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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

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.  x

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 June 30, 2003 and February 27, 2004, was zero.

As of February 2, 2004, 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.

None

Virginia Electric and Power Company.

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Part 1

Item 1. Business

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 operations through three primary operating segments. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.

Delivery manages the Company’s electric distribution systems and customer service operations.

Energy manages the Company’s electric transmission and energy trading, hedging and arbitrage activities.

Generation manages the Company’s portfolio of electric generating facilities and power purchase contracts.

The majority of the Company’s revenue is provided through bundled rate tariffs. This revenue is allocated between the Delivery, Energy and Generation 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 24 to the Consolidated Financial Statements.

As of December 31, 2003, the Company had approximately 7,300 full-time employees. Approximately 3,400 employees are subject to collective bargaining agreements.

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

Seasonality

Sales of electricity in the Delivery and Generation segments typically vary seasonally based on increased demand for electricity by residential and commercial customers for cooling and heating use due to 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. See Risk Factors and Cautionary Statements That May Affect Future Results in Item 7. Management’s Discussion and Analysis of Results of Operations (MD&A) for additional information on how weather may affect the Company’s results of operations.

Regulation

The Company is subject to regulation by the Securities and Exchange Commission (SEC), Federal Energy Regulatory Commission (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 Regulatory Matters

The Company is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission).

The Company holds certificates of public convenience and necessity authorizing it to maintain 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.

Status of Electric Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed among other things: capped base rates, regional transmission organization (RTO) participation, retail choice, the recovery of stranded costs and the functional separation of a utility’s electric generation from its electric transmission and distribution operations.

Retail choice has been available to all of the Company’s Virginia regulated electric customers since January 1, 2003. The Company has also separated its generation, distribution and transmission functions through the creation of divisions. Virginia codes of conduct ensure that Virginia Power’s generation and other divisions operate independently and prevent cross-subsidies between the generation and other divisions.

Since the passage of the Virginia Restructuring Act, the competitive environment has not developed in Virginia as

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anticipated. In January 2004, legislation supported by the offices of the Governor and the Attorney General of Virginia was submitted to the Virginia General Assembly that would extend the capped base rates by three and one-half years, through December 31, 2010. The bill was supported by the Company and was approved by the Virginia Senate in late January 2004. In addition to extending capped rates, the bill would:

n Lock in the Company’s fuel factor until the earlier of July 1, 2007 or the termination of capped rates through Virginia Commission order;

n Provide for a one-time adjustment of the Company’s fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery of fuel costs, and thus would eliminate deferred fuel accounting; and

n End wires charges on the earlier of July 1, 2007, or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

Other bills were introduced in the Virginia House of Delegates that would repeal the Virginia Restructuring Act, suspend most of the Virginia Restructuring Act, suspend customer choice, and re-impose “cost of service” rate making. Legislation calling for suspension of the Virginia Restructuring Act’s key provisions and a return to the cost-of-service regulatory methodology was defeated in a House committee in early February. Other measures have been deferred to 2005 by a House Committee. Until the legislative process is concluded, no assessment can be made concerning future developments.

See Status of Deregulation in Virginia in Future Issues and Other Matters in MD&A for additional information on capped base rates, stranded costs and RTO participation.

Retail Access Pilot Programs

In September 2003, the Virginia Commission approved the Company’s application for three proposed electric retail access pilot programs. The programs were proposed by the Company to stimulate the development of retail electric competition in Virginia. The pilot programs are to run through the remainder of the capped rate period and will make available to competitive service providers up to 500 megawatts of load, with expected participation of more than 65,000 customers from a variety of customer classes. The programs were scheduled to begin in February 2004. However in January 2004, the Company asked the Virginia Commission for an extension in the start of the programs by 60 days so that it may address deregulation legislation under consideration by the Virginia General Assembly, increased market prices for electricity due to colder weather and reevaluate the size and design of the programs due to the large number of volunteers. In February 2004, the Virginia Commission granted the 60-day extension.

Rate Matters

Virginia—In December 2003, the Virginia Commission approved the Company’s proposed settlement of its 2004 fuel factor increase of $386 million. The settlement includes a recovery period for the under-recovery balance over three and a half years. Approximately $171 million of the $386 million would be recovered in 2004, $85 million in 2005, $87 million in 2006 and $43 million in the first six months of 2007.

Under current Virginia law, the Company is permitted to request adjustments to its fuel rates, subject to the Virginia Restructuring Act. The Company is generally permitted to pass the cost of recoverable fuel and certain purchased power costs to its customers through a fuel factor, to the extent the Virginia Commission determines after hearing that such costs are prudently incurred. Certain proposed modifications to the timing and scope of fuel adjustments are the subject of proposed legislation in the Virginia General Assembly which is discussed in Status of Electric Deregulation in Virginia.

North Carolina—In connection with the North Carolina Commission’s approval of the Consolidated Natural Gas Company (CNG) acquisition, the Company agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on the Company’s electric utility operations. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. In January 2004, the North Carolina Public Staff requested that the North Carolina Commission initiate an investigation into the Company’s North Carolina base rates and sought a decrease in base rates. The Company believes that its base rates are reasonable and intends to respond to the filing; however, the Company cannot predict the outcome of this matter at this time.

Public Utility Holding Company Act of 1935 (1935 Act)

Dominion is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern 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 also suffice for 1935 Act purposes, 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 does not 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

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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, liquid hydrocarbon by-products and oil in wholesale markets are not regulated by FERC.

The Virginia Restructuring Act requires that the Company join an RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. The Company and PJM Interconnection, LLC (PJM) entered into an agreement in September 2002 that provides that, subject to regulatory approval and certain provisions, the Company will become a member of PJM and transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region. However, in April 2003, Virginia enacted legislation that required the Company to file an application with the Virginia Commission by July 1, 2003 to an RTO and delayed entry into an RTO until on or after July 1, 2004. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its electric transmission assets to an RTO by January 1, 2005. See RTO in Future Issues and Other Matters in MD&A for additional information on this matter.

In November 2003, FERC issued new Standards of Conduct governing conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The new rule redefines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing function or affiliates undue preferences. All transmission providers must be in compliance by June 2004. The Company has adopted an implementation plan and will train the appropriate personnel to ensure compliance with the new rules.

Environmental Regulations

Each operating segment 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 Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 20 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 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.

In December 2003, the EPA announced plans to propose additional regulations addressing pollution transport from electric generating plants as well as the regulation of mercury and nickel emissions. These regulatory actions, in addition to revised regulations expected to be issued in 2004 to address regional haze, could require additional reductions in emissions from the Company’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, additional significant expenditures may be required.

The United States Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 16 years. If these new proposals are adopted, additional significant expenditures may be required.

The EPA has announced the publication of new regulations that govern existing utilities that employ a cooling water intake structure, and whose flow levels exceed a minimum threshold. As announced, the EPA’s rule presents several control options. The Company is evaluating facility information from certain of its power stations. The Company cannot predict the future impact on its operations at this time.

The Company has applied for or obtained the necessary environmental permits for the operation of its regulated facilities. 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, which are part of the Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

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 be financially prepared. For information on the Company’s decommissioning trusts, see Note 8 to the Consolidated Financial Statements.

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Interconnections

The Company maintains major interconnections with Progress Energy, American Electric Power Company, 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 RTO in Future Issues and Other Matters in MD&A.

Competition

Deregulation and restructuring in the electric industry continue to create issues that affect or will likely affect the markets where the Company does business, and govern the way the Company and its competitors operate. The electric power industry continues to evolve into a competitive marketplace where energy companies will compete to provide energy and energy services to a broad range of customers.

As noted earlier, the Company has made retail choice available for all of its Virginia regulated electric customers since January 1, 2003. For additional information on electric deregulation in Virginia, see Status of Electric Deregulation in Virginia in Future Issues and Other Matters in MD&A.

In North Carolina, regulators and legislators have explored 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.

Availability of 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

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

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.

Item 2. Properties

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 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 Energy segment has approximately 6,000 miles of electric transmission lines. Portions of the electric 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 Company leases its headquarters facility from Dominion. In addition, the Delivery, Energy and Generation segments share certain leased buildings and equipment.

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The Generation segment provides electricity for use on a wholesale and a retail level. The Generation segment can supply electricity demand either from its generation facilities in Virginia, North Carolina and West Virginia or through purchased power contracts when needed. The following table lists the Company’s generating units and capability.

Virginia Electric and Power Company’s Power Generation

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Nuclear Decommissioning

The Company has four licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia that serve customers of the Company’s regulated electric utility operations. Decommissioning represents the decontamination and removal of radioactive contaminants from a nuclear power plant, once operations have ceased, in accordance with standards estab-lished by the NRC. Through July 2007, amounts are being collected from ratepayers and placed in trusts and invested to fund the expected costs of decommissioning the Surry and North Anna units.

The total estimated cost to decommission the Company’s four nuclear units is $1.5 billion based upon site-specific studies completed in 2002. The Company expects to perform new cost studies in 2006. The cost estimate assumes that the method of completing decommissioning activities is prompt dismantlement. During 2003, the NRC approved the Company’s application for a 20-year life extension for the Surry and North Anna units. The Company expects to decommission the units during the period 2032 to 2045.

Item 3. Legal Proceedings

From time to time, the Company is alleged to be in violation of 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. Administrative proceedings may also be pending on these matters. 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 in Item 1. Business and Note 20 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

In connection with a Notice of Violation received by Virginia Power in 2000 from the EPA and related proceedings, the Virginia federal district court entered the final Consent Decree in October 2003 involving Virginia Power, the U.S. Department of Justice, the EPA and five states. Under the settlement, Virginia Power paid a $5 million civil penalty, agreed to fund $14 million for environmental projects and committed to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of December 31, 2003, the Company had recognized a provision for the funding of the environmental projects, substantially all of which was recorded in 2000.

In June 2002, Wiley Fisher, Jr. and John Fisher filed a purported class action lawsuit against Virginia Power 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 Virginia Power’s electric transmission lines and on or in which fiber optic cable has been installed.” Discovery has begun and the court has granted a motion to add additional plaintiffs, Harmon T. Tomlinson, Jr. and Linda D. Tomlinson. In August 2003, the federal district court issued an order granting the plaintiff’s motion for class certification. The U.S. Court of Appeals for the Fourth Circuit denied the Company’s petitions for appeal on the class certification issue. The outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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Part II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

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

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

Item 6. Selected Financial Data

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 Electric and Power Company. 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 Electric and Power Company’s consolidated subsidiaries or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion).

Contents of MD&A

The reader will find the following information in this MD&A:

n Forward-Looking Statements

n Introduction

n Accounting Matters

n Results of Operations

n Segment Results of Operations

n Sources and Uses of Cash

n Future Issues and Other Matters

n Risk Factors and Cautionary Statements That May Affect Future Results

Forward-Looking Statements

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.

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The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

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.

Introduction

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

Maintaining and improving the Company’s financial condition and flexibility is of paramount importance to its management. Important measures of an entity’s financial strength and creditworthiness are the credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc. (Standard & Poor’s). Those agencies have determined the Company’s credit ratings to be investment grade.

The Company’s businesses are managed along three primary operating segments: Generation, Energy and Delivery. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.

The contributions to net income by the Company’s primary operating segments are determined based on a measure of profit that executive management believes represents the segments’ “core” earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment.

Generation includes the Company’s electric generation operations. The fuel mix used by these operations is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. The Company’s strategy for its electric generation operations focuses on serving customers in Virginia and northeastern North Carolina. Its generation facilities are located in Virginia, West Virginia and North Carolina.

Utility generation operations provide the Generation segment’s sources of revenue and cash flows. These operations are sensitive to external factors, primarily weather. Currently, revenue from utility operations largely reflects the capped rates charged to customers in Virginia, the majority of its utility customer base. Under Virginia’s current deregulation legislation, electric base rates are capped through mid-2007. As rates are capped, changes in the Generation segment’s operating costs, relative to costs recovered in the capped rates, will impact the Company’s earnings.

The Generation segment has reduced costs by terminating certain long-term power purchase agreements and, based on engineering studies, extended the estimated useful lives of generation assets, reducing the annual depreciation expense for those assets. Currently, legislators in Virginia are evaluating the future of electric deregulation in Virginia as well as the possibility of extending the capped rates period.

Variability in expenses for the Generation segment relates primarily to the cost of fuel consumed and the timing, duration and costs of scheduled outages. The Company is currently permitted to seek rate-recovery for fuel costs associated with utility operations.

Energy includes the following operations:

n A regulated electric transmission system located in Virginia and northeastern North Carolina; and

n The Company’s Clearinghouse operations (Clearinghouse), which is responsible for energy trading, hedging and arbitrage activities.

The Energy segment’s revenue and cash flows are derived from both regulated and non-regulated operations.

Revenue and cash flows provided by regulated electric transmission operations are based primarily on rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flows provided by this business results from fluctuation in throughput which is primarily weather dependent. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding use of resources for operations and maintenance or capital-related activities.

Revenue and cash flows for the Energy segment’s Clearinghouse business are subject to variability associated with changes in commodity prices. The Energy segment’s non-regulated Clearinghouse business uses physical and financial commodity contracts to hedge this price risk. Certain hedging and trading activities may require cash deposits to satisfy

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margin requirements. In addition, reported earnings for this segment reflect changes in the fair value of certain derivatives; these values may change significantly from period to period. Variability in expenses for these non-regulated businesses relates largely to labor and benefits and the costs of purchased commodities for resale and payments under financially-settled contracts.

Delivery includes the Company’s electric distribution systems and customer service operations. Electric distribution operations serve customers in Virginia and northeastern North Carolina.

Revenue and cash flows provided by electric distribution operations are based primarily on rates established by state regulatory authorities. Variability in the Delivery segment’s revenue and cash flows relates largely to changes in sales volumes, which are primarily weather sensitive.

Variability in expenses results from changes in the cost of routine maintenance and repairs (including labor and benefits as well as decisions regarding the use of resources for operations and maintenance or capital-related activities) and storm-related damage to property, such as the recent property damage caused by Hurricane Isabel.

Corporate and Other includes the Company’s corporate and other functions and specific items attributable to the Company’s operating segments that are reported in Corporate and Other.

Accounting Matters

Critical Accounting Policies and Estimates

The Company has identified the following accounting policies, including certain inherent estimates, 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 derivative 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. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.

Generally, derivatives are reported on the Consolidated Balance Sheets at fair value. In addition, in 2002 and prior years, all energy trading contracts were reported at fair value. As a result of new accounting requirements beginning in 2003, non-derivative trading contracts are no longer reported at fair value. Prior period financial statements were not restated for this change. Changes in the fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, 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 considered appropriate by 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 the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.

Use of estimates in long-lived asset impairment testing

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset’s carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on relevant 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.

Asset retirement obligations

The Company recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These asset retirement obligations (AROs) are recognized at fair value as incurred, and are capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, the Company estimates the fair value of its AROs using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using its credit-adjusted risk free rate. AROs currently reported on the Company’s Consolidated Balance Sheet were measured during a period of historically low interest rates. The impact on measurements of new AROs, using different rates in the future, may be significant.

A significant portion of the Company’s AROs relates to the future decommissioning of its nuclear facilities. At December 31, 2003, nuclear decommissioning AROs totaled $716 million, which represented approximately 97% of the Company’s total AROs. Because of their significance, the

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following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with the Company’s nuclear decommissioning obligations.

The Company obtains from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which the Company considers to be a critical assumption.

The Company determines cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of its nuclear facilities. The weighted average cost escalation used by the Company was 3.28%. The use of alternative rates would have been material to the liabilities recognized. For example, had the Company increased the cost escalation rate by 0.5% to 3.78%, the amount recognized as of December 31, 2003 for its AROs related to nuclear decommissioning would have been $140 million higher.

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 non-regulated 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 or amounts collected from customers for expenditures not yet incurred. 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 on orders issued by regulatory commissions, 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 11 to the Consolidated Financial Statements.

Newly Adopted Accounting Standards in 2003

During 2003, the Company was required to adopt several new accounting standards, which affect the comparability of its Consolidated Financial Statements. The requirements of those standards are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The following discussion is presented to provide an understanding of the financial statement impacts of those standards when comparing the 2003 Consolidated Financial Statements to prior years.

SFAS No. 143

Adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003 affected the comparability of the Company’s 2003 Consolidated Financial Statements to those of prior years as follows:

n Recognition of asset retirement obligations of $697 million compared to a liability of $838 million that had been previously recorded for nuclear decommissioning;

n Recognition of $175 million of capitalized asset retirement costs in property, plant and equipment and a $77 million increase in accumulated depreciation and amortization, representing the depreciation of such costs through December 31, 2002;

n Beginning in 2003, accretion of the AROs for nuclear decommissioning is reported in other operations and maintenance expense. Previously, expenses associated with the provision for nuclear decommissioning were reported in depreciation and amortization expense and in other expense, as described below; and

n Beginning in 2003, realized and unrealized earnings of trusts available for funding decommissioning activities at the Company’s nuclear plants are recorded in other income and other comprehensive income, as appropriate. Previously, as permitted by regulatory authorities, these earnings were recorded in other income with an offsetting charge to expense, also recorded in other income, for the accretion of the decommissioning liability.

EITF 02-3 and 03-11

The adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities and the related EITF 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, changed the timing of recognition in earnings for certain Clearinghouse energy-related contracts, as well as the financial statement presentation of gains and losses associated with energy-related contracts. The Consolidated Statements of Income for 2002 and 2001 were not restated. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value and settlements reported in revenue on a net basis. Specifically, adopting EITF 02-3 and 03-11 affected the comparability of the Company’s 2003 Consolidated Financial Statements to those of prior years as follows:

n For derivative contracts not held for trading purposes that involve physical delivery of commodities, unrealized gains and losses and settlements on sales contracts are presented in

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revenue, while unrealized gains and losses and settlements on purchase contracts are reported in expense; and

n Non-derivative energy-related contracts, previously subject to fair value accounting under prior accounting guidance, are no longer subject to fair value accounting. The Company recognizes revenue or expense on a gross basis at the time of contract performance, settlement or termination.

FIN 46R

Upon adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R), on December 31, 2003 with respect to special purpose entities, the Company was required to consolidate a variable interest lessor entity through which the Company had financed and leased a power generation project. As a result, the Consolidated Balance Sheet at December 31, 2003 reflected an additional $364 million in net property, plant and equipment and deferred charges and $370 million of related debt.

In addition, under FIN 46R, the Company reports its junior subordinated notes held by an affiliated trust as long-term debt, rather than the trust preferred securities issued by the trust. At December 31, 2002, the Company consolidated the trust and reported the trust preferred securities on its Consolidated Balance Sheet.

Results of Operations

Following is a summary of contributions by its operating segments to net income for the years ended December 31, 2003, 2002 and 2001:

Overview

2003 vs. 2002

Net income decreased 27% to $561 million, as compared to 2002. The decrease included the net impact of a $21 million after-tax loss for the cumulative effect of changes in accounting principles, resulting from the adoption of the following new accounting standards:

n $139 million after-tax gain—adoption of SFAS No. 143;

n $101 million after-tax loss—adoption of SFAS No. 133 Implementation Issue C20;

n $55 million after-tax loss—adoption of EITF 02-3; and

n $4 million after-tax loss—adoption of FIN 46R.

The decrease in net income was also impacted by the following items recognized in 2003 and reported in the Corporate and Other segment:

n $197 million ($122 million after-tax) of incremental restoration expenses associated with Hurricane Isabel;

n $105 million ($65 million after-tax) cost of terminating two long-term power purchase agreements;

n $21 million ($12 million after-tax) of charges associated with the restructuring of power sales contracts; and

n $8 million ($5 million after-tax) of severance costs associated with workforce reductions.

2002 vs. 2001

Net income increased 73% to $773 million, as compared to 2001. The increase in net income reflected the impact of the following items recognized in 2001 that did not recur in 2002. These items were reported in the Corporate and Other segment:

n $220 million ($136 million after-tax) cost of terminating certain long-term power purchase contracts; and

n $48 million ($29 million after-tax) of severance costs for workforce reductions.

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Analysis of Consolidated Operations

Presented below are selected amounts related to the Company’s results of operations for the years ended December 31, 2003, 2002 and 2001:

An analysis of the Company’s results of operations for 2003 compared to 2002 and 2002 compared to 2001 follows:

2003 vs. 2002

Operating Revenue

Regulated electric sales revenue increased less than 1% to $4.9 billion, primarily reflecting the following:

n A $54 million increase representing customer growth associated with new customer connections; and

n A $42 million increase resulting from fuel rate recoveries. Fuel rate recoveries were generally offset by a comparable increase in fuel expense and did not materially affect net income. These increases were partially offset by:

n A $103 million decrease associated with milder weather; and

n Decreases in sales revenue due to hurricane-related outages.

Non-regulated gas sales revenue increased 553% to $263 million, reflecting higher margins in Clearinghouse gas sales, net of applicable purchases, due to favorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3. The increase included $54 million associated with the economic hedges (described further in the discussion of the Energy segment’s results).

Other revenue increased 167% to $254 million, reflecting:

n A $52 million increase in coal sales revenue; and

n A $115 million increase resulting from a change in the classification of coal purchases from other revenue to expense under EITF 02-3 beginning in 2003.

Operating Expenses and Other Items

Electric fuel and energy purchases, net increased 15% to $1.5 billion, primarily reflecting:

n A $123 million increase associated with non-regulated energy trading operations, primarily resulting from higher volumes purchased and the reclassification of certain purchase contracts after the implementation of EITF 02-3; and

n A $68 million increase related to regulated operations, including $42 million associated with rate recovery in revenue and the recognition of $14 million of previously deferred fuel costs that will not be recovered under the settlement of the Virginia jurisdictional fuel rate case.

Purchased electric capacity expense decreased 12% to $607 million, reflecting scheduled rate reductions on certain non-utility generation supply contracts ($54 million) and lower purchases of capacity for utility operations ($30 million).

Other purchased energy commodities were $304 million, reflecting the reclassification of certain purchase contracts for transportation, storage and coal after the adoption of EITF 02-3.

Other operations and maintenance expense rose 43% to $1.3 billion, primarily reflecting the impact of the following 2003 items:

n Incremental restoration expenses associated with Hurricane Isabel ($197 million);

n Cost of terminating two power purchase contracts used in electric utility operations ($105 million);

n A charge associated with the restructuring of certain electric sales contracts ($21 million);

n Accretion expense for asset retirement obligations ($38 million); and

n Expenses associated with nuclear refueling outages ($13 million).

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Depreciation and amortization expense decreased 7% to $458 million, primarily reflecting the change in the presentation of expenses associated with asset retirement obligations.

Other taxes increased 14% to $173 million, primarily due to the effect of a favorable resolution of sales and use tax issues in 2002. Such benefits were not recognized in 2003.

Other income increased 153% to $81 million, primarily reflecting net realized gains and income ($34 million) associated with nuclear decommissioning trust fund investments.

Cumulative effect of changes in accounting principles—During 2003, the Company was required to adopt several new accounting standards, resulting in a net after-tax loss of $21 million, which included the following:

n A $139 million after-tax gain (SFAS No. 143);

n A $101 million after-tax loss (SFAS No. 133 Implementation Issue No. C20);

n A $55 million after-tax loss (EITF 02-3); and

n A $4 million after-tax loss (FIN 46R).

2002 vs. 2001

Operating Revenue

Regulated electric sales revenue increased 5% to $4.9 billion, primarily due to:

n A $195 million increase resulting from favorable weather conditions, reflecting increased cooling and heating degree-days in 2002;

n A $60 million increase resulting from customer growth; and

n A $65 million increase in fuel rate recoveries, which was generally offset in fuel expense and did not materially affect net income; partially offset by

n Other factors not separately measurable, such as the impact of economic conditions on customer usage, as well as variations in seasonal rate premiums and discounts.

Non-regulated electric sales revenue decreased 57% to $78 million, reflecting:

n A $74 million decrease in revenue from the wholesale marketing of utility generation. Due to the higher demand of utility service territory customers during 2002, less production from utility plant generation was available for profitable sale in the wholesale market; and

n A $31 million decrease in Clearinghouse electric revenue, net of applicable trading purchases, reflecting the effect of unfavorable changes in the fair value of contracts and lower margins.

Non-regulated gas sales revenue decreased 207% to $58 million, primarily reflecting a decrease in Clearinghouse gas revenue, net of applicable trading purchases, due to unfavorable changes in the fair value of contracts and lower overall margins. The decrease included $70 million associated with the economic hedges discussed in the Energy segment’s results.

Other revenue increased 9% to $95 million, primarily reflecting an increase from sales of coal.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 2% to $1.3 billion, reflecting an increase of $29 million related to regulated utility operations, including $66 million subject to rate recovery, partially offset by a $37 million decrease in fuel expenses associated with lower wholesale marketing of utility plant generation.

Other operations and maintenance expense decreased 29% to $900 million, primarily reflecting:

n A $220 million cost of terminating certain long-term power purchase contracts in 2001;

n A decrease ($68 million) in 2002 scheduled outages and routine maintenance costs at both nuclear and fossil plants;

n $48 million of severance costs for workforce reductions in 2001; and

n A decrease ($27 million) in 2002 general and administrative expenses.

Depreciation and amortization expense decreased 4% to $495 million, primarily reflecting a $40 million decrease associated with the extension of estimated useful lives of most fossil fuel stations and electric transmission and distribution properties in 2002.

Other taxes decreased 15% to $152 million, primarily due to a reduction in average business and occupation tax rates and the recognition of a favorable resolution of prior year’s sales and use tax issues in 2002.

Income taxes increased 49% to $425 million, reflecting higher income before income taxes, as compared to 2001. The Company’s effective tax rate decreased from 39.1% to 35.5% in 2002, primarily due to a net benefit related to permanent differences, a reduction in percentages of state income taxes to book income and a decrease in book depreciation of regulated assets.

Outlook

The Company believes its operating businesses will provide stable growth in net income. The following are factors that will impact these expected results:

n Potential increase in regulated electric sales, as compared to 2003, assuming the Company’s utility service territories experience a return to normal weather in 2004;

n Continued growth in electric utility customers;

n Reduced electric capacity expenses, resulting from terminated contracts;

n Lower interest expense as a result of refinanced debt;

n Expected Six Sigma benefits; and

n Specific costs and reductions to earnings in 2003 that are not expected to recur in 2004, including:

n Lost revenue due to Hurricane Isabel;

n The Virginia fuel rate case settlement; and

n Costs associated with refinancing callable debt.

These growth factors will be partially offset by:

n Increased pension and other postretirement benefit costs; and

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n Normalization of Clearinghouse contribution.

Based on these projections, the Company estimates that cash flows from operations will increase in 2004, as compared to 2003. Management believes this increase will provide sufficient cash flows to maintain or grow the Company’s current dividend to Dominion.

Segment Results of Operations

Generation Segment

The Generation segment includes the Company’s electric generation operations.

The Generation segment provides electricity primarily from nuclear, coal, oil and purchased power. Presented below is a summary of the system’s energy output by energy source.

Presented below are the key factors impacting the Generation segment’s operating results:

2003 vs. 2002

The Generation segment had a decrease of $82 million in net income, as compared to 2002, primarily reflecting the following:

n A change in the allocation of electric base rate revenue among the Generation, Energy and Delivery segments effective January 1, 2003;

n A decrease in regulated electric sales due to comparably milder summer weather, resulting from a decrease in cooling degree days in 2003, partially offset by an increase in heating degree days in 2003;

n An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers;

n Scheduled decreases in capacity expenses under certain power purchase agreements;

n Recognition of previously deferred fuel costs in connection with the Virginia rate settlement; and

n Increased outage expenses, reflecting nuclear refueling outages in 2003 at the Company’s nuclear generating units.

2002 vs. 2001

The Generation segment’s net income contribution increased $157 million, as compared to 2001, primarily reflecting the following:

n An increase in regulated electric sales due to comparably warmer summer weather in 2002, resulting from an increase in cooling degree days;

n An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers; and

n Lower outage costs relating to the fossil & hydro units due to fewer planned outages.

Energy Segment

The Energy segment includes the Company’s electric transmission business, as well as the Company’s Clearinghouse (energy trading, hedging and arbitrage activities) operations:

Presented below are the key factors impacting the Energy segment’s operating results:

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2003 vs. 2002

The Energy segment’s net income contribution increased $74 million, as compared to 2002, primarily reflecting:

n An increase in the contribution of the Clearinghouse operations, reflecting a $43 million increase in margins on settled contracts, partially offset by a $20 million decrease in net mark-to-market gains on energy trading contracts;

n Lower net losses associated with a portfolio of financial derivatives held by the Clearinghouse as economic hedges on behalf of Dominion in connection with price risk management for a portion of its future sales of natural gas production; and

n A change in the allocation of electric base rate revenue among the Generation, Energy and Delivery segments effective January 1, 2003.

2002 vs. 2001

Net income for the Energy segment decreased $76 million from 2001, primarily reflecting:

n A decrease in the contribution of the Clearinghouse operations, reflecting a $92 million decrease in net mark-to-market gains on energy trading contracts, partially offset by a $30 million increase in margins on settled contracts; and

n Higher net losses associated with a portfolio of financial derivatives held by the Clearinghouse as economic hedges on behalf of Dominion in connection with price risk management for a portion of its future sales of natural gas production.

Selected Information—Energy Trading Activities

As previously described, the Energy segment manages the Company’s energy trading, hedging and arbitrage activities through the Clearinghouse. The Company believes these operations complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas and oil. During 2003 and prior periods, the Company’s Clearinghouse operations also included contracts for purchases and sales of electricity. In connection with Dominion’s plan to conduct its non-utility wholesale electric marketing and trading activities through another Dominion subsidiary, the Company assigned certain wholesale electric contracts that are not supplied from its own generation resources and involve activities outside of its service territory. The Company will continue to market its generation resources not needed to serve utility customers but will do so as part of its management of utility system resources in the Generation segment rather than through its Clearinghouse operations.

Settlement of a contract may require physical delivery of the underlying commodity or cash settlement. The Clearinghouse enters into contracts with the objective of benefiting from changes in prices. 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 may pay a net cash margin (a realized loss). 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.

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

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

Delivery Segment

The Delivery segment includes the Company’s electric distribution and customer service operations.

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Presented below are the key factors impacting Delivery’s operating results:

2003 vs. 2002

The Delivery segment’s net income contribution increased $27 million, as compared to 2002, reflecting:

n A change in the allocation of electric base rate revenue among the Generation, Energy and Delivery segments effective January 1, 2003;

n An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting new residential customers;

n A decrease in regulated electric sales due to comparably milder weather; and

n An increase in pension and other postretirement benefit costs.

2002 vs. 2001

The Delivery segment’s net income contribution increased $78 million, as compared to 2001, reflecting:

n An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting new residential customers;

n An increase in regulated electric sales due to comparably favorable weather; and

n A decrease in other expenses, reflecting primarily workforce reductions and other savings as a result of restructuring activities in 2001.

Corporate and Other

Corporate and Other includes the Company’s corporate and other functions.

Presented below are Corporate and Other’s operating results for 2003, 2002 and 2001:

2003 vs. 2002

The Company reported in the Corporate and Other segment the following items in 2003 attributable to its operating segments:

n Cumulative effect of changes in accounting principles—$21 million net after-tax loss resulting from the adoption of new accounting standards, as described in Note 3 to the Consolidated Financial Statements, including:

n SFAS No. 143: a $139 million after-tax gain ($140 million after-tax gain—Generation and $1 million after-tax loss—Delivery);

n SFAS No. 133 Interpretation C20: a $101 million after-tax loss (Generation);

n EITF 02-3: a $55 million after-tax loss (Energy); and

n FIN 46R: a $4 million after-tax loss (Generation).

n Other operations and maintenance expenses:

n $197 million of other operations and maintenance expense ($122 million after-tax), representing incremental restoration costs associated with Hurricane Isabel, primarily incurred by the Delivery segment;

n $105 million ($65 million after-tax) cost of terminating two long-term power purchase contracts by the Generation segment;

n A $21 million ($12 million after-tax) charge for the restructuring of certain electric sales contracts by the Generation segment; and

n $8 million ($5 million after-tax) of severance costs for workforce reductions during 2003: $3 million (Generation) and $5 million (Delivery).

2002 vs. 2001

The Company reported no specific items in Corporate and Other attributable to its operating segments in 2002. In 2001, the Corporate and Other segment reported the following items in other operations and maintenance expenses:

n $220 million ($136 million after-tax) related to the cost of terminating certain power purchase contracts (Generation); and

n $48 million ($29 million after-tax) of severance costs for workforce reductions: $10 million (Generation), $5 million (Energy) and $33 million (Delivery).

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Sources and Uses of Cash

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 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 financing.

At December 31, 2003, the Company had cash and cash equivalents of $46 million with $475 million of unused capacity under its credit facilities. For long-term financing needs, amounts available for debt or equity offerings under currently effective shelf registrations totaled $670 million at March 1, 2004.

Cash Provided by Operations

As presented on the Company’s Consolidated Statements of Cash Flows, net cash flows from operating activities were $1.2 billion in 2003, $1.3 billion in 2002 and $1.1 billion in 2001. Management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow current dividends payable to Dominion.

The Company’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, including:

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

n The cost of replacement of 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 its subsidiaries; and

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

Credit Risk

The Company’s exposure to potential concentrations of credit risk results primarily from its energy trading activities. Presented below is a summary of the Company’s gross and net credit exposure as of December 31, 2003 for these activities. The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

Cash Provided by Financing Activities

The Company relies on access to bank and capital markets as a significant source of funding for capital requirements not satisfied by the cash provided by the Company’s operations. As discussed in the 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 authorization by the Virginia State Corporation Commission (Virginia Commission).

During 2003, the Company issued long-term debt totaling approximately $1.1 billion. The proceeds were used primarily to repay other debt and to finance capital expenditures.

Credit Facilities and Short-Term Debt

The Company’s financial policy precludes issuing commercial paper in excess of its supporting lines of credit. Dominion, Consolidated Natural Gas Company (CNG) and the Company maintain two joint credit facilities that allow aggregate borrowings of up to $2 billion. The Company is required to pay minimal annual commitment fees to maintain the joint credit facilities. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2004 and a $750 million three-year revolving credit facility that terminates in May 2005. The 364-day facility includes an option to extend any borrowings for an additional period of one year to May 2005. The Company expects the 364-day revolving credit facility to be renewed prior to its maturity in May 2004. The three-year facility can also be used to support up to $200 million of letters of credit. The remaining joint credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, CNG and the

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Company; and for other general corporate purposes. At December 31, 2003, capacity available under the two credit facilities was $475 million.

Both joint credit agreements contain terms and conditions that could affect the Company’s ability to borrow funds under these facilities, accelerate repayment of any outstanding Company borrowings or possibly result in the termination of the commitment to lend funds to the Company. These terms and conditions include maximum debt to total capital ratios, cross-default provisions and material adverse change clauses.

The ratio of the Company’s debt to total capital, as defined by the agreements, should not exceed 60% at the end of any fiscal quarter. As of December 31, 2003, the Company’s calculated debt to total capital ratio was 52%. Under the agreements’ cross-default provisions, if the Company or any of its material subsidiaries fail to make payment on various debt obligations in excess of $25 million, the lenders could require the Company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to the Company. However, any defaults on indebtedness by Dominion, CNG or any material subsidiaries of those affiliates would not affect the lenders’ commitment to the Company under the joint credit agreements.

Although the joint credit agreements contain material adverse change clauses, the participating lenders, under those specific provisions, cannot refuse to advance funds to the Company for the repurchase of its outstanding commercial paper.

At December 31, 2003, total outstanding commercial paper supported by the joint credit facilities was $1.4 billion, of which the Company’s borrowings were $717 million, with a weighted average interest rate of 1.17%. At December 31, 2002, total outstanding commercial paper supported by previous credit agreements was $1.2 billion, of which the Company’s borrowings were $443 million, with a weighted average interest rate of 1.67%. 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.

At December 31, 2003, total outstanding letters of credit supported by the three-year facility were $85 million, of which $62 million was issued on behalf of an unregulated subsidiary of the Company and $23 million was issued on behalf of other Dominion subsidiaries. At December 31, 2002, total outstanding letters of credit supported by the three-year facility were $106 million issued on the behalf of other Dominion subsidiaries.

Common Stock

In exchange for a reduction in amounts payable to Dominion, the Company recognized $21 million of additional paid-in capital in 2003 and issued $150 million of common stock to Dominion in 2002.

Borrowings from Parent

During 2003, Dominion advanced $54 million, net of repayments, to certain unregulated subsidiaries of the Company pursuant to a short-term demand note. Dominion also advanced $220 million to the Company pursuant to a long-term note. Interest charges incurred by the Company related to these advances were not material. See Note 23 to the Consolidated Financial Statements.

Long-Term Debt

In 2003, the Company issued $1.1 billion of long-term debt, using the proceeds for general corporate purposes, including the repayment of other debt and a portion of the bonds that the Company called for redemption in December 2003. Debt issued during 2003 consisted of:

n $400 million of 2003 Series A, 4.75% senior notes due 2013;

n $230 million of 2003 Series B, 4.50% senior notes due 2010;

n $200 million of 2003 Series C, 5.25% senior notes due 2015; and

n $225 million of callable and puttable enhanced securities, 4.10% due 2038.

In 2003, the Company repaid the following long-term debt:

n $160 million of medium-term notes, various series;

n $150 million of 1998-A, 7.15% senior notes;

n $150 million of 1999-A, 6.70% senior notes;

n $100 million of 1993-A, 7.25% mortgage bonds;

n $200 million of 1993-B, 6.625% mortgage bonds;

n $189 million of 1993-D, 7.50% mortgage bonds; and

n $200 million of 1993-G, 6.75% mortgage bonds.

Amounts Available under Shelf Registrations

At March 1, 2004, the Company had $670 million 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 banking 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 should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for the Company are most affected by the Company’s financial profile,

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mix of regulated and non-regulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable.

Credit ratings for the Company as of February 2, 2004 follow:

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 remains “investment grade,” but it would increase the cost of borrowing. The Company has been working closely with both Standard & Poor’s and Moody’s with the objective of maintaining the Company’s current credit ratings. Recent steps to improve the agencies’ view of the Company’s financial position include the reduction of planned capital spending and related borrowings, as discussed below. 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 modify 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 into 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 submitting financial reports filed with the SEC to lenders;

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

n Compliance with collateral minimums or requirements related to mortgage bonds; and

n Limitations on liens.

The Company monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2003, there were no events of default under the Company’s covenants.

Cash Used in Investing Activities

During 2003, 2002 and 2001, the Company’s investing activities resulted in net cash outflows of $1.1 billion, $857 million and $733 million, respectively. Significant investing activities for 2003 included $986 million for the construction and expansion of generation facilities, including environmental upgrades and construction and improvements of electric transmission and distribution assets and $97 million for nuclear fuel expenditures.

Generation-related projects totaled approximately $511 million and included environmental upgrades, nuclear reactor head replacement expenditures and routine capital improvements. The Company spent approximately $84 million and $350 million on transmission and distribution-related projects, respectively, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled $41 million.

Investing activities also included $342 million for the purchases of securities and $256 million for the sales of securities related to investments held in the Company’s nuclear decommissioning trusts.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

The Company is party to numerous contracts and arrangements obligating the Company to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing expected cash payments that may result from contracts to which the Company is a party as of December 31, 2003. For purchase obligations and other liabilities, amounts are largely estimated based on contract terms, including fixed, minimum or expected quantities to be purchased at fixed or market-based prices. Actual cash payments will be based on actual quantities purchased and prices paid and will likely differ from amounts presented below.

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The Company’s planned capital expenditures during 2004 are expected to total approximately $830 million. For 2005, planned capital expenditures are expected to range from $700 million to $900 million. Included in the Company’s total planned capital expenditures are the following: