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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 1-8489

DOMINION RESOURCES, INC.

(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 (as defined in Exchange Act Rule 12b-2).  Yes  x  No  ¨

The aggregate market value of the common equity held by non-affiliates of the registrant was approximately $20.8 billion based on the closing price of Dominion’s common stock on the New York Stock Exchange on both June 30, 2003 and February 2, 2004.

As of February 2, 2004, Dominion had 325,256,436 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

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Dominion Resources, Inc.

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Part 1

Item 1. Business

The Company

Dominion Resources, Inc. is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Incorporated in Virginia in 1983, Dominion is a registered public utility holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act).

The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion Resources, Inc.’s consolidated subsidiaries or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Operating Segments

Dominion manages its operations along four primary business lines that integrate its electric and gas services, streamline operations and position it for long-term growth in the competitive marketplace. These segments, and their composition, reflect changes made to Dominion’s management structure during the fourth quarter of 2003.

Dominion Delivery manages Dominion’s electric and gas distribution systems and customer service operations, as well as retail energy marketing operations.

Dominion Energy manages Dominion’s electric and gas transmission operations, certain gas production and storage operations, energy trading, marketing, hedging and arbitrage activities.

Dominion Exploration & Production manages Dominion’s gas and oil exploration, development and production operations.

Dominion Generation manages the generation operations of Dominion’s electric utility and merchant fleet and its power purchase agreements. Dominion operates generating facilities in Connecticut, Indiana, Illinois, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

While Dominion manages its daily operations as described above, its assets remain wholly-owned by its legal subsidiaries, which are described below. For additional financial information on business segments and geographic areas, see Note 28 to the Consolidated Financial Statements.

Dominion’s principal direct legal subsidiaries are Virginia Electric and Power Company (Virginia Power), Consolidated Natural Gas Company (CNG) and Dominion Energy, Inc. (DEI). Virginia Power is a regulated public utility that generates, transmits and distributes power for sale in Virginia and northeastern North Carolina. CNG is a producer, transporter, distributor and retail marketer of natural gas, serving customers in Pennsylvania, Ohio, West Virginia and other states. DEI is involved in merchant generation, energy trading and marketing and natural gas and oil exploration and production in the United States and Canada.

As of December 31, 2003, Dominion and its subsidiaries had approximately 16,700 full-time employees. Approximately 6,200 employees are subject to collective bargaining agreements.

Dominion’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and its telephone number is (804) 819-2000.

Where You Can Find More Information About Dominion

Dominion files its annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (SEC). Dominion’s SEC filings are available to the public over the Internet at the SEC’s web site at http://www.sec.gov. You may also read and copy any document Dominion files at the SEC’s public reference room at 450 Fifth Street, NW, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

Dominion’s website address is www.dom.com. Dominion makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports as soon as practicable after filing or furnishing the material with the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning us at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000.

Business Developments

In November 2003, Dominion announced that it had reached an agreement to purchase the Kewaunee power plant from Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WPL), a subsidiary of Alliant Energy Corporation. The Kewaunee power plant is a 545-megawatt single unit station located in northeastern Wisconsin. Under the terms of the agreement, Dominion will acquire the power plant for $220 million in cash, including $35 million for nuclear fuel. Dominion will sell 100% of the facility’s output to WPS and WPL under a power purchase agreement that expires in 2013. The transaction is expected to close in the second half of 2004, subject to regulatory approvals.

Since reactivating its Cove Point liquefied natural gas (LNG) facility in August 2003, Dominion started construction on a fifth storage tank. The new tank is expected to be completed in the

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first quarter of 2005 and increases the current storage capacity from 5.0 billion cubic feet (bcf) to 7.8 bcf. In February 2004, Dominion announced plans to increase the Cove Point storage tank capacity to 14.6 bcf and the plant’s deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. Associated with the Cove Point expansion, Dominion also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed into service in 2008.

Dominion is a participant in two deepwater Gulf of Mexico projects, Devils Tower and Front Runner, that are expected to start production in 2004. The Devils Tower deepwater production platform, which is known as a spar, has been installed with production scheduled to commence in the second quarter of 2004. Front Runner spar installation is expected to begin in the second quarter of 2004, with production anticipated to start in the fourth quarter of 2004.

Seasonality

Sales of electricity in the Dominion Delivery and Dominion Generation segments 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 same is true for gas sales based on heating needs. Dominion Energy’s business is also impacted by seasonal changes in the prices of commodities, primarily electricity and natural gas, that it actively markets and trades. For Dominion Exploration & Production, natural gas and oil prices can vary seasonally as well. See Risk Factors and Cautionary Statements That May Affect Future Results in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for additional information on how weather may affect Dominion’s results of operations.

Regulation

Dominion is subject to regulation by the 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

Electric

Dominion’s electric retail service is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission).

Dominion’s electric utility subsidiary 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 Dominion’s Virginia regulated electric customers since January 1, 2003. Dominion has also separated its generation, distribution and transmission functions through the creation of divisions within Virginia Power. 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 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 Dominion and was approved by the Virginia Senate in late January 2004. In addition to extending capped rates, the bill would:

n Lock in Dominion’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 Dominion’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.

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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 Dominion’s application for three proposed electric retail access pilot programs. The programs were proposed by Dominion 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, Dominion 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 numbers of volunteers. In February 2004, the Virginia Commission granted the 60-day extension.

Rate Matters

Virginia—In December 2003, the Virginia Commission approved Dominion’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, Dominion is permitted to request adjustments to its fuel rates, subject to the Virginia Restructuring Act. Dominion 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 above in Status of Electric Deregulation in Virginia.

North Carolina—In connection with the North Carolina Commission’s approval of the CNG acquisition, Dominion 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 Dominion’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 Dominion’s North Carolina base rates and sought a decrease in base rates. Dominion believes that its base rates are reasonable and intends to respond to the filing; however, Dominion cannot predict the outcome of this matter at this time.

Gas

Dominion’s gas distribution service is regulated by the Public Utilities Commission of Ohio (Ohio Commission), the Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission).

Status of Gas Deregulation

Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.

Ohio—Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion on its own initiative offers retail choice to customers. At December 31, 2003, approximately 670,000 of Dominion’s 1.2 million Ohio customers were participating in this open-access program. Large industrial customers in Ohio also source their own natural gas supplies.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers. At December 31, 2003, approximately 95,000 residential and small commercial customers had opted for Energy Choice in Dominion’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

West Virginia—At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

Rate Matters—Gas Distribution

Dominion’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Pennsylvania, Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, certain of Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are generally subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective three-month or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

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Ohio—In December 2003, the Ohio Commission approved a joint application filed by Dominion and several other Ohio natural gas companies for recovery of bad debt expense via a rider known as a bad debt tracker. The tracker insulates Dominion from the effect of changes in bad debt expense, which is affected by the volatility of natural gas prices, weather, and prices charged by competitive retail natural gas suppliers. The tracker is an adjustable rate that recovers the cost of bad debt in a manner similar to a gas cost recovery rate. Instead of recovering bad debt costs through its base rates, Dominion now will recover all bad debt expenses through the bad debt tracker and will remove bad debt from base rates. Annually, Dominion will assess the need to adjust the tracker based on the preceding year’s actual bad debt expense.

West Virginia—In August 2003, Dominion filed an application with the West Virginia Commission to increase its purchased gas cost rate by approximately $31 million on an annualized basis, effective for the period January 1, 2004 through October 31, 2004. The increase is in anticipation of higher purchased gas costs expected for that period. Dominion’s rate moratorium expired at the end of 2003. The application reflects the traditional purchased gas adjustment treatment for Dominion’s purchased gas costs. The West Virginia Commission issued an order setting an interim rate in the fourth quarter of 2003, with a final rate order to be issued in the second quarter of 2004.

Rate Matters—Gas Transmission

Dominion implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2003. In all material respects, these filings were approved by FERC in the form requested by Dominion and were subject to only minor modifications. Dominion has no significant rate matters pending before FERC 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 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.

Dominion became a registered public utility holding company when it completed the CNG acquisition in January 2000. The 1935 Act prohibits registered companies from owning businesses not directly related to utility or other energy operations. Dominion has substantially completed its strategy to exit the core operating business of Dominion Capital, Inc. (DCI), its financial services subsidiary, and continues to seek opportunities to divest the remaining assets. Currently, Dominion is required to divest of all remaining DCI holdings by January 2006.

Federal Energy Regulatory Commission

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 functions or affiliates undue preferences. All transmission providers must be in compliance by June 2004. Dominion has adopted an implementation plan and will train the appropriate personnel to ensure compliance with the new rules.

Other FERC regulations that affect the electric and gas industries are discussed below.

Electric

Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities. Dominion’s electric utility subsidiary 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, Dominion’s electric utility subsidiary 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. Dominion’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 Dominion join an RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. Dominion and PJM Interconnection, LLC (PJM) entered into an agreement in September 2002 that provides that, subject to regulatory approval and certain provisions, Dominion 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 Dominion to file an application with the Virginia Commission by July 1, 2003 to join an RTO and delayed entry into an RTO until on or after July 1, 2004. Subject to Virginia Commission approval, Dominion would be required to transfer management and control of its electric transmission assets to an RTO by January 1, 2005. For additional discussion on this matter, see RTO in Future Issues and Other Matters in MD&A.

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. FERC also has jurisdiction over the construction of pipeline and related facilities used in transportation and storage of natural gas in interstate commerce.

Competition in the natural gas industry was increased by FERC Order 636, which was issued in 1992. FERC Order 636

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requires transmission pipelines to operate as open-access transporters and provide transportation and storage services on an equal basis for all gas suppliers, whether purchased from Dominion or from another gas supplier.

Dominion’s interstate gas transportation and storage activities are conducted in accordance with certificates, tariffs and service agreements on file with FERC. Dominion is also subject to the Natural Gas Pipeline Safety Act of 1968, which authorizes the establishment and enforcement of federal pipeline safety standards and places jurisdiction of these standards with the Department of Transportation.

In December 2002, Congress enacted the Pipeline Safety Act of 2002, which included new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission and storage pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Company is currently evaluating its natural gas transmission and storage properties under the final regulations issued in December 2003 and is currently assessing the nature and costs of inspection and potential remediation activities at this time.

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 23 to the Consolidated Financial Statements.

From time to time Dominion 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, Dominion 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. Dominion 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 proposed rule presents several control options. Dominion is evaluating facility information from certain of its power stations. Dominion cannot predict the future impact on its operations at this time.

Dominion 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 Dominion’s nuclear power stations, which are part of the Dominion 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 Dominion’s nuclear generating units.

The NRC also requires Dominion to decontaminate nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion is required by the NRC to be financially prepared. For information on Dominion’s decommissioning trusts, see Note 11 to the Consolidated Financial Statements.

Interconnections

Dominion maintains major interconnections with Progress Energy, American Electric Power Company, Inc., PJM-West and PJM. Through this major transmission network, Dominion 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.

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Competition

Deregulation and restructuring in the electric and gas industries continue to create issues that affect or will likely affect the markets where Dominion Generation and Dominion Delivery do business, and govern the way these business units and their competitors operate. The electric power and natural gas industries continue to evolve into a competitive marketplace where energy companies will compete to provide energy and energy services to a broad range of customers.

Dominion Delivery

Retail Electric Distribution—As noted earlier, Dominion 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 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.

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

Retail Gas Distribution—Deregulation is at varying stages in the three states in which Dominion’s gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small commercial customers. In Ohio, legislation has not been enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion offers an Energy Choice program to customers on its own initiative, in cooperation with the Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. See Status of Gas Deregulation for additional information.

Dominion Energy

Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major gas pipelines and large markets in the Northeast and Mid-Atlantic regions and on the East Coast. Dominion’s pipelines are part of an interconnected gas transmission system which continues to provide local distribution companies, marketers, power generators and industrial and commercial customers the accessibility of supplies nationwide.

Dominion competes with domestic and Canadian pipeline companies and gas marketers seeking to provide or arrange transportation, storage and other services for customers. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enables Dominion to tailor its services to meet the needs of individual customers.

Dominion Exploration & Production

Dominion conducts exploration and production operations in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico and Western Canada. Competitors range from major, international oil companies to smaller, independent producers.

Dominion faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Dominion is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development.

In terms of its production activities, Dominion sells most of its deliverable natural gas and oil into short and intermediate-term markets. Dominion faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, Dominion owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions, which strengthens its knowledge of the marketplace and delivery options.

Dominion Generation

Dominion has a diversified generation portfolio located in the Midwest, Northeast and Mid-Atlantic regions of the United States.

In Virginia and North Carolina, Dominion’s electric utility generation, along with power purchases, is used to serve its utility service area obligations. Revenues for serving this load are based on capped rates, with the majority of fuel costs for both its utility generating fleet and power purchases being recovered through the fuel factor. Subject to market conditions, any generation remaining after meeting system needs is sold outside of Dominion’s service area.

With respect to its merchant generation fleet, Dominion owns and operates three large facilities in the Midwest. These generation plants are all under long-term contracts and are therefore largely unaffected by competition.

The majority of Dominion Generation’s remaining merchant assets operates within functioning Independent System Operators (ISO). Competitors include other generating assets bidding to operate within the ISO. These ISOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of short and medium term contracts, and also compete in the spot market with other generators to produce any number of products including energy, capacity and operating reserves. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies, and operating characteristics of the fleet

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within any given ISO. However, management believes that Dominion has the expertise in operations, dispatch and risk management to ensure its merchant fleet remains competitive compared to like assets within the region.

Availability of Fuel for Electric Generation

Dominion 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

Dominion 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

Dominion utilizes coal, oil and natural gas in its fossil fuel operations. Dominion Generation’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.

Dominion uses natural gas as needed throughout the year for Dominion’s jurisdictional and non-jurisdictional generation facilities. Dominion’s gas supply is obtained from various sources including: purchases from major and independent producers in the Southwest and Midwest regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from Dominion’s and third party underground storage fields.

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

Availability of Natural Gas for Retail Distribution

Dominion is engaged in the sale and storage of natural gas through its operating subsidiaries. Sources of gas supplies for sale to customers are the same as those described in Fossil Fuel Supply above.

Dominion continues to purchase volumes from the array of accessible producing basins using its firm capacity resources. These purchased supplies include Appalachian resources in Ohio, Pennsylvania and West Virginia and production from the Gulf Coast, Mid-Continent and offshore areas. Upon FERC’s restructuring of the interstate pipeline business in 1992 and 1993, pipelines no longer sell the delivered natural gas commodity; rather, customers provide their own gas supply for wholesale storage and/or delivery by the pipelines. Much of the supply is purchased by local distributors, energy marketing companies or end-users under seasonal or spot purchase agreements.

Dominion’s underground storage facilities play an important part in balancing gas supply with sales demand and are essential to servicing the Mid-Atlantic and Northeast’s large volume of space-heating business. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.

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Item 2. Properties

Dominion leases its principal executive office in Richmond, Virginia as well as corporate offices in other cities in which its subsidiaries operate. It also owns two corporate offices in Richmond.

Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described below.

Substantially all of Dominion’s electric subsidiary’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds and certain of its nonutility generation facilities are subject to liens.

Dominion Delivery’s right-of-way grants from the apparent owners of real estate have been obtained for most 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.

Dominion Delivery’s investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network includes approximately 27,000 miles of pipe, exclusive of service pipe.

Dominion Energy has more than 100 compressor stations with approximately 597,000 installed compressor horsepower located in Ohio, Virginia, West Virginia, Pennsylvania and New York.

Dominion Energy has approximately 6,000 miles of electric transmission lines and approximately 7,900 miles of gas transmission, gathering and storage pipelines. Portions of Dominion Energy’s 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.

Dominion Energy operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. Dominion owns 20 of these storage fields and has joint-ownership with other companies in six of the fields. The total designed capacity of the underground storage fields is approximately 960 billion cubic feet (bcf). Dominion’s share of the total capacity is about 717 bcf. Dominion Energy also has 5 bcf of above ground storage capacity at its Cove Point liquefied natural gas facility. Dominion’s storage operation also includes approximately 372,000 acres of operated leaseholds and more than 2,000 storage wells.

The map below illustrates Dominion’s gas transmission pipelines, storage facilities and electric transmission lines.

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Dominion Exploration & Production owns 6.4 trillion cubic feet of proved equivalent natural gas reserves and produces approximately 1.2 billion cubic feet of equivalent natural gas per day from its leasehold acreage and facility investments. Dominion, either alone or with partners, holds interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. Dominion also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. Dominion’s share of developed leasehold totals 3.2 million acres, with another 2.3 million acres held for future exploration and development drilling opportunities.

Information detailing Dominion’s gas and oil operations presented below and on the following pages includes the activities of the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included in the Dominion Energy segment:

Company-Owned Proved Gas and Oil Reserves

Estimated net quantities of proved gas and oil reserves at December 31 of each of the last three years were as follows:

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Certain subsidiaries of Dominion file Form EIA-23 with the DOE, which reports gross proved reserves, including the working interests share of other owners, for properties operated by such Dominion subsidiaries. The proved reserves reported in the table above represent Dominion’s share of proved reserves for all properties, based on Dominion’s ownership interest in each property. For properties operated by Dominion, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2003 are based upon studies for each Dominion property prepared by Dominion’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or Ryder Scott Company, L.P.

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Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

Quantities of Gas and Oil Produced

Quantities of gas and oil produced* during each of the last three years ending December 31 follow:

The average sales price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Dominion operations at market prices) realized during the years 2003, 2002 and 2001 was $3.98, $3.41 and $3.83, respectively. The respective average prices without hedging results per mcf of gas produced were $5.02, $3.04 and $3.92. The respective average sales prices realized for oil with hedging results were $24.30, $23.29 and $23.42 per barrel and the respective average prices without hedging results were $29.82, $24.45 and $23.53 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2003, 2002 and 2001 was $0.80, $0.60 and $0.65, respectively.

Acreage

Gross and net developed and undeveloped acreage at December 31, 2003 was:

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Net Wells Drilled in the Calendar Year

The number of net wells completed during each of the last three years ending December 31 follows:

As of December 31, 2003, 93 gross (64 net) wells were in process of drilling, including wells temporarily suspended.

Productive Wells

The number of productive gas and oil wells in which Dominion’s subsidiaries had an interest at December 31, 2003, follow:

The number of productive wells includes 311 gross (123 net) multiple completion gas wells and 22 gross (10 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes.

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

Dominion’s Power Generation

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

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Nuclear Decommissioning

Dominion has a total of six licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia and its Millstone plant in Connecticut. Surry and North Anna serve customers of Dominion’s regulated electric utility operations.

Millstone is a non-regulated merchant plant with two operating units. A third Millstone unit ceased operations before Dominion acquired the plant.

Decommissioning represents the decontamination and removal of radioactive contaminants from a nuclear power plant, once operations have ceased, in accordance with standards established 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. As part of its acquisition of Millstone, Dominion acquired the decommissioning trusts for the three units that were fully funded to the regulatory minimum as of the acquisition date. Currently, Dominion believes that the amounts available in the trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone units, without any additional contributions to the trusts.

The total estimated cost to decommission Dominion’s seven nuclear units is $3.0 billion based upon site-specific studies completed in 2002. Dominion expects to perform new cost studies in 2006. For all units except Millstone Unit 1 and Unit 2, the current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when operating licenses expire. Millstone Unit 1 is not in service and will be monitored until decommissioning activities begin for the remaining Millstone units. The current operating licenses expire in the years detailed in the following table. During 2003, the NRC approved Dominion’s application for a 20-year life extension for the Surry and North Anna units and Dominion has filed a similar request for the Millstone units in 2004. Dominion expects to decommission the Surry and North Anna units during the period 2032 to 2045 and the Millstone units during the period 2034 to 2057.

(1) Unit 1 ceased operations in 1998 before Dominion’s acquisition of Millstone.

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Item 3. Legal Proceedings

From time to time, Dominion and its subsidiaries are 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. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, Dominion and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on Dominion’s financial position, liquidity or results of operations.

See Regulation in Item 1. Business and Note 23 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which Dominion is a party.

Before being acquired by Dominion, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hildalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

In July 1997, Jack Grynberg, an oil and gas entrepreneur, brought suit against CNG and several of its subsidiaries. The suit seeks damages for alleged fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg’s claims were dismissed on the basis that they overlapped with Mr. Wright’s claims, which are noted below. Mr. Grynberg has filed an appeal. The defendants plan to file a motion to dismiss in the spring of 2004.

In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against Dominion Exploration & Production, Inc. (formerly known as CNG Producing Company), a subsidiary of CNG, alleging various fraudulent valuation practices in the payment of royalties on federal leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against CNG Producing Company was resolved by settlement in late 2002, and the case was remanded back to the U.S. District Court for the Eastern District of Texas.

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. Dominion 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, Dominion 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 Virginia Power and Dominion Telecom strung fiber-optic cable across their land, along a Virginia Power electric transmission corridor without paying compensation. The plaintiffs are seeking damages for trespass and “unjust enrichment,” as well as punitive damages from the defendants.

The named plaintiffs purport to “represent a class . . . consisting of all owners of land in North Carolina and Virginia, other than public streets or highways, that underlies Virginia Power’s electric transmission lines and on or in which fiber optic cable has been installed.” 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 Dominion’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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Executive Officers of the Registrant

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Any service listed for Virginia Electric and Power Company, Consolidated Natural Gas Company, Dominion Resources Services, Inc. and Dominion Energy, Inc. reflects service at a subsidiary of Dominion.

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Part II

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

Dominion’s common stock is listed on the New York Stock Exchange. At December 31, 2003, there were approximately 175,000 registered shareholders, including approximately 84,000 certificate holders. The quarterly information concerning stock prices and dividends is incorporated by reference from Note 30 to the Consolidated Financial Statements.

During 2003, Dominion issued 106 shares of common stock to a former employee as a deferred payment under a 1985 performance achievement plan. These shares were not registered under the Securities Act of 1933 (Securities Act). The issuance of this stock did not involve a public offering, and is therefore exempt from registration under the Securities Act.

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 Dominion. MD&A should be read in conjunction with the Consolidated Financial Statements. The term “Dominion” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc.; one of Dominion Resources, Inc.’s consolidated subsidiaries; or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

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 Dominion’s Results of Operations

n Segment Results of Operations

n Dominion’s Sources and Uses of Cash

n Future Issues and Other Matters

n Market Rate Sensitive Instruments and Risk Management

n Risk Factors and Cautionary Statements that May Affect Future Results

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Forward-Looking Statements

This report contains statements concerning Dominion’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.

Dominion 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.

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

Introduction

Dominion is a diversified, fully integrated electric and gas holding company headquartered in Richmond, Virginia. Dominion concentrates its efforts largely in what Dominion refers to as the “MAIN to Maine” region. In the power industry, “MAIN” means the Mid-America Interconnected Network, which comprises all of Illinois and portions of the states of Missouri, Iowa, Wisconsin, Michigan and Minnesota. Under this strategy, Dominion focuses its efforts on the region stretching from MAIN, through its primary Mid-Atlantic service areas in Ohio, Pennsylvania, West Virginia, Virginia and North Carolina, and up through New York and New England. The MAIN-to-Maine region is home to approximately 40% of the nation’s demand for energy.

Operating in all aspects of the energy supply chain positions Dominion to optimize the value of its energy portfolio and enhance its return on invested capital. Dominion has the capability to discover and produce gas, store it, sell it or use it to generate power; it can generate electricity to sell to customers in its retail markets or in wholesale transactions. These capabilities give Dominion the ability to produce and sell energy in whatever form it finds most useful and economic. Dominion also operates North America’s largest natural gas storage system, which gives it the flexibility to provide supply when it is most economically advantageous to do so.

Maintaining and improving Dominion’s financial condition and flexibility is of paramount importance to its management. Important measures of an entity’s financial strength and credit-worthiness are the credit ratings assigned by Moody’s and Standard & Poor’s. Dominion Resources, Inc., and its subsidiaries, Virginia Electric and Power Company (Virginia Power) and Consolidated Natural Gas Company (CNG), are each rated by those agencies and have ratings that are considered investment grade. Dominion has responded to recommendations by those agencies to reduce the percentage of debt in Dominion’s overall capital structure by focusing on minimizing incremental debt issuance, delaying certain capital projects and raising capital by issuing equity securities in proportion to debt so as to reduce overall debt to capital.

Dominion’s businesses are managed along four primary operating segments: Dominion Generation, Dominion Energy, Dominion Delivery and Dominion Exploration & Production. These segments, and their composition, reflect changes made to Dominion’s management structure during the fourth quarter of 2003.

The contributions to net income by Dominion’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.

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet. The fuel mix used by these operations is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. Dominion’s strategy for its electric generation operations focuses on serving customers in the MAIN to Maine region. Its generation facilities are located in Virginia, West Virginia, North Carolina, Connecticut, Illinois, Indiana, Pennsylvania and Ohio. In addition, Dominion expects to complete the acquisition of the Kewaunee power plant located in northeastern Wisconsin in the second half of 2004.

Utility generation operations represent Dominion Generation’s primary source of revenue and cash flow. 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 rates are capped through mid-2007. As rates are capped, changes in Dominion Generation’s operating costs, relative to costs recovered in the capped rates, will impact Dominion’s earnings. Dominion Generation 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.

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Prices received for electricity generated by its merchant fleet are market-based, subjecting Dominion Generation to risks associated with recovering capital expenditures and absorbing variability in fuel costs. Generally, Dominion Generation manages these risks by entering into fixed-price sales and purchase contracts.

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

Dominion Energy includes the following operations:

n A regulated interstate gas transmission pipeline and storage system, serving Dominion’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;

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

n Field services operations, representing aggregation of gas supply and related wholesale activities related to Appalachian and Canadian areas;

n A liquefied natural gas unloading and storage facility in Maryland;

n Certain gas production operations located in the Appalachian basin and

n Dominion Energy Clearinghouse (Clearinghouse), which is responsible for energy trading, marketing, hedging and arbitrage activities.

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

Revenue and cash flow provided by regulated electric and gas transmission operations and the liquefied natural gas facility are based primarily on rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flow provided by these businesses results primarily from changes in rates. 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 flow for Dominion Energy’s nonregulated businesses are subject to variability associated with changes in commodity prices. Dominion Energy’s nonregulated businesses use physical and financial arrangements to hedge this price risk. Certain hedging and trading activities may require cash deposits to satisfy 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 nonregulated businesses relates largely to labor and benefits and the costs of purchased commodities for resale and payments under financially-settled contracts.

Dominion Delivery includes Dominion’s electric and gas distribution systems and customer service operations as well as retail energy marketing activities. Electric distribution operations serve customers in Virginia and northeastern North Carolina. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Retail energy marketing activities include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast and Midwest.

Revenue and cash flow provided by electric and gas distribution operations are based primarily on rates established by state regulatory authorities. Variability in Dominion Delivery’s revenue and cash flow relates largely to changes in volumes, which are primarily weather sensitive. For local gas distribution operations, revenue may vary based upon changes in levels of rate recovery for the costs of gas sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail energy marketing operations may vary in connection with changes in weather and commodity prices as well as the acquisition and potential loss of customers.

Variability in expenses results from changes in the cost of purchased gas, 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 unplanned damage to property, such as the recent storm-related damage caused by Hurricane Isabel. For gas distribution operations, Dominion is permitted to seek recovery of the cost of gas sold to customers.

Dominion Exploration & Production includes Dominion’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, and Western Canada.

Dominion Exploration & Production operates a drilling program focused on low risk development drilling in several proven onshore regions of the United States and Western Canada, while also maintaining some exposure to higher risk exploration opportunities. Significant development drilling programs are currently underway in West Texas, the Appalachians and the Rocky Mountains where Dominion Exploration & Production holds sizable acreage positions and operational experience. While each region provides Dominion Exploration & Production with exploration opportunities, most exploratory drilling takes place in the Gulf Coast region, including the deepwater Gulf of Mexico. Dominion Exploration & Production maintains an active and ongoing drilling program, participating in 922 net wells during 2003, and replacing approximately 160 percent of its 2003 production.

Revenue and cash flow provided by exploration and production operations are based primarily on the production and sale of company-owned natural gas and oil reserves. Variability in Dominion Exploration & Production’s revenue and cash flow relates primarily to changes in commodity prices, which are market based, and volumes, which are impacted by numerous

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factors including drilling success, timing of development projects, as well as external factors such as severe weather. Dominion manages commodity price volatility by hedging a substantial portion of its near term expected production.

Variability in Dominion Exploration & Production’s expenses relates primarily to changes in operating costs and production taxes, which tend to increase and decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related E&P service industry costs, while severance and property taxes move with changes in revenue. A changing price environment impacts both operating costs and the cost of acquiring, finding and developing natural gas and oil reserves.

Corporate and Other includes:

n The operations of Dominion Capital, Inc., a financial services subsidiary (DCI), which are being divested in accordance with an SEC order;

n Dominion Fiber Ventures, LLC (DFV) and its subsidiary, Dominion Telecom, Inc. (DTI), a telecommunications business that is being discontinued;

n Dominion’s corporate and other operations, including its services company and

n Specific items attributable to Dominion’s operating segments that are reported in Corporate and Other.

Accounting Matters

Critical Accounting Policies and Estimates

Dominion 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

Dominion uses derivative instruments to manage its commodity and financial market risks. In addition, Dominion 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, Dominion 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 Dominion 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, Dominion 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 goodwill impairment testing

Dominion is required to test its goodwill for potential impairment on an annual basis, or more frequently if impairment indicators are present. In performing the test, Dominion estimates the fair value of its reporting units by using discounted cash flow analyses and other valuation techniques based on multiples of earnings for peer group companies, as well as analyses of recent business combinations involving peer group companies. These calculations are dependent on many subjective factors, including management’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. The cash flow estimates used by Dominion are based on relevant information available at the time the estimates are made. However, estimates of future cash flows are highly uncertain by nature and may vary significantly from actual results.

The underlying assumptions and estimates involved in preparing these fair value calculations could change significantly from period to period. Modifications to any of these assumptions, particularly changes in discount rates and changes in growth rates inherent in management’s estimate of future cash flows, could result in a future impairment of goodwill.

Substantially all of Dominion’s goodwill is allocated to its Generation, Energy, Delivery and Exploration & Production reporting units. If the estimates of future cash flows used in the 2003 annual test had been 10% lower, the resulting discounted cash flows would have been greater than the carrying values of each of those reporting units, still indicating no impairment was present.

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, Dominion 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

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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 Dominion 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.

In 2003, reflecting a significant revision in long-term expectations for potential growth in telecommunications service revenue, Dominion approved a strategy to sell its interest in the telecommunications business. In connection with this change in strategy, Dominion tested the network assets to be sold for impairment, using the revised long-term expectations for potential growth. Dominion’s assets were determined to be substantially impaired and were written down to fair value.

Asset retirement obligations

Dominion 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, Dominion 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 Dominion’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 Dominion’s AROs relates to the future decommissioning of its nuclear facilities. At December 31, 2003, nuclear decommissioning AROs totaled $1.3 billion, which represented approximately 80% of Dominion’s total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with Dominion’s nuclear decommissioning obligations.

Dominion 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 utility nuclear plants. Dominion uses internal cost studies for its merchant nuclear facility based on similar methods. 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 cost estimates are dependent on subjective factors, including the selection of cost escalation rates, which Dominion considers to be a critical assumption.

Dominion 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 Dominion was 3.18%. The use of alternative rates would have been material to the liabilities recognized. For example, had Dominion increased the cost escalation rate by 0.5% to 3.68%, the amount recognized as of December 31, 2003 for its AROs related to nuclear decommissioning would have been $256 million higher.

Employee benefit plans

Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected rate of return on plan assets, discount rates applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs, also have a significant impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants rather than immediately.

The selection of discount rates and expected long-term rates of return on plan assets are critical assumptions. Dominion determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

n Historical return analysis to determine expected future risk premiums;

n Forward looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;

n Expected inflation and risk-free interest rate assumptions and

n The types of investments expected to be held by the plans.

Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under Dominion’s plans.

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The following table illustrates the effect of changing the critical actuarial assumptions discussed above:

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, Dominion’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 or 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 14 to the Consolidated Financial Statements.

Accounting for gas and oil operations

Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using a unit-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proved reserve quantities and estimates of the amount and timing of future expenditures to develop the proved reserves. Proved reserves, and the cash flows related to these reserves, are estimated based on a combination of historical data and expected future activity. Actual reserve quantities and development expenditures may differ from the forecasted amounts.

In addition, Dominion has significant investments in unproved properties, which are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base, determined on a property-by-property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base.

Capitalized costs in the depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves assuming period-end hedge-adjusted prices. Dominion performs the ceiling test quarterly, on a country-by-country basis, and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. Any impairment of excess gas and oil property costs over the ceiling is charged to operations. Given the volatility of natural gas and oil prices, it is possible that Dominion’s estimate of discounted future net cash flows from proved natural gas and oil reserves could change in the near term. If natural gas or oil prices have declined as of the date of the ceiling test, or if Dominion revises its estimates of the quantities or timing of future production from its proved reserves, recognition of natural gas and oil property impairments could occur. See Notes 2 and 29 to the Consolidated Financial Statements.

Accounting for retained interests from securitizations

Securitizations involve selling loans to qualifying unconsolidated trusts in exchange for cash and retained interests. Retained interests may include unsecured debt of the trust or retained interests in the transferred loans. Dominion holds retained interests from mortgage and commercial loans securitized in prior years and classifies them as available-for-sale investments, carried on the Consolidated Balance Sheets at fair value. Quarterly, Dominion evaluates the key assumptions relating to valuing the retained interests. Those key assumptions include: loan prepayment speeds, credit losses, forward yield curves and discount rates. Using a published forward yield curve, cash flows, net of adjustments for expected credit losses and loan prepayments, are discounted to determine the estimated fair value of the retained interests. Loan prepayment speeds and credit loss assumptions are based on actual historical results and future estimates. The discount rate is risk adjusted and is periodically compared to industry averages and recent or similar transactions for reasonableness. Changes in interest rates will result in a change in the forward yield curve and can result in a change in the assumed amount of loan prepayments. Changes in general economic conditions may impact actual credit losses, thus impacting the credit loss assumption used in Dominion’s quarterly evaluation. Income from the residual interests is reported as other revenue. See Note 27 to the Consolidated Financial Statements for a discussion of impairment charges recorded in 2003, 2002 and 2001.

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Newly Adopted Accounting Standards in 2003

During 2003, Dominion 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 Dominion’s 2003 Consolidated Financial Statements to those of prior years as follows:

n Recognition of asset retirement obligations of $1.5 billion compared to a liability of $1.6 billion that had been previously recorded for nuclear decommissioning;

n Recognition of $350 million of capitalized asset retirement costs in property, plant and equipment and a $90 million increase in accumulated depreciation, depletion and amortization, representing the depreciation of such costs through December 31, 2002;

n Beginning in 2003, accretion of the AROs, including nuclear decommissioning, is reported in other operations and maintenance expense. Previously, expenses associated with the provision for nuclear decommissioning were reported in depreciation 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 Dominion’s utility 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 EITF 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 EITF 03-11 affected the comparability of Dominion’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 revenue, while unrealized gains and losses and settlements on purchase contracts are reported in expenses 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. Dominion 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, Dominion was required to consolidate certain variable interest lessor entities through which Dominion had financed and leased several new power generation projects, as well as its corporate headquarters and aircraft. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $644 million in net property, plant and equipment and deferred charges and $688 million of related debt.

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

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Dominion’s Results of Operations

Overview

2003 vs. 2002

Dominion earned $1.00 per diluted share on net income of $318 million, a decrease of $3.82 per diluted share and $1,044 million. The per share decrease includes approximately $0.13 of share dilution, reflecting an increase in the average number of common shares outstanding during 2003.

The combined net income contribution of Dominion’s primary operating segments increased $95 million in 2003. This increase largely reflects the benefits of higher natural gas prices during 2003 on sales of Dominion’s gas and oil production as well as margins associated with gas trading activities. See Note 28 to the Consolidated Financial Statements for information about Dominion’s operating segments. This increased contribution by the operating segments was more than offset by significant specific charges recognized in 2003 and reported in the Corporate and Other segment, including:

n $750 million of after-tax losses associated with Dominion’s telecommunications business, which is being discontinued;

n $122 million of after-tax incremental expenses associated with Hurricane Isabel;

n $96 million of after-tax charges for DCI asset impairments;

n $69 million of after-tax charges for asset impairments related to certain investments held for sale;

n $104 million of after-tax charges associated with the termination of long-term power purchase agreements and the restructuring of power sales agreements and

n $16 million of after-tax severance costs for workforce reductions.

2002 vs. 2001

Dominion earned $4.82 per diluted share on net income of $1.4 billion, an increase of $818 million and $2.67 per diluted share compared to 2001. Per share amounts also reflect approximately $0.57 of share dilution, due to an increase in the average number of common shares outstanding during 2002.

The combined net income contribution of Dominion’s primary operating segments increased $222 million in 2002. These results largely reflect the impact of favorable weather and customer growth on utility operations and the inclusion of a full year of operations after the Louis Dreyfus acquisition. In addition to the increased contribution by the operating segments, the increase in net income included the effect of discontinuing the amortization of goodwill in 2002 ($95 million) and the impact of significant specific charges recognized in 2001 that did not recur in 2002. These items were reported in the Corporate and Other segment and included:

n $208 million of after-tax losses from the impairment of DCI financial assets and the sale of a DCI subsidiary;

n A $136 million after-tax charge related to the termination of certain long-term power purchase contracts;

n A $97 million after-tax charge for credit exposure associated with the bankruptcy of Enron and

n A $68 million after-tax charge for restructuring activities.

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion’s results of operations.

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An analysis of Dominion’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 combined effects of:

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

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

n A $103 million decrease associated with milder weather.

Regulated gas sales revenue increased 44% to $1.3 billion, primarily due to:

n Recovery of higher gas prices in rates ($289 million) and

n Comparably colder weather in the first and fourth quarters of 2003 ($79 million), reflecting more heating degree-days in 2003.

The increase in regulated gas sales revenue was largely offset by a comparable increase in purchased gas expense.

Nonregulated electric sales revenue increased 11% to $1.1 billion, primarily reflecting the combined effects of:

n A $77 million increase in merchant generation revenue, reflecting higher volumes ($59 million) and higher prices ($18 million). The increase in volumes can be attributed to fewer outage days at the Millstone Power Station in 2003 and a full year’s sales from generating units placed into service during 2002;

n A $76 million increase in retail energy sales, primarily as a result of customer growth, including the acquisition of              new customers previously served by other energy companies during 2003 and

n A $43 million decrease in Clearinghouse electric revenue, net of applicable purchases, due to unfavorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3, partially offset by increased margins.

Nonregulated gas sales revenue increased 121% to $1.7 billion, primarily reflecting:

n An $82 million increase in revenue from retail energy marketing operations, reflecting higher prices ($78 million) and higher volumes ($4 million);

n A $659 million increase in revenue from field services operations, reflecting higher prices ($467 million) and higher volumes ($192 million) and

n A $208 million increase in Clearinghouse gas revenue, net of applicable purchases, due to higher margins, favorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3. The increase included a $54 million increase associated with the economic hedges, described further in the discussion of Dominion Energy’s results.

Gas and oil production revenue increased 13% to $1.5 billion primarily due to higher average realized prices for gas and oil. It also includes $43 million of revenue recognized related to deliveries under a volumetric production payment transaction.

Other revenue increased 31% to $853 million, primarily reflecting the combined effects of:

n A $49 million increase in coal sales revenue;

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;

n $94 million of sales of emissions credits that began in 2003;

n A $26 million increase in sales of extracted products and

n An $81 million decrease in revenue associated with Dominion financial services operations, reflecting the winding-down under Dominion’s divestiture strategy.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 15% to $1.7 billion, primarily reflecting:

n A $154 million increase associated with nonregulated energy marketing 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 utility operations, including $42 million associated with rate recovery in 2003 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).

Purchased gas expense increased 88% to $2.2 billion, primarily reflecting:

n A $647 million increase associated with field services operations, reflecting higher prices ($459 million) and higher volumes ($188 million) and

n A $363 million increase associated with regulated gas operations discussed above in Regulated gas sales revenue.

Liquids, pipeline capacity and other purchases expense increased 194% to $468 million, reflecting primarily the reclassification of certain purchase contracts for transportation, storage, coal and emissions allowances after the adoption of EITF 02-3.

Other operations and maintenance expense rose 32% to $2.9 billion, primarily reflecting the following specific increases:

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

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

n Asset and goodwill impairments associated with DCI’s financial services operations ($108 million);

n Goodwill impairment associated with the purchase of the remaining interest in the telecommunications joint venture held by another party ($60 million);

n A charge for the restructuring of certain electric sales contracts recorded as derivative assets ($64 million);

n Accretion expense for asset retirement obligations ($86 million);

n Decrease in net pension credits and an increase in other postretirement benefit costs ($87 million) and

n Expenses associated with nuclear outages for refueling in 2003 ($13 million).

These increases were partially offset by a decrease attributable to lower outage costs at Millstone ($28 million).

Other taxes increased 11% to $476 million, primarily due to higher severance taxes and gross receipts taxes, as well as the effect of a favorable resolution of sales and use tax issues in 2002. Such benefits were not recognized in 2003.

Other income decreased 138% to a net loss of $40 million, which included the following items:

n $57 million of costs associated with the acquisition of DFV senior notes;

n $27 million for the reallocation of equity losses between Dominion and the minority interest owner of DFV;

n $62 million for the impairment of certain equity-method investments and

n A $32 million increase in net realized losses associated with nuclear decommissioning trust fund investments.

Partially offsetting these reductions to other income was an increase of $28 million, reflecting equity losses on Dominion’s investment in DFV in 2002; DFV was consolidated beginning in the first quarter of 2003. In 2003, the operating losses of DFV’s subsidiary, DTI, were classified in discontinued operations.

Income taxes—Dominion’s effective tax rate increased 5.3% to 38.6% for 2003. The increase primarily resulted from the expiration of nonconventional fuel credits beginning in 2003, an increase in the valuation allowance related to the impairment of goodwill associated with the telecommunications investment and federal loss carryforwards at CNG International and DCI that are not expected to be utilized, partially offset by a reduction in Canadian tax rates applied to deferred tax balances.

Loss from discontinued operations reflects the results of operations of Dominion’s telecommunications business, which is classified as held for sale. The loss includes the following:

n Impairment of network assets of $566 million. Dominion has not recognized any deferred tax benefits related to the impairment charges, since realization of tax benefits will be dependent upon Dominion’s future tax profile and taxable earnings. In addition, Dominion also increased the valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting in a $48 million increase in deferred income tax expense; and

n DTI operating losses of $28 million.

Cumulative effect of changes in accounting principles—During 2003 Dominion was required to adopt several new accounting standards, resulting in a net after-tax gain of $11 million which included the following:

n A $180 million after-tax gain (SFAS No. 143), partially offset by;

n A $67 million after-tax loss (EITF 02-3);

n A $75 million after-tax loss (Statement 133 Implementation Issue No. C20) and

n A $27 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 Favorable weather conditions ($195 million), reflecting increased cooling and heating degree-days in 2002;

n Customer growth ($60 million) and