credit rating would not restrict its ability to raise short-term or long-term financing so long as its credit rating is still “investment grade,” but it would increase the cost of borrowing. Management has been working closely with both Standard & Poor’s and Moody’s with the objective of maintaining the Company’s current credit ratings. As discussed in Risk Factors and Cautionary Statements That May Affect Future Results, in order to maintain its current ratings, the Company may find it necessary to take steps or change its business plans, and such changes may adversely affect its growth.

Debt Covenants

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

n  the timely payment of principal and interest;

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

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

n  payment of taxes; maintaining insurance;

n  performance obligations, audits/inspections, continuation of the basic nature of business, restrictions

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on certain matters related to merger or consolidation, restrictions on disposition of substantial assets;

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

n  compliance with collateral minimums or requirements related to mortgage bonds (See Note 15 to the Consolidated Financial Statements); and

n  limitations on liens.

The Company monitors the covenants on a regular basis in order to provide assurance that events of default will not occur. As of December 31, 2002, there were no events of default under the Company’s covenants.

Investing Activities

In 2002, the Company’s investing activities resulted in a net cash outflow of $857 million. These activities included plant construction and other property additions of $748 million and nuclear fuel expenditures of $59 million. Generation-related projects totaled approximately $393 million and included environmental upgrades, nuclear reactor head replacement expenditures and routine capital improvements. The Company spent approximately $322 million on transmission and distribution-related projects, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled $33 million. Investing activities also include $36 million of contributions to the Company’s nuclear decommissioning trusts. Other miscellaneous expenditures totaled $14 million.

Capital Requirements

The Company expects to fund its capital requirements and debt maturities with cash flow from operations and a combination of sales of securities and short-term borrowings.

Capacity

The Company anticipates that retail peak demand will grow approximately 1.0 percent each year through 2005, reflecting the continued growth in the number of retail customers expected to be served by the Company. However, sales under wholesale requirements contracts declined approximately $34 million in 2002 as compared to 2001, with further decreases expected as contracts expire in the future. Any future additional capacity and energy requirements through 2005 will be met primarily through market purchases.

Plant and Equipment

The Company’s generation construction and nuclear fuel expenditures during 2003, 2004 and 2005 are expected to total approximately $630 million, $395 million and $325 million, respectively. The Company’s annual transmission and distribution capital expenditures are expected to be approximately $55 million and $310 million, respectively, in each of the years 2003, 2004 and 2005. The Company’s distribution capital expenditures will primarily provide for customer growth, reliability initiatives and routine replacements.

In early 2002 the Company completed the installation of sulfur dioxide (SO₂) emission control equipment at two coal-fired generating units at a total cost of approximately $120 million. An additional $55 million has been budgeted through 2007 for the development of future SO₂ control projects.

In response to Clean Air Act requirements, the Company is installing nitrogen oxide (NOx) reduction equipment on all of its affected facilities at an estimated capital cost of $630 million of which $370 million has been incurred as of December 31, 2002. The installations are scheduled for completion by midyear 2004. The Company is also discontinuing the use of coal at its Possum Point station in Prince William County, Virginia. Two of the Possum Point station’s oil-fired units have been retired, and its two coal-fired units will be converted to gas at an estimated capital cost of $13 million, of which $5 million has been incurred as of December 31, 2002. See Environmental Matters for additional discussion of Clean Air Act matters.

The Company also plans to spend approximately $150 million in 2003 to complete the vessel head replacements at the North Anna and Surry nuclear stations. The total cost for this project is estimated to be $202 million, of which $52 million has been incurred as of December 31, 2002.

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Contractual Cash Obligations

Presented below is a summary of the Company’s contractual obligations as of December 31, 2002. These items are discussed in Notes 15, 16 and 21 to the Consolidated Financial Statements.

The Company expects to fund these obligations and commitments with cash flow from operations and a combination of sales of securities and short-term borrowings. These amounts do not include planned capital expenditures or working capital commitments, such as the repayment of short-term debt and settlement of derivative and energy trading contracts, or amounts for interest or distributions payable on securities issued by the Company.

In addition, the Company has entered into agreements with another Dominion subsidiary in order to develop, construct, finance and lease a new power generation facility at the Company’s Possum Point station in Prince William County, Virginia. The project is scheduled for completion in 2003 at an estimated cost of $370 million. Upon completion, the Company will operate the new generating facility under an operating lease with estimated annual lease payments of $20 million. See Note 21 to the Consolidated Financial Statements.

Future Issues and Outlook

Electric Deregulation Legislation

Virginia—Enacted in 1999, the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) establishes a plan to restructure Virginia’s electric utility industry and provides for the phase-in of choice for retail customers from January 1, 2002 through January 1, 2004. As ordered by the Virginia Commission, the Company made retail choice available for all of its Virginia regulated electric customers as of January 1, 2003.

Under the Virginia Restructuring Act, the generation portion of the Company’s Virginia jurisdictional operations was no longer subject to cost-based rate regulation as of January 1, 2002. The Company’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007, unless modified or terminated sooner under the Act. Recovery of generation-related costs will continue through capped rates and, where applicable, a wires charge assessed on those customers opting for alternative suppliers. The Company may petition the Virginia Commission to terminate the capped rates after January 1, 2004. If the Company were to request that the capped rates be terminated, the Virginia Commission may terminate the capped rates if it finds that a competitive generation services market exists within the Company’s service area.

Additionally, the Virginia Restructuring Act provides that after the end of the capped rate period, any default service provided by the Company will be based upon competitive market prices for electric generation services. The Virginia Commission has opened a proceeding to determine the components of default service in Virginia.

North Carolina—The North Carolina General Assembly has been exploring the future of electric service in North Carolina, the development of a competitive wholesale market and retail competition. However, to date, there has been no significant activity.

Virginia Commission Report on the Status of Competition in Virginia

In August 2002, the Virginia Commission submitted to the Governor and the Legislative Transition Task Force (Task Force) its status report on the development of a competitive retail market for electric generation within Virginia.

In an addendum to the report, the Virginia Commission recommended that state policymakers should decide promptly whether to proceed with or

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delay implementation of the Virginia Restructuring Act, in light of recent developments impacting electric industry restructuring in Virginia, including the FERC issuance of a notice of proposed rule making on Standard Market Design. No assessment can be made at this time concerning future developments.

Legislation that would delay entry into a regional transmission organization (RTO) until on or after July 1, 2004 was approved by the Virginia General Assembly in February 2003 and is now awaiting action by the Governor. The proposed legislation also would require the Company to file an application with the Virginia Commission by July 1, 2003 to join a RTO. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its transmission assets to a RTO by January 1, 2005.

Separation of Generation and Delivery Operations in Virginia

Under the Virginia Restructuring Act, the Company separated its generation, distribution, and transmission functions through creation of divisions within the Company. Virginia codes of conduct ensure that the Company’s generation and other divisions operate independently and prevent cross-subsidies between generation and other divisions.

Economic Risks and Benefits During the Transition to a Competitive Electric Marketplace in Virginia

As previously discussed, the Company will recover generation-related costs through capped rates and wires charges, where applicable, assessed to those customers opting for alternative suppliers during the transition period which extends until July 2007, unless modified or terminated earlier under the Virginia Restructuring Act. Under the Virginia Restructuring Act, the Company may request a termination of the capped rates at any time after January 1, 2004, and the Virginia Commission may grant the Company’s request to terminate capped rates, if it finds that a competitive generation services market exists in the Company’s service area. While the Company is exposed to certain risks as a result of the deregulation of its utility operations, it also has the opportunity to realize potential benefits during this transition period, if management is successful in preparing for the change in the environment in which its generation-related business operates.

Stranded Costs

Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market. At December 31, 2002, the Company’s exposure to potentially stranded costs consisted of long-term purchased power contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. The Company believes capped electric retail rates and, where applicable, wires charges, will provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Recovery of the Company’s potentially stranded costs remains subject to numerous risks even in the capped-rate environment. These include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs, and recovery of certain other items. These items are discussed in Notes 8 and 21 to the Consolidated Financial Statements.

The enactment of deregulation legislation in 1999 not only caused the discontinuance of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, for the Company’s utility generation-related operations but also caused the Company to review its utility generation assets for impairment and long-term power purchase contracts for potential loss at that time. Significant assumptions considered in that review included possible future market prices for fuel and electricity, load growth, generating unit availability and future capacity additions in the Company’s market, capital expenditures, including those related to environmental improvements, and decommissioning activities. Based on those analyses, no recognition of plant impairments or contract losses was appropriate at that time. In response to future events resulting from the development of a competitive market structure in Virginia and the expiration or termination of capped rates and wires charges, the Company may have to reevaluate its utility generation assets for impairment and long-term power purchase contracts for potential losses. Assumptions about future market prices for electricity represent a critical factor that affects the results of such evaluations. Since 1999, market prices for electricity have fluctuated significantly and will

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continue to be subject to volatility. Any such review in the future, which would be highly dependent on assumptions considered appropriate at that time, could possibly result in the recognition of plant impairment or contract losses that would be material to the Company’s results of operations or its financial position.

In December 2002, the Task Force requested the Virginia Commission to convene a work group on stranded costs. The work group will attempt to develop a consensus methodology for determining the over- or under-recovery of stranded costs. The Virginia Commission will report the work group’s findings to the Task Force by July 1, 2003. No assessment can be made at this time concerning future developments.

Changes to Cost Structure

While the Virginia Restructuring Act did not define specific generation-related costs to be recovered, it did provide generation-related cash flows (through the combination of capped rates and wires charges billed to

customers) during the transition period. The generation-related cash flows provided by the Virginia Restructuring Act are intended to compensate the Company for continuing to provide generation services and to allow management to incur costs to restructure such operations during the transition period. As a result, during the transition period, the Company may realize an increased rate of return on its generation-related operations to the extent that management can favorably alter the cost structure underlying its utility generation-related operations. Conversely, the same risks affecting the recovery of the Company’s stranded costs, discussed above, may also adversely impact its cost structure during the transition period. Accordingly, the Company could realize the negative economic impact of any such adverse event. In addition to managing the cost of its generation-related operations, the Company may also seek opportunities to sell available electric energy and capacity to customers beyond its electric utility service territory. Using cash flows from operations during the transition period, the Company may further alter its cost structure or choose to make additional investments in its business.

The capped rates were derived from rates established as part of the 1998 Virginia rate settlement and do not provide for specific recovery of particular generation-related expenditures, except for certain regulatory assets. See Note 10 to the Consolidated Financial Statements. To the extent that the Company manages its operations to reduce its overall operating costs below those levels contemplated by the capped rates, the Company’s earnings may increase. Since the enactment of the Virginia Restructuring Act, the Company has been reviewing its cost structure to identify opportunities to reduce the annual operating expenses of its generation- related operations. For example, the Company terminated certain long-term power purchase agreements in 2001, resulting in an after-tax charge of $136 million. See Note 21 to the Consolidated Financial Statements. By avoiding fixed capacity payments that would have otherwise been required under the contracts, annual after-tax earnings will increase by $30 million during the capped rate transition period.

Also in 2002 and 2001, the Company revised the estimated useful lives of its electric generation, transmission and distribution assets. The changes in estimates were based upon expected life-extensions of nuclear plants and new studies for the other assets. As a result of these changes, annual after-tax earnings will increase by approximately $88 million during the capped rate transition period. See Note 2 to the Consolidated Financial Statements.

Regional Transmission Organization

The Virginia Restructuring Act requires that the Company join a RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. FERC Order No. 2000 requires each public utility that owns or operates transmission facilities to make certain filings with respect to RTO formation, but will rely on voluntary formation of RTOs to advance its energy policies. By joining a RTO, the Company would transfer functional control of its transmission assets to a RTO, a third party.

In September 2002, the Company and PJM Interconnection, LLC (PJM) entered into the PJM South Implementation Agreement. The agreement provides that, subject to regulatory approval and certain provisions, the Company will become a member of PJM, transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region, integrate its control area into the PJM energy markets and otherwise facilitate the establishment and operation of PJM as the RTO with respect to the Company’s transmission facilities. The agreement also contemplates additional agreements and transmission tariff provisions to be negotiated by the parties and allocates costs of implementation of the agreement among the parties.

The Company intends to file for FERC approval to join PJM in the future. The Company will also seek

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authorization from the Virginia Commission and the North Carolina Commission to become a member of PJM at that time. The Company will incur integration and operating costs associated with joining a RTO. The Company has deferred certain of those costs for future recovery and is giving further consideration to seeking regulatory approval to defer the balance of such costs.

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

Also in December 2002, the Company filed with FERC an amendment to its open access transmission tariff to establish a transitional transmission rate method that would apply from the time American Electric Power and Commonwealth Edison Company would begin to participate under the PJM transmission tariff until the Company joins PJM.

Legislation that would delay entry into a RTO until on or after July 1, 2004 was approved by the Virginia General Assembly in February 2003 and is now awaiting action by the Governor. The proposed legislation also would require the Company to file an application with the Virginia Commission by July 1, 2003 to join a RTO. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its transmission assets to a RTO by January 1, 2005.

Wholesale Competition

The Company sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but has agreed not to make wholesale power sales under this tariff to loads located within its service territory. In February 2002, the Company received FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside its service territory. Any such sales would be voluntary.

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

Rate Matters

Virginia—The Company filed its Virginia Commission-approved unbundled rates reflecting the functional separation of generation, transmission and distribution in January 2002. Base rates (excluding fuel costs and certain other allowable adjustments) are capped and will remain unchanged until July 2007, unless modified or terminated sooner, as provided by the Virginia Restructuring Act. Under the Virginia Restructuring Act, the Company may request a termination of the capped rates at any time after January 1, 2004, and the Virginia Commission may grant the Company’s request to terminate capped rates, if it finds that a competitive generation services market exists in the Company’s service area. Where applicable, wires charges, effective January 1, 2002 and subject to annual adjustment, will be paid by the Company’s Virginia jurisdictional retail customers who choose an alternative generation supplier during the capped rate period.

In October 2002, the Virginia Commission approved the Company’s methodology for its 2003 market prices for generation, including a capacity adder and the resulting wires charges. The capacity adder reflects the capacity value that the sale of generation is expected to produce in addition to an energy value in market prices. Inclusion of the capacity adder in the market price calculation will reduce wires charge revenues by the amount of the expected additional revenue from the sale of the displaced capacity in the wholesale market.

The Company’s fuel factor for sales to Virginia jurisdictional customers will remain unchanged for 2003.

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

FERC Policy Developments

In July 2002, FERC issued proposed rules that would establish a standardized transmission service and wholesale electric market design for entities participating in wholesale electric markets. FERC proposed to exercise jurisdiction over the transmission component of bundled retail transactions, modify the existing electric transmission tariff to include a single tariff service

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applicable to all transmission customers and provide a standard market design for wholesale electric markets. FERC also proposed that transmission owners that have not yet joined a RTO must contract with a separate entity, an independent transmission provider, to operate their transmission facilities. FERC scheduled a number of technical conferences and meetings with interested parties and has indicated that the market design and timing of the rule is subject to change. No assessment can be made at this time concerning future developments.

FERC also continues to pursue a rulemaking that will eliminate separate standards of conduct regulations for natural gas pipelines and electric transmission utilities, and to replace these requirements with uniform standards applicable to interstate “Transmission Providers.” The proposed standards would redefine the scope of affiliates covered by standards of conduct for most FERC-regulated companies. If the proposed policy is adopted, it will supersede the existing standards that are applicable to the Company. The Company supports the policy goal to ensure competitive interstate energy markets; however, the Company has advocated adjustments to the proposed rules. The Company anticipates further action by FERC in early 2003. While the Company expects the outcome of a final rule to improve its ability to compete with similarly-situated transmission providers, it does not expect a final rule to have a short-term material impact on its results of operations, financial position or cash flows.

Environmental Matters

The Company is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

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

Environmental Protection and Monitoring Expenditures

The Company incurred approximately $117 million, $109 million and $90 million of expenses (including depreciation) during 2002, 2001 and 2000, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $115 million in 2003. In addition, capital expenditures related to environmental controls were $269 million, $197 million and $207 million for 2002, 2001 and 2000, respectively. The amount estimated for 2003 for these expenditures is $230 million.

Clean Air Act Compliance

The Clean Air Act requires the Company to reduce its emissions of sulfur dioxide (SO₂ ) and nitrogen oxide (NO_X ), which are gaseous by-products of fossil fuel combustion. The Clean Air Act’s SO₂ reduction program is based on the issuance of a limited number of SO₂ emission allowances. Each allowance permits the emission of one ton of SO₂ into the atmosphere. The allowances may be transacted with a third party. Implementation of projects to comply with SO₂ and NO_X limitations are ongoing and will be influenced by changes in the regulatory environment, availability of allowances, various state and federal control programs and emission control technology. In response to Clean Air Act requirements, the Company is installing NO_X reduction equipment on all of its affected facilities at an estimated capital cost of $630 million, of which $370 million has been incurred as of December 31, 2002. The installations are scheduled for completion by midyear 2004. The Company is also discontinuing the use of coal at its Possum Point Station in Prince William County, Virginia. Two of the Possum Point station’s oil-fired units have been retired, and the two coal-fired units will be converted to gas during 2003 at an estimated capital cost of $13 million. The Company installed SO₂ emission control equipment at two coal-fired generating units during 2002 at a total cost of $120 million. An additional $55 million has been budgeted through 2007 for the development of future SO₂ control projects.

The Environmental Protection Agency (EPA) is planning to issue additional regulations to address non-attainment of the new ozone and fine particulate standards within the next few years, as well as ongoing regulatory action associated with regional haze. That regulatory action could require additional reductions in SO₂ and NO_X emissions from the Company’s fossil fuel-fired generating facilities. In addition, EPA is in the process of developing a proposed standard for

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mercury emissions for electric utility coal-fired boilers that could require significant mercury emission reductions from all of the Company’s coal-fired generating units. If these more stringent emission reduction requirements are imposed in the future, new and perhaps significant expenditures could be required. The Company cannot predict the future financial impact of implementing these potential requirements on its operations at this time.

The United States Congress is considering various “multi-pollutant” legislative proposals that would require fossil-fuel fired generating units to comply with more stringent pollution control standards for air emissions. Many of the proposals would rely upon flexible cap and trade programs for compliance and would exempt covered facilities from other Clean Air Act requirements. They would phase-in the emission reduction requirements under a variety of timeframes, up to 16 years. The Company cannot predict whether any of these proposals will pass this year or in the future. However, if more stringent emissions standards are ultimately imposed on the Company’s generating units, new, perhaps significant, expenditures could be required. The Company cannot predict the future financial impact on its operations at this time.

During 2000, the Company received a Notice of Violation from the EPA, alleging that the Company failed to obtain New Source Review permits under the Clean Air Act prior to undertaking specified construction projects at the Mt. Storm Power Station in West Virginia. The Attorney General of New York filed a suit against the Company alleging similar violations of the Clean Air Act at the Mt. Storm Power Station. The Company also received notices from the Attorneys General of Connecticut and New Jersey of their intentions to file suit for similar violations. In December 2002, the Attorney General of Connecticut filed a motion to intervene as a plaintiff in the action filed by the New York State Attorney General. This action has been stayed. Management believes that the Company has obtained the necessary permits for its generating facilities. The Company has reached an agreement in principle with the federal government and the state of New York to resolve this situation. The agreement in principle includes payment of a $5 million civil penalty, a commitment of $14 million for environmental projects in Virginia, West Virginia, Connecticut, New Jersey and New York and a 12-year, $1.2 billion capital investment program for environmental improvements at the Company’s coal-fired generating stations in Virginia and West Virginia. The Company had already committed to a substantial portion of the $1.2 billion expenditures for SO₂ and NO_X emissions controls. The negotiations over the terms of a binding settlement have expanded beyond the basic agreement in principle and are ongoing. As of December 31, 2002, the Company has recorded, on a discounted basis, $18 million for the civil penalty and environmental projects.

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

Global Climate Change

In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18 percent over the next 10 years. However, the United States Congress is considering legislation that could impose mandatory reductions of greenhouse gas emissions. The cost of compliance with the Protocol or other mandatory greenhouse gas reduction obligations could be significant for the Company. Given the highly uncertain outcome and timing of future action by the U.S. federal government on this issue, the Company cannot predict the financial impact of future climate change actions on its operations at this time.

Clean Water Act Compliance

Under authority of the Clean Water Act, the EPA is promulgating new regulations governing utilities that employ a cooling water intake structure, with flow levels that exceed a minimum threshold. As currently written, the EPA’s proposed rule presents several control options under consideration for the final rule. The Company is evaluating facility information from Bremo, Chesapeake, Chesterfield, Mt. Storm, North Anna, Possum Point, Surry and Yorktown power stations. Given the uncertainties of future action by the EPA on this issue, the Company cannot predict the future impact on its operations at this time.

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Accounting Matters

The FASB has issued several new standards that will affect the Company beginning in 2003. These include: SFAS No. 143, Accounting for Asset Retirement Obligations; Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Others—An Interpretation of FASB Statements No. 5, 57 and 107; and Interpretation No. 46, Consolidation of Variable Interest Entities. In addition, the EITF rescinded EITF Issue No. 98-10. See Note 4 to the Consolidated Financial Statements for further discussion of the impact of adopting these new accounting standards and information about other standard-setting activities.

Outlook for 2003

The Company believes its operating businesses will provide growth in earnings in 2003. However, reported earnings for 2003 will also include the effects of severance costs under the workforce reduction plan discussed below and the cumulative effect of implementing changes in accounting for asset retirement obligations and energy trading activities. See Note 4 to the Consolidated Financial Statements. The 2003 projections for the Company’s operating businesses anticipate continued growth in electric utility service customers, which would be, however, offset by higher pension benefit expense and the effect of assuming normal weather, as compared to 2002.

Other Matters

Pension Costs

As discussed in Note 20 to the Consolidated Financial Statements, the Company participates in the Dominion pension plan, a qualified noncontributory defined benefit retirement plan. As a participating employer, the Company is subject to Dominion’s funding policy, which is to generally contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. Investment experience and market conditions, including interest rates, impact the measurement of these benefit obligations and the cost of providing such benefits. Accordingly, assumptions for discount rates and the expected long-term rate of return on investments are important considerations under SFAS No. 87, Employers’ Accounting for Pensions. However, since the objective of SFAS No. 87 is to recognize the cost of providing benefits over employees’ service period, it permits the delayed recognition of certain elements of retirement plan results.

Dominion has reviewed the assumption used for expected long-term rate of return on plan assets to better reflect anticipated future market conditions and has adopted an expected rate of 8.75 percent for 2003. This change, combined with other factors such as a revised discount rate assumption of 6.75 percent for 2003, will increase the Company’s 2003 pension expense by an estimated $22 million, as compared to 2002. In addition, in order to maintain the funded status of Dominion’s retirement plans, Dominion and its subsidiaries, including the Company, may have to contribute increased amounts to the plans in future years.

Workforce Reductions

In connection with a plan announced by Dominion in January 2003, the Company expects to eliminate some union and salaried jobs during 2003. The workforce reductions will affect primarily support positions including meter readers, supply and warehouse workers and auto mechanics. Many of the reductions result from investments in automated meter-reading technology and purchases of newer, lower maintenance vehicles. Affected workers will be offered severance packages, and benefits for union workers will be negotiated during 2003. Pending completion of the process to identify affected positions, the Company has not estimated the cost of the workforce reductions.

Change in Composition of Operating Segments

Effective January 1, 2003, the Company’s electric transmission operations will be reported as a part of the Energy segment instead of the Delivery segment.

Nuclear Relicensing

The Company filed applications for 20-year life-extensions for the North Anna and Surry units in May 2001 with the NRC. The NRC has completed its review of the applications. The Company expects to receive a renewed license for these units in 2003.

Nuclear Insurance

The Price-Anderson Act expired in August 2002, but operating nuclear reactors would continue to be covered by the law, which would channel and cap claims if a nuclear accident should occur. The Act has been renewed three times since 1957, and Congress is currently holding hearings to reauthorize the legislation. The expiration of the Act does not impact the coverage of existing nuclear license holders.

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Effect of Changes in Commodity Prices

The Company’s operations are impacted by changes in energy commodity prices. To the extent that energy commodities are sold by the Company and such sales are subject to cost-of-service rate regulation, the commodity costs are generally recovered through rates. Market price changes impact the Company’s revenues from commodity sales through unregulated subsidiaries. The Company has established an enterprise risk management function to evaluate these risks and to recommend actions to management that are intended to mitigate such risks.

Market Rate Sensitive Instruments and Risk Management

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

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

Commodity Price Risk—Trading Activities

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of 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 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 $30 million and $7 million in the fair value of its commodity contracts held for trading purposes as of December 31, 2002 and 2001, respectively.

Interest Rate Risk

The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2002, a hypothetical 10 percent increase in market interest rates would decrease annual earnings by approximately $2 million. A hypothetical 10 percent increase in market interest rates, as determined at December 31, 2001, would have resulted in a decrease in annual earnings of approximately $2 million.

Foreign Exchange Risk

The Company manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel uranium enrichment services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, the Company’s exposure to foreign currency risk is minimal. A hypothetical 10 percent unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $17 million and $5 million in the fair value of currency forward contracts held by the Company at December 31, 2002 and 2001, respectively.

Investment Price Risk

The Company is subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. As described in Note 8 to the Consolidated Financial Statements, the Company recognized net realized and unrealized losses on decommissioning trust investments of $56 million for 2002 and $29 million for 2001.

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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 by the Company to the employee benefit plans.

Risk Management Policies

The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements, where deemed necessary, and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Management believes, based on Dominion’s credit policies and the Company’s December 31, 2002 provision for credit losses, that it is unlikely that a material adverse effect on the Company’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

See Risk Factors and Cautionary Statements That May Affect Future Results and Market Rate Sensitive Instruments and Risk Management in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Index

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Report of Management

The Company’s management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company’s annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.

Management maintains a system of internal controls designed to provide reasonable assurance, at a reasonable cost, that the Company’s assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 2002 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and included a review of the Company’s accounting systems, procedures and internal controls to the extent necessary for the purpose of its report.

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

Virginia Electric and Power Company

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Independent Auditors’ Report

To the Board of Directors of

Virginia Electric and Power Company

Richmond, Virginia

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

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

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

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

/s/    DELOITTE & TOUCHE LLP

Richmond, Virginia

January 21, 2003

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Virginia Electric and Power Company

Consolidated Statements of Income

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

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Virginia Electric and Power Company

Consolidated Balance Sheets