SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                 

Commission File Number 1-8489

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Virginia	54-1229715
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
120 Tredegar Street
Richmond, Virginia	23219
(Address of principal executive offices)	(Zip Code)

(804) 819-2000

(Registrant’s telephone number)

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

Title of Each Class	Name of Each Exchange on Which Registered
Common stock, no par value	New York Stock Exchange
8.75% Equity Income Securities, $50 par	New York Stock Exchange
9.5% Equity Income Securities, $50 par	New York Stock Exchange
8.4% Trust Preferred Securities, $25 par	New York Stock Exchange

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.

(a) Portions of the 2004 Proxy Statement are incorporated by reference in Part III.

Dominion Resources, Inc.

Item Number		Page Number
Part I
1.	Business	3
2.	Properties	10
3.	Legal Proceedings	16
4.	Submission of Matters to a Vote of Security Holders	16
Executive Officers of the Registrant		17
Part II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	19
6.	Selected Financial Data	19
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
7A.	Quantitative and Qualitative Disclosures About Market Risk	45
8.	Financial Statements and Supplementary Data	46
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
9A.	Controls and Procedures	92
Part III
10.	Directors and Executive Officers of the Registrant	93
11.	Executive Compensation	93
12.	Security Ownership of Certain Beneficial Owners and Management	93
13.	Certain Relationships and Related Transactions	93
14.	Principal Accountant Fees and Services	93
Part IV
15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	94

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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.

10

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:

	2003		2002		2001
	Proved Developed	Total Proved	Proved Developed	Total Proved	Proved Developed	Total Proved
Proved gas reserves (bcf)
United States	3,553	4,801	3,549	4,458	3,026	3,517
Canada	453	568	486	640	440	573
Total proved gas reserves	4,006	5,369	4,035	5,098	3,466	4,090
Proved oil reserves (000 bbls)
United States	42,347	135,914	47,759	138,798	46,473	115,988
Canada	17,407	34,020	18,064	30,432	17,304	24,579
Total proved oil reserves	59,754	169,934	65,823	169,230	63,777	140,567
Total proved gas and oil reserves (bcfe)	4,364	6,388	4,430	6,113	3,850	4,933

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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.

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:

	2003	2002	2001
Gas production (bcf)
United States	347	346	238
Canada	49	53	57
Total gas production	396	399	295
Oil production (000 bbls)
United States	7,642	8,653	6,134
Canada	1,081	1,072	1,529
Total oil production	8,723	9,725	7,663
Total gas and oil production (bcfe)	449	458	341

* Gas and oil production quantities include the production from the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included in the Dominion Energy segment.

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:

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
United States	3,828,253	2,398,568	3,219,089	1,644,919
Canada	1,429,698	788,165	856,973	627,256
Total	5,257,951	3,186,733	4,076,062	2,272,175

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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:

	2003	2002	2001
Exploratory:
United States
Productive	8	12	17
Dry	7	12	15
Total United States	15	24	32
Canada
Productive	10	1	2
Dry	1	1	1
Total Canada	11	2	3
Total Exploratory	26	26	35
Development:
United States
Productive	819	774	372
Dry	36	38	3
Total United States	855	812	375
Canada
Productive	31	61	93
Dry	10	11	15
Total Canada	41	72	108
Total Development	896	884	483
Total wells drilled (net):	922	910	518

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:

	Gross	Net
Gas wells
United States	23,633	15,602
Canada	928	605
Total gas wells	24,561	16,207
Oil wells
United States	1,017	525
Canada	531	222
Total oil wells	1,548	747

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

Plant	Location	Primary Fuel Type	Net Summer Capability (Mw)
Utility Generation
North Anna	Mineral, VA	Nuclear	1,628	(a)
Surry	Surry, VA	Nuclear	1,625
Altavista	Altavista, VA	Coal	63
Bremo	Bremo Bluff, VA	Coal	227
Chesapeake	Chesapeake, VA	Coal	595
Chesterfield	Chester, VA	Coal	1,234
Clover	Clover, VA	Coal	441	(b)
Mt. Storm	Mt. Storm, WV	Coal	1,569
North Branch	Bayard, WV	Coal	74
Southampton	Southampton, VA	Coal	63
Yorktown	Yorktown, VA	Coal	326
Chesapeake (CT)	Chesapeake, VA	Oil	144
Darbytown (CT)	Richmond, VA	Oil	144
Gravel Neck (CT)	Surry, VA	Oil	183
Kitty Hawk (CT)	Kitty Hawk, NC	Oil	44
Low Moor (CT)	Covington, VA	Oil	60
Northern Neck (CT)	Lively, VA	Oil	64
Possum Point	Dumfries, VA	Oil	786
Possum Point (CT)	Dumfries, VA	Oil	78
Yorktown	Yorktown, VA	Oil	818
Bellmeade (CC)	Richmond, VA	Gas	230
Chesterfield (CC)	Chester, VA	Gas	397
Darbytown (CT)	Richmond, VA	Gas	144
Gordonsville (CC)	Gordonsville, VA	Gas	217
Gravel Neck (CT)	Surry, VA	Gas	146
Ladysmith (CT)	Ladysmith, VA	Gas	290
Possum Point (CC)	Dumfries, VA	Gas	322
Possum Point (CT)	Dumfries, VA	Gas	545
Remington (CT)	Remington, VA	Gas	580
Bath County	Warm Springs, VA	Hydro	1,464	(c)
Gaston	Roanoke Rapids, NC	Hydro	225
Roanoke Rapids	Roanoke Rapids, NC	Hydro	99
Other	Various	Various	15
			14,840
Non-utility Generation
Millstone	Waterford, CT	Nuclear	1,954	(d)
Kincaid	Kincaid, IL	Coal	1,158
State Line	Hammond, IN	Coal	515
Morgantown	Morgantown, WV	Coal	33	(e)
Elwood (CT)	Elwood, IL	Gas	682	(f)
Armstrong (CT)	Shelocta, PA	Gas	600
Troy (CT)	Luckey, OH	Gas	600
Pleasants (CT)	St. Mary’s, WV	Gas	300
Others	Various	Various	31
			5,873
Purchased Capacity			3,550
Net Purchases			145
Total Capacity			24,408

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

(a) Excludes 11.6 percent undivided interest owned by Old Dominion Electric Cooperative (ODEC).

(b) Excludes 50 percent undivided interest owned by ODEC.

(c) Excludes 40 percent undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

(d) Excludes 6.53 percent undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Company.

(e) Excludes 50 percent interest owned by Cogen Technologies Morgantown, Ltd. and Hickory Power Corporation.

(f)  Excludes 50 percent interest owned by Peoples Energy.

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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.

	Surry				North Anna				Millstone
	Unit 1		Unit 2		Unit 1		Unit 2		Unit 1			Unit 2		Unit 3		Total
(millions)
NRC license expiration year		2032		2033		2038		2040		(1	)		2015		2025
Current cost estimate (2002 dollars)	$	375	$	368	$	391	$	363	$	531		$	486	$	518	$	3,032
Funds in trusts at December 31, 2003		283		277		231		219		282			292		288		1,872
2003 contributions to trusts		11		11		7		7		—			—		—		36

(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

Name and Age	Business Experience Past Five Years
Thos. E. Capps (68)	Chairman of the Board of Directors and Chief Executive Officer of Dominion from August 2000 to date; Chairman of the Board of Directors of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Directors and President of Consolidated Natural Gas Company from January 2004 to date; President of Dominion from August 2000 to December 2003; President of Consolidated Natural Gas Company from January 2003 to December 2003; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from January 2000 to August 2000; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from September 1995 to January 2000.
Thomas F. Farrell, II (49)	President and Chief Operating Officer of Dominion from January 2004 to date; President and Chief Operating Officer of Consolidated Natural Gas Company from January 2004 to date; Executive Vice President of Dominion from March 1999 to December 2003; President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to December 2003; Executive Vice President of Consolidated Natural Gas Company from January 2000 to December 2003; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2002; Executive Vice President, General Counsel and Corporate Secretary of Virginia Electric and Power Company from July 1998 to April 1999.
Thomas N. Chewning (58)	Executive Vice President and Chief Financial Officer of Dominion from May 1999 to date; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 2000 to date; Executive Vice President of Dominion prior to May 1999.
Jay L. Johnson (57)	Executive Vice President of Dominion and President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to date; Senior Vice President, Business Excellence, Dominion Energy, Inc. from September 2000 to December 2002; Chief of Naval Operations, U.S. Navy, and member of the Joint Chiefs of Staff from 1996 until July 2000.
Duane C. Radtke (55)	Executive Vice President of Dominion and Consolidated Natural Gas Company from April 2001 to date; President of Devon Energy International from August 2000 to April 2001; Executive Vice President—Production of Santa Fe Snyder Corp. from May 1999 to August 2000; Senior Vice President—Production of Santa Fe Energy Resources from April 1998 to May 1999.
Mary C. Doswell (45)	Senior Vice President and Chief Administrative Officer of Dominion from January 2003 to date; President and Chief Executive Officer of Dominion Resources Services, Inc. from January 2004 to date; President of Dominion Resources Services, Inc. from January 2003 to December 2003; Vice President—Billing and Credit of Virginia Electric and Power Company from October 2001 to December 2002; Vice President—Metering of Virginia Electric and Power Company from January 2000 to October 2001; General Manager—Metering of Virginia Electric and Power Company from February 1999 to January 2000; Project Manager of Virginia Electric and Power Company from December 1997 to February 1999.
Paul D. Koonce (44)	Chief Executive Officer—Energy of Virginia Electric and Power Company from January 2004 to date; Chief Executive Officer—Transmission of Virginia Electric and Power Company from January 2003 to December 2003; Senior Vice President—Portfolio Management of Virginia Electric and Power Company from January 2000 to December 2002; Senior Vice President—Commercial Operations of Consolidated Natural Gas Company from January 1999 to January 2000; Vice President of Regulated Commercial Operations of Consolidated Natural Gas Company from January 1999 to June 1999.

17

Name and Age	Business Experience Past Five Years
Mark F. McGettrick (46)	President and Chief Executive Officer—Generation of Virginia Electric and Power Company from January 2003 to date; Senior Vice President and Chief Administrative Officer of Dominion from January 2002 to December 2002; President of Dominion Resources Services, Inc. from October 2002 to January 2003; Senior Vice President—Customer Service and Metering of Virginia Electric and Power Company from January 2000 to December 2001; Vice President—Customer Service and Marketing of Virginia Electric and Power Company from January 1997 to January 2000.
Eva S. Hardy (59)	Senior Vice President—External Affairs & Corporate Communications of Dominion from May 1999 to date; Senior Vice President-External Affairs & Corporate Communications of Virginia Electric and Power Company from September 1997 to April 2000.
G. Scott Hetzer (47)	Senior Vice President and Treasurer of Dominion from May 1999 to date; Senior Vice President and Treasurer of Virginia Electric and Power Company and Consolidated Natural Gas Company from January 2000 to date; Vice President and Treasurer of Dominion from October 1997 to May 1999.
James L. Sanderlin (62)	Senior Vice President—Law of Dominion from September 1999 to date; Senior Vice President—Law of Consolidated Natural Gas Company from January 2000 to date. Partner in the law firm of McGuire, Woods, Battle & Boothe LLP prior to September 1999.
Steven A. Rogers (42)	Vice President, Controller and Principal Accounting Officer of Dominion and Consolidated Natural Gas Company and Vice President and Principal Accounting Officer of Virginia Electric and Power Company from June 2000 to date; Controller of Virginia Electric and Power Company from January 2000 to May 2000; Controller of Dominion Energy, Inc. from September 1998 to June 2000.

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

	2003			2002		2001		2000		1999
(millions, except per share amounts)
Operating revenue	$	12,078		$	10,218	$	10,558	$	9,246	$	5,520
Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles		949			1,362		544		415		552
Loss on discontinued operations, net of taxes		(642	)		—		—		—		—
Extraordinary item, net of taxes		—			—		—		—		(255	)
Cumulative effect of changes in accounting principles, net of taxes		11			—		—		21		—
Net income		318			1,362		544		436		297
Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles per common share—basic		2.99			4.85		2.17		1.85		1.55
Net income per common share—basic		1.00			4.85		2.17		1.85		1.55
Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles per common share—diluted		2.98			4.82		2.15		1.85		1.48
Net income per common share—diluted		1.00			4.82		2.15		1.85		1.48
Dividends paid per share		2.58			2.58		2.58		2.58		2.58
Total assets		44,186			39,998		36,431		30,683		19,132
Long-term debt		15,776			12,060		12,119		10,101		6,936
Preferred securities of subsidiary trusts		—			1,397		1,132		385		385

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:

			Increase in 2004 Net Periodic Cost
Actuarial Assumption	Change in Assumption		Pension Benefits		Other Postretirement Benefits
			(millions)
Discount rate	(0.25	%)	$	12	$	6
Rate of return on plan assets	(0.25	%)		10		1
Healthcare cost trend rate	1	%		N/A		22

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

Year Ended December 31,	2003						2002						2001
	Net Income			Diluted EPS			Net Income			Diluted EPS			Net Income			Diluted EPS
(millions, except per share amounts)
Dominion Generation	$	508		$	1.59		$	561		$	1.98		$	511		$	2.02
Dominion Energy		350			1.10			268			0.95			268			1.06
Dominion Delivery		453			1.42			422			1.49			311			1.23
Dominion Exploration & Production		415			1.30			380			1.34			320			1.27
Primary operating segments		1,726			5.41			1,631			5.76			1,410			5.58
Corporate and Other		(1,408	)		(4.41	)		(269	)		(0.94	)		(866	)		(3.43	)
Consolidated	$	318		$	1.00		$	1,362		$	4.82		$	544		$	2.15

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.

Year Ended December 31,	2003			2002			2001
(millions)
Operating Revenue
Regulated electric sales	$	4,876		$	4,856		$	4,619
Regulated gas sales		1,258			876			1,409
Nonregulated electric sales		1,130			1,017			1,022
Nonregulated gas sales		1,718			778			1,073
Gas transportation and storage		740			705			702
Gas and oil production		1,503			1,334			1,057
Other		853			652			676
Operating Expenses
Electric fuel and energy purchases, net		1,667			1,447			1,369
Purchased electric capacity		607			691			680
Purchased gas, net		2,175			1,159			1,822
Liquids, pipeline capacity and other purchases		468			159			219
Restructuring and other acquisition-related costs		—			(8	)		105
Other operations and maintenance		2,908			2,198			2,938
Depreciation, depletion and amortization		1,216			1,258			1,245
Other taxes		476			429			395
Other income (loss)		(40	)		103			126
Interest and related charges		975			945			997
Income tax expense		597		$	681		$	370
Loss from discontinued operations		(642	)		—			—
Cumulative effect of changes in accounting principles	$	11			—			—

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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

n Fuel rate recoveries ($65 million), which were generally offset in fuel expense and do not materially affect net income.

These increases were partially offset by other factors not separately measurable, such as the impact of economic conditions on customer usage, as well as variations in seasonal rate premiums and discounts.

Regulated gas sales revenue decreased 38% to $876 million, reflecting $550 million for lower gas cost recoveries attributable to lower prices and customer migration, partially offset by the impact of slightly colder weather and other factors. The decline was offset by a corresponding $491 million decrease in purchased gas expense, reflecting the matching of purchased gas costs and gas cost recoveries in rates, and increased gas transportation service revenue.

Nonregulated electric sales revenue increased 1% to $1.0 billion, primarily reflecting the combined effects of:

n A $21 million decrease in sales revenue from Dominion’s merchant generation fleet, reflecting a $201 million decline due to lower prices partially offset by sales from assets acquired and constructed in 2002 and the inclusion of Millstone operations for all of 2002;

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

n A $71 million increase in revenue from retail energy sales, reflecting primarily customer growth over the prior year and

n A $33 million increase in Clearinghouse electric revenue, net of applicable trading purchases, reflecting the effect of favorable price changes on unsettled contracts and higher margins.

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Nonregulated gas sales revenue decreased 28% to $778 million, primarily reflecting:

n A $261 million decrease in sales by Dominion’s field services and retail energy marketing operations, reflecting to a large extent declining prices and

n A $51 million decrease in Clearinghouse gas revenue, net of applicable trading purchases, due to unfavorable price changes on unsettled contracts and lower overall margins. Those losses were partially offset by contributions from higher trading volumes in gas and oil markets. The decrease included a $70 million revenue decrease associated with the economic hedges.

Gas and oil production revenue increased 26% to $1.3 billion, reflecting higher overall production as a result of the inclusion of a full year of operations after the Louis Dreyfus acquisition and Dominion’s ongoing drilling programs. Average realized gas and oil prices, including the effects of hedging, decreased for the comparative years.

Operating Expenses and Other Items

Purchased gas expense decreased 36% to $1.2 billion, primarily reflecting:

n A $196 million decrease associated with field services and gas transmission operations, primarily reflecting lower prices and

n A $489 million decrease associated with regulated gas operations discussed above in Regulated gas sales revenue.

Liquids, pipeline capacity and other purchases expense decreased 28% to $159 million, primarily reflecting comparably lower levels of rate recoveries of certain costs of transmission operations in the current year period. The difference between actual expenses and amounts recovered in the period are deferred pending future rate adjustments.

Other operations and maintenance expense decreased 25% to $2.2 billion, primarily reflecting the following expenses incurred in 2001 that did not recur in 2002:

n A $281 million charge for impairments of certain financial assets held by DCI;

n $151 million charge for credit exposure associated with the bankruptcy of Enron;

n A $220 million charge related to the termination of certain long-term power purchase contracts and

n A $40 million loss on the sale of assets by DCI.

Depreciation expense increased 1% to $1.3 billion, primarily reflecting the combined effects of:

n A $95 million decrease resulting from discontinued amortization of goodwill effective January 1, 2002;

n A $58 million decrease related to the extension of estimated useful lives of most fossil fuel stations and electric transmission and distribution properties in 2002 and nuclear properties in 2001;

n $138 million of additional depreciation, depletion and amortization expense recognized in connection with a full year of operations after the Louis Dreyfus acquisition and

n A $28 million increase associated with other new plant additions.

Other taxes increased 9% to $429 million, primarily due to higher severance taxes associated with a full year of Louis Dreyfus operations. In addition, Dominion incurred higher property taxes on new asset additions, partially offset by lower gross receipts taxes, primarily reflecting lower regulated gas sales revenue.

Other income decreased 18% to $103 million, primarily reflecting $27 million of equity losses from DFV.

Income taxes—Dominion’s effective income tax rate decreased, reflecting the net $33 million effect of including certain subsidiaries in Dominion’s consolidated state income tax returns. In addition, the effective tax rate decreased for foreign earnings, the discontinuance of goodwill amortization for book purposes and other factors.

Outlook—Dominion

Dominion believes its operating businesses will provide growth in net income on a per share basis, including the impact of higher expected average shares outstanding, in 2004 and 2005.

Growth factors for 2004 include:

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

n Continued growth in utility customers;

n Reduced electric capacity expenses, resulting from terminated contracts;

n Lower interest expense as a result of refinanced debt;

n Higher expected levels of gas and oil production as a result of Devils Tower and Front Runner becoming operational;

n Improved contributions from Millstone’s operations, resulting from expected higher capacity factors and favorable sales prices;

n Higher contribution from Cove Point operations;

n Expected Six Sigma benefits and

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

n Lost revenue due to Hurricane Isabel;

n The Virginia fuel rate case settlement and

n Costs associated with refinancing callable debt.

For 2004, the growth factors will be partially offset by:

n Decreased pension credits and increased other postretirement benefit costs;

n Higher expected operating expenses for gas and oil production and

n Normalization of Clearinghouse contribution.

Growth factors for 2005 include:

n Gas and oil production growth, reflecting a full year of Devils Tower and Front Runner operations;

n A full year of operations of the Kewaunee power plant, expected to be acquired in the second half of 2004;

n Continued growth in utility customers;

n Expanded operations of Cove Point and

n Expected Six Sigma benefits.

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For 2005, the growth factors are expected to be partially offset by:

n Increased interest expense and

n Inflation and other factors.

Based on these projections, Dominion estimates that cash flow from operations will increase in 2004, as compared to 2003. Management believes this increase, coupled with reductions in discretionary and developmental capital expenditures previously planned for power generation and gas and oil exploration and production projects, will provide sufficient cash flow to maintain or grow Dominion’s current dividend to common shareholders.

Segment Results of Operations

Dominion Generation

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet.

	2003		2002		2001
(millions, except EPS)
Net income contribution	$	508	$	561	$	511
EPS contribution	$	1.59	$	1.98	$	2.02
Electricity supplied (million mwhrs)		105		101		95

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

	2003 vs. 2002						2002 vs. 2001
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Revenue reallocation	$	(57	)	$	(0.20	)		—			—
Regulated electric sales:
Weather		(42	)		(0.15	)	$	82		$	0.32
Customer growth		23			0.08			25			0.10
Merchant generation margins		18			0.06			(122	)		(0.48	)
Capacity expenses		29			0.10			8			0.03
Fuel settlement		(9	)		(0.03	)		—			—
Utility outages		(13	)		(0.04	)		11			0.04
Other		(2	)		—			46			0.19
Share dilution		—			(0.21	)		—			(0.24	)
Change in net income contribution	$	(53	)	$	(0.39	)	$	50		$	(0.04	)

2003 vs. 2002

Dominion Generation’s net income contribution decreased $53 million over 2002, primarily reflecting:

n A change in the allocation of electric utility base rate revenue beginning in 2003 among Dominion Generation, Dominion Energy and Dominion Delivery;

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

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

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

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

n Increased utility outage expenses, reflecting the refueling activities at the utility nuclear facilities in 2003.

2002 vs. 2001

Dominion Generation’s net income contribution rose $50 million over 2001, primarily reflecting:

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

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

n A decrease in merchant generation sales primarily as a result of lower prices in 2002, partially offset by a full year of Millstone operations.

Dominion Energy

Dominion Energy includes Dominion’s electric transmission, natural gas transmission pipeline and storage businesses, certain natural gas production, as well as Clearinghouse (energy trading and marketing) and field services (aggregation of gas supply and related wholesale activities) operations.

	2003		2002		2001
(millions, except EPS)
Net income contribution	$	350	$	268	$	268
EPS contribution	$	1.10	$	0.95	$	1.06
Gas transportation throughput (bcf)		612		597		553

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

	2003 vs. 2002						2002 vs. 2001
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Clearinghouse	$	16		$	0.06		$	(4	)	$	(0.02	)
Economic hedges		33			0.12			(43	)		(0.17	)
Electric transmission operations		11			0.04			16			0.06
Cove Point operations		9			0.03			—			—
Revenue reallocation		7			0.02			—			—
Interest		(5	)		(0.02	)		6			0.02
Other		11			0.04			25			0.11
Share dilution		—			(0.14	)		—			(0.11	)
Change in net income contribution	$	82		$	0.15			—		$	(0.11	)

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2003 vs. 2002

Dominion Energy’s net income rose $82 million from 2002, primarily reflecting:

n An increase in the contribution of Clearinghouse operations, reflecting a $43 million increase in margins on settled contracts, partially offset by a $27 million decrease in net mark-to-market gains on derivative contracts;

n An increase attributable to a reduction in net losses on the economic hedges of Dominion Exploration & Production gas production described in Selected Information—Energy Trading Activities below;

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

n An increase in electric transmission contribution due to customer growth and other factors, partially offset by weather and

n The operations of Cove Point, which was reactivated during 2003.

2002 vs. 2001

Dominion Energy’s net income contribution did not change compared to 2001, and reflected:

n A decrease in the contribution of Clearinghouse operations, reflecting a $54 million decrease in net mark-to-market gains on derivative contracts, partially offset by a $47 million increase in margins on settled contracts;

n Net losses associated with the economic hedges of Dominion Exploration & Production gas production;

n An increase in electric transmission contribution, reflecting the impact of customer growth and favorable weather conditions as well as reduced depreciation expense, resulting from the extension of estimated useful lives of transmission assets and

n A decrease in interest expense, resulting primarily from lower interest rates.

Selected Information—Energy Trading Activities

As previously described, Dominion Energy manages Dominion’s energy trading, hedging and arbitrage activities through the Clearinghouse. Dominion believes these operations complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas, electricity, and oil. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. The Clearinghouse enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, the Clearinghouse typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Clearinghouse management continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity, seeking arbitrage opportunities.

In addition, the Clearinghouse held a portfolio of financial derivative instruments to manage Dominion’s price risk associated with a portion of its anticipated sales of 2003 natural gas production that had not been considered in the hedging activities of the Dominion Exploration & Production segment (economic hedges). For the year ended December 31, 2003, Dominion Energy recognized a net loss of $10 million on the economic hedges. As anticipated, Dominion Exploration & Production sold sufficient volumes of natural gas in 2003 at market prices, which, when combined with the settlement of the economic hedges, resulted in a range of prices for those sales contemplated by the risk management strategy.

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

	Amount
(millions)
Net unrealized gain at December 31, 2002	$	170
Reclassification of contracts—adoption of EITF 02-3:
Non-derivative energy contracts		(110	)
Derivative energy contracts, not held for trading purposes		(81	)
		(21	)
Contracts realized or otherwise settled during the period		41
Net unrealized gain at inception of contracts initiated during the period		—
Changes in valuation techniques		—
Other changes in fair value		13
Net unrealized gain at December 31, 2003	$	33

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

	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less than 1 year			1-2 years		2-3 years		3-5 years		In Excess of 5 years	Total
(millions)
Actively quoted(1)	$	(14	)	$	24	$	4		—	—	$	14
Other external sources(2)		—			10		6	$	3	—		19
Models and other valuation methods(3)		—			—		—		—	—		—
Total	$	(14	)	$	34	$	10	$	3	—	$	33

(1) Exchange-traded and over-the-counter contracts.

(2) Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.

(3) Values based on Dominion’s estimate of future commodity prices when information from external sources is not available and use of internally-developed models, reflecting option pricing theory, discounted cash flow concepts, etc.

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Dominion Delivery

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

	2003		2002		2001
(millions, except EPS)
Net income contribution	$	453	$	422	$	311
EPS contribution	$	1.42	$	1.49	$	1.23
Electricity delivered (million mwhrs)		75		75		72
Gas throughput (bcf)		373		364		357

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

	2003 vs. 2002						2002 vs. 2001
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount		EPS
(millions, except EPS)
Revenue reallocation	$	50		$	0.18			—		—
Customer growth—utility operations		10			0.03		$	10	$	0.04
Weather		(5	)		(0.02	)		50		0.20
Interest expense		—			—			14		0.06
Income taxes		(9	)		(0.03	)		18		0.07
Other		(15	)		(0.05	)		19		0.07
Share dilution		—			(0.18	)		—		(0.18	)
Change in net income contribution	$	31		$	(0.07	)	$	111	$	0.26

2003 vs. 2002

Dominion Delivery’s net income contribution rose $31 million from 2002, primarily reflecting:

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

n Customer growth in the electric and gas franchise service area, primarily reflecting new residential electric customers;

n A decrease in regulated electric sales due to comparably milder weather in Dominion’s electric utility service territories offset by the increase in regulated gas sales due to comparably colder weather in Dominion’s gas utility service territories;

n A decrease in pension credits and an increase in other postretirement benefit costs and

n The deferral of 2003 bad debt expenses as regulatory assets, pending future recovery under a bad debt rider approved by the Public Utility Commission of Ohio, effective January 1, 2003.

2002 vs. 2001

Dominion Delivery’s net income contribution rose $111 million over 2001, primarily reflecting:

n Customer growth in the electric and gas franchise service area, primarily reflecting new residential electric customers;

n Comparably warmer weather, resulting in increased summer sales in Dominion’s electric service territories and comparably colder winter weather, resulting in increased sales in both electric and gas service territories;

n A decrease in interest expense, resulting primarily from lower interest rates and

n A decrease in the effective income tax rate for reasons described for Dominion on a consolidated basis.

Dominion Exploration & Production

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

	2003		2002		2001
(millions, except EPS)
Net income contribution	$	415	$	380	$	320
EPS contribution	$	1.30	$	1.34	$	1.27
Gas production (bcf)		384		385		283
Oil production (million bbls)		9		10		7
Average realized prices with hedging results:(1)
Gas (per mcf)(2)	$	3.95	$	3.40	$	3.80
Oil (per bbl)		24.29		23.28		23.42
Average prices without hedging results:
Gas (per mcf)(2)		4.99		3.03		3.87
Oil (per bbl)		29.82		24.44		23.53
DD&A (per mcfe)	$	1.20	$	1.12	$	1.08
Average production (lifting) cost (per mcfe)		0.80		0.60		0.65

(1) Excludes the effects of the economic hedges discussed in the operating results of Dominion Energy under Selected Information—Energy Trading Activities.

(2) Excludes $43 million of revenue recognized in 2003 under the volumetric production payment agreement described in Note 12 to the Consolidated Financial Statements.

Presented below are the key factors impacting Dominion Exploration & Production’s operating results:

	2003 vs. 2002						2002 vs. 2001
	Increase (Decrease)						Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Gas and oil—prices	$	133		$	0.47		$	(88	)	$	(0.35	)
Gas and oil—production		(18	)		(0.06	)		277			1.10
VPP revenue		27			0.10			—			—
DD&A—rate		(22	)		(0.08	)		14			0.06
DD&A—production		3			0.01			(105	)		(0.42	)
Operations and maintenance		(41	)		(0.15	)		(21	)		(0.08	)
Severance taxes		(18	)		(0.06	)		(7	)		(0.03	)
Income taxes		(20	)		(0.07	)		(5	)		(0.02	)
Other		(9	)		(0.03	)		(5	)		(0.03	)
Share dilution		—		$	(0.17	)		—		$	(0.16	)
Change in net income contribution	$	35		$	(0.04	)	$	60		$	0.07

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2003 vs. 2002

Dominion Exploration & Production’s net income contribution rose $35 million from 2002, primarily reflecting:

n Higher average realized prices for gas and oil;

n Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production. Lower gas production, reflecting the sale of minerals rights under a volumetric production payment agreement (VPP) and declines in Rocky Mountain and Michigan production, was largely offset by increased Gulf of Mexico gas production;

n A higher rate for depreciation, depletion and amortization in 2003, primarily reflecting increased acquisition, finding and development costs;

nHigher operations and maintenance expenses which increased in connection with overall higher commodity prices in 2003, that caused an increase in the demand for equipment, labor and services;

n Higher severance taxes, resulting from higher gas and oil revenue associated with higher commodity prices in a higher commodity price environment and

n Higher income taxes, primarily reflecting the expiration of Section 29 production tax credits beginning in 2003 ($34 million), partially offset by a reduction in tax rates applied to deferred taxes associated with Canadian operations ($14 million).

2002 vs. 2001

Dominion Exploration & Production’s net income contribution rose $60 million, primarily reflecting a full year of Louis Dreyfus operations following its acquisition in the fourth quarter of 2001. These new operations, as well as ongoing drilling programs, resulted in increased gas and oil production, and higher operating expenses, such as depreciation, depletion and amortization and gas well expenses.

Corporate and Other

Corporate and Other includes the operations of DCI, DFV and related telecommunications operations, and Dominion’s corporate and other operations.

	2003			2002			2001
(millions, except EPS amounts)
Specific items attributable to operating segments	$	(221	)	$	7		$	(297	)
DCI operations		(95	)		14			(225	)
Telecommunications operations(1)		(750	)		(26	)		—
Other corporate operations		(342	)		(264	)		(344	)
Total net expense		(1,408	)		(269	)		(866	)
Earnings per share impact	$	(4.41	)	$	(0.94	)	$	(3.43	)

(1) $642 million is classified as discontinued operations in 2003.

Specific Items Attributable to Operating Segments—2003

During 2003, Dominion reported in the Corporate and Other segment the following items attributable to its operating segments:

n $21 million net after-tax gain representing the cumulative effect of adopting new accounting principles, as described in Note 3 to the Consolidated Financial Statements, including:

n SFAS No. 143: a $180 million after-tax gain attributable to: Dominion Generation ($188 million after-tax gain); Dominion Exploration & Production ($7 million after-tax loss); and Dominion Delivery ($1 million after-tax loss);

n EITF 02-3: a $67 million after-tax loss attributable to Dominion Energy;

n SFAS No. 133 Interpretation C20: a $75 million after-tax loss attributable to Dominion Generation and

n FIN 46R: a $17 million after-tax loss attributable to Dominion Generation;

n $197 million of operations and maintenance expense ($122 million after-tax), representing incremental restoration expenses associated with Hurricane Isabel, attributable primarily to Dominion Delivery;

n A $105 million ($65 million after-tax) charge for the termination of power purchase contracts attributable to Dominion Generation;

n A $64 million ($39 million after-tax) charge for the restructuring and termination of certain electric sales contracts attributable to Dominion Generation and

n $28 million ($16 million after-tax) of severance costs for workforce reductions during the first quarter of 2003, attributable to:

n Dominion Generation ($8 million after-tax)

n Dominion Energy ($2 million after-tax),

n Dominion Delivery ($4 million after-tax),

n Dominion Exploration & Production ($1 million after-tax) and

n Corporate and other ($1 million after-tax);

Specific Items Attributable to Operating Segments—2001

During 2001, Dominion reported in the Corporate and Other segment the following items attributable to its operating segments:

n A $68 million after-tax charge for restructuring activities, including employee severance and termination benefits and costs associated with the termination of leases, attributable to:

n Dominion Generation ($8 million after-tax);

n Dominion Energy ($9 million after-tax);

n Dominion Delivery ($44 million after-tax) and

n Dominion Exploration & Production ($3 million after-tax);

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

n Dominion Exploration & Production ($99 million after-tax);

n Dominion Energy ($2 million after-tax credit);

33

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

DCI Operations

DCI recognized a net loss in 2003, resulting primarily from the recognition of the following:

n $51 million ($33 million after-tax) impairment of retained interests from securitizations;

n $34 million ($22 million after-tax) impairment of goodwill and other investments;

n $23 million ($15 million after-tax) recognized in connection with the sale of financial assets during the fourth quarter of 2003 and

n $26 million valuation allowance on certain deferred tax assets.

DCI earned $14 million in 2002, compared to a net loss of $225 million in 2001. The net loss in 2001, resulted primarily from the recognition of the following:

n $102 million ($66 million after-tax) impairment of retained interests from securitizations;

n $94 million ($61 million after-tax) impairment of loans receivable and

n $85 million ($55 million after-tax) impairment of other investments.

Telecommunications Operations

Dominion’s loss from its telecommunications business increased $724 million to $750 million in 2003, primarily reflecting:

n $566 million associated with the impairment of network assets and related inventories. 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;

n A $48 million increase in deferred tax expense as a result of the increase in the valuation allowance on deferred tax assets;

n Dominion’s purchase of the remaining equity interest in DFV held by another party for $62 million in December 2003, $60 million of which was recorded as goodwill and impaired;

n $57 million ($35 million after-tax) for the costs associated with Dominion’s acquisition of DFV senior notes and

n $41 million of after-tax operating losses.

Other Corporate Operations

The net loss associated with other corporate operations for 2003 increased by $78 million as compared to 2002, primarily reflecting the impairment of certain investments held for sale. Included in these investments was a small generation facility in Kauai, Hawaii that was sold in December 2003.

The net loss associated with other corporate operations decreased in 2002 as compared to 2001, primarily as a result of discontinuing the amortization of goodwill beginning January 1, 2002.

Dominion’s Sources and Uses of Cash

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

At December 31, 2003, Dominion had cash and cash equivalents of $126 million with $655 million of unused capacity under its credit facilities. For long-term financing needs, amounts available for debt or equity offerings under currently effective shelf registrations totaled $4.4 billion at March 1, 2004.

Cash Provided By Operations

As presented on Dominion’s Consolidated Statements of Cash Flows, net cash flows from operating activities were $2.4 billion for each of the years 2003, 2002 and 2001. Dominion’s management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow current shareholder dividend levels.

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

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

n Extreme weather events that could disrupt gas and oil production or cause catastrophic damage to Dominion’s electric distribution and transmission systems;

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

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

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

n Contractual or regulatory restrictions on transfers of funds among Dominion and its subsidiaries; and

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

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy trading, marketing and hedging activities and sales of gas and oil production. Presented below is a summary of Dominion’s gross and net credit exposure as of December 31, 2003 for these activities. Dominion calculates its gross credit exposure for each counterparty as the unrealized

34

fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	404		—	$	404
Non-investment grade(2)		60	$	14		46
No external ratings:
Internally rated—investment grade(3)		306		—		306
Internally rated—non-investment grade(4)		109		—		109
Total	$	879	$	14	$	865

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 13% of the total gross credit exposure.

(2) The five largest counterparty exposures, combined, for this category represented approximately 4% of the total gross credit exposure.

(3) The five largest counterparty exposures, combined, for this category represented approximately 24% of the total gross credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 5% of the total gross credit exposure.

Cash Provided By Financing Activities

Dominion Resources, Inc., Virginia Electric and Power Company (Virginia Power) and CNG (collectively the Dominion Companies) rely on bank and capital markets as a significant source of funding for capital requirements not satisfied by cash provided by the companies’ operations. As discussed further in the Credit Ratings section below, the Dominion Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by the issuing company’s credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including authorization by the SEC and, in the case of Virginia Power, the Virginia State Corporation Commission (Virginia Commission).

During 2003, 2002 and 2001, net cash flows from financing activities were $853 million, $1.3 billion and $1.9 billion, respectively. During 2003, the Dominion Companies issued long-term debt (net of exchanged debt) and common stock totaling approximately $4.4 billion. The proceeds were used primarily to repay other debt and to finance capital expenditures.

Credit Facilities and Short-Term Debt

The Dominion Companies use short-term debt, primarily commercial paper, to fund working capital requirements and as bridge financing for acquisitions, if applicable. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. At December 31, 2003, the Dominion Companies had committed lines of credit totaling $3.0 billion. Although there were no loans outstanding, these lines of credit support commercial paper borrowings and letter of credit issuances. At December 31, 2003, the Dominion Companies had the following short-term debt outstanding and capacity available under credit facilities:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
364-day joint revolving credit facility	$	1,250
Three-year joint revolving credit facility		750
Total joint credit facilities(1)		2,000	$	1,440	$	85	$	475
364-day CNG credit facility(2)		1,000		—		820		180
Totals	$	3,000	$	1,440	$	905	$	655

(1) The joint credit facilities support borrowings by the Dominion Companies. The 364-day revolving credit facility was executed in May 2003 and terminates in May 2004. The three-year revolving credit facility was executed in May 2002 and terminates in May 2005.

(2) The credit facility is used to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements under its gas and oil hedging program. The facility was executed in August 2003 and terminates in August 2004.

Dominion’s financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2003, the total amount of commercial paper outstanding was $1,440 million and the total amount of letter of credit issuances was $905 million, leaving approximately $655 million available for issuance. The Dominion Companies are required to pay minimal annual commitment fees to maintain the credit facilities.

In addition, these credit agreements contain various terms and conditions that could affect the Dominion Companies’ ability to borrow under these facilities. They include maximum debt to total capital ratios, material adverse change clauses and cross-default provisions.

All of the credit facilities include a defined maximum total debt to total capital ratio. As of December 31, 2003, the calculated ratio for the Dominion Companies, pursuant to the terms of the agreements, was as follows:

Company	Maximum Ratio		Actual Ratio(1)
Dominion Resources, Inc.	65	%	56	%
Virginia Power	60	%	52	%
CNG	60	%	52	%

(1) Indebtedness as defined by the bank agreements excludes certain junior subordinated notes payable to affiliated trusts and mandatorily convertible securities that are reflected on the Consolidated Balance Sheets.

These provisions apply separately to Dominion Resources, Inc., Virginia Power and CNG. If any one of the Dominion Companies or any of that specific company’s material subsidiaries fail to make payment on various debt obligations in excess of $25 million, the lenders could require that respective company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commit -

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ment to lend funds to that company. Accordingly, any defaults on indebtedness by CNG or any of its material subsidiaries would not affect the lenders’ commitment to Virginia Power. Similarly, any defaults on indebtedness by Virginia Power or any of its material subsidiaries would not affect the lenders’ commitment to CNG. However, any default by either CNG or Virginia Power would also affect in like manner the lenders’ commitment to Dominion Resources, Inc. under the joint credit agreements.

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

Common Stock

During 2003, Dominion issued 17 million shares of common stock and received proceeds of $990 million. Of this amount, 11 million shares and proceeds of $683 million resulted from a public offering. The remainder of the shares issued and proceeds received were through Dominion Direct® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options.

Long-Term Debt

During 2003, Dominion Resources, Inc. and its subsidiaries issued the following long-term debt:

Type	Principal			Rate	Maturity	Issuing Company
	(millions)
Senior notes	$	2,120		2.125% to 6.30%	2005 to 2033	Dominion Resources, Inc.
Senior notes		500		Variable	2013	Dominion Resources, Inc.
Senior notes		200		5.00%	2014	CNG
Senior notes		1,055		4.10% to 5.25%	2010 to 2038	Virginia Power
Total long-term debt issued		3,875
Less: direct exchange(1)		(500	)
Total long-term debt issued, excluding direct exchanges	$	3,375

(1) During the third quarter of 2003, Dominion redeemed its $500 million variable rate senior notes due 2013. In a direct exchange, Dominion completed the redemption by issuing $510 million of 5.25% senior notes due 2033.

In addition to the senior notes described above, Dominion borrowed $18 million to complete a power generation project at Virginia Power’s Possum Point power station.

In January 2004, Dominion Resources, Inc. issued $100 million of variable rate senior notes due 2006 and $200 million of 5.2% senior notes due 2016. Net proceeds were used for general corporate purposes, principally the repayment of debt.

During 2003, Dominion Resources, Inc. and its subsidiaries repaid $2.9 billion of long-term debt securities. Dominion used the entirety of its $500 million escrow deposit, established in December 2002, to repay matured debt in January 2003.

Amounts Available under Shelf Registrations

At March 1, 2004, Dominion Resources, Inc., Virginia Power, and CNG had approximately $2.4 billion, $670 million, and $1.3 billion, respectively, of available capacity under currently effective shelf registrations. Securities that may be issued under these shelf registrations, depending upon the registrant, include senior notes (including medium-term notes), subordinated notes, first and refunding mortgage bonds, trust preferred securities, preferred stock and common stock.

Credit Ratings

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

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for the Dominion Companies are most affected by each company’s financial profile, mix of regulated and non-regulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable, such as major acquisitions.

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

	Standard & Poor’s	Moody’s
Dominion Resources, Inc.
Senior unsecured debt securities	BBB+	Baa1
Preferred securities of affiliated trusts	BBB-	Baa2
Commercial paper	A-2	P-2
Virginia Power
Mortgage bonds	A-	A2
Senior unsecured (including tax-exempt) debt securities	BBB+	A3
Preferred securities of affiliated trust	BBB	Baa1
Preferred stock	BBB	Baa2
Commercial paper	A-2	P-1
CNG
Senior unsecured debt securities	BBB+	A3
Preferred securities of affiliated trust	BBB-	Baa1
Commercial paper	A-2	P-2

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As of February 2, 2004, Moody’s maintains a negative outlook for its ratings of CNG and Standard & Poor’s maintains a negative outlook for its ratings of Dominion Resources, Inc. and CNG.

Generally, a downgrade in an individual company’s credit rating would not restrict its ability to raise short-term and long-term financing so long as its credit rating remains “investment grade,” but it would increase the cost of borrowing. Dominion has been working closely with both Standard & Poor’s and Moody’s with the objective of maintaining its current credit ratings. Recent steps to improve the agencies’ view of Dominion’s financial position include the reduction of planned capital spending and related borrowings, as discussed below, and the issuance of $2.0 billion of common stock during 2002 and $990 million during 2003. As discussed in Risk Factors and Cautionary Statements That May Affect Future Results, in order to maintain its current ratings, Dominion may find it necessary to modify its business plans and such changes may adversely affect its growth and earnings per share.

Debt Covenants

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

n The timely payment of principal and interest;

n Information requirements, including submitting financial reports filed with the SEC to lenders;

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

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

n Limitations on liens.

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

Cash Used In Investing Activities

During 2003, 2002 and 2001, investing activities resulted in net cash outflows of $3.4 billion, $4.0 billion, and $4.2 billion respectively. Significant investing activities for 2003 included:

n $2.1 billion for the construction and expansion of generation facilities, including environmental upgrades, purchases of nuclear fuel, and construction and improvements of gas and electric transmission and distribution assets;

n $1.3 billion for the purchase and development of gas and oil producing properties, drilling and equipment costs and undeveloped lease acquisitions;

n $777 million for the purchase of securities and $912 million for the sale of securities, primarily related to investments held in nuclear decommissioning trusts;

n $633 million for purchase of DFV senior notes;

n $385 million in advances related to a generation project under construction in Pennsylvania. The asset, when completed, will be leased to Dominion;

n $305 million of proceeds from sales of gas and oil properties and

n release of $500 million from escrow for the repayment of debt.

Future Cash Payments For Contractual Obligations and Planned Capital Expenditures

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

	Less Than 1 Year		1-3 years		3-5 years		More than 5 years		Total
(millions)
Long-term debt(1)	$	1,239	$	3,724	$	2,626	$	9,485	$	17,074
Interest charges		981		1,778		1,383		7,965		12,107
Leases		70		95		60		57		282
Purchase obligations:
Purchased electric capacity for utility operations		589		1,155		1,063		4,176		6,983
Fuel used for utility operations—other(2)		986		638		309		424		2,357
Production handling		44		117		89		43		293
Pipeline capacity		86		141		89		235		551
Energy commodity purchases for resale(3)		547		102		24		—		673
Other fuel – nonregulated		30		119		102		—		251
Other		283		276		265		274		1,098
Other long-term liabilities:
Financial derivatives(3)		725		645		40		193		1,603
Asset retirement obligations(4)		49		56		84		11,502		11,691
Other contractual obligations		55		35		4		32		126
Total cash payments	$	5,684	$	8,881	$	6,138	$	34,386	$	55,089

⁽¹⁾ Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

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⁽²⁾ Fuel used in utility operations is recoverable through rate recovery mechanisms.

⁽³⁾ Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among Dominion and its counterparties were liquidated and terminated.

⁽⁴⁾ Represents expected cash payments adjusted for inflation for estimated costs to perform asset retirement activities.

Dominion’s planned capital expenditures during 2004 are expected to total approximately $2.4 billion. For 2005, planned capital expenditures are expected to range from $2.4 billion to $2.6 billion. These expenditures include construction and expansion of generation facilities, environmental upgrades, construction improvements and expansion of gas and electric transmission and distribution assets, purchases of nuclear fuel and expenditures to explore for and develop natural gas and oil properties. Dominion expects to fund its capital expenditures with cash from operations, and a combination of sales of securities and short-term borrowings.

Dominion may choose to postpone or cancel certain planned capital expenditures, to the extent they are not fully covered by operating cash flows. Dominion would do this in order to mitigate the need for future debt financings, beyond those needed to cover normal maturities and redemptions.

Use of Off-Balance Sheet Arrangements

Leasing Arrangements

As of December 31, 2003, Dominion was party to an agreement with a voting interest entity (lessor) in order to construct and lease a new power generation project in Pennsylvania. Project costs totaled $695 million at December 31, 2003 of which $624 million was advanced to the lessor by Dominion. Dominion expects to be repaid during 2004. This project is expected to be completed in 2004 and will result in estimated annual lease commitments of approximately $58 million. A lease agreement has not yet been executed for this project, however, Dominion expects that, once executed, it will qualify as an operating lease.

Dominion has been appointed to act as the construction agent for the lessor and controls the design and construction of the facility. Dominion, in this role, is responsible for completing construction by a specified date. In the event a project is terminated before completion, Dominion has the option to either purchase the project for 100% of project costs plus fees or terminate the project and turn it over to the lessor.

Benefits of this arrangement include:

n Certain tax benefits as Dominion would be considered the owner of the leased property for tax purposes. As a result, it would be entitled to tax deductions for depreciation not recognized for financial accounting purposes and

n As an operating lease for financial accounting purposes, the asset and related borrowings used to finance the construction of the asset would not be included on Dominion’s Consolidated Balance Sheets. Although this improves measures of leverage calculated using amounts reported in Dominion’s Consolidated Financial Statements, credit rating agencies view lease obligations as debt equivalents in evaluating Dominion’s credit profile.

Securitizations of Mortgages and Loans

As of December 31, 2003, Dominion held $413 million of retained interests from securitizations of mortgage and commercial loans completed in prior years. Dominion did not securitize or originate any loans in 2003. Investors in the securitization trusts have no recourse to Dominion’s other assets for failure of debtors to repay principal and interest on the underlying loans when due. Therefore, Dominion’s exposure to any future losses from this activity is limited to its investment in retained interests.

Future Issues and Other Matters

Status of Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act), enacted in 1999, established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed among other things: capped base rates, participation in a regional transmission organization (RTO), retail choice and the recovery of stranded costs. Dominion made retail choice available to all of its Virginia regulated electric customers as of January 1, 2003.

Base Rates

Under the Virginia Restructuring Act, the generation portion of Dominion’s Virginia jurisdictional operations is no longer subject to cost-based rate regulation. Dominion’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007, unless modified or terminated sooner under the Virginia Restructuring Act. Recovery of generation-related costs will continue through capped rates, and, where applicable, a wires charge assessed on those customers opting for alternative suppliers. Additionally, the Virginia Restructuring Act provides that after the end of the capped rate period, any default service provided by Dominion will be based upon competitive market prices for electric generation services.

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

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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.

RTO

The Virginia Restructuring Act requires that Dominion join an RTO subject to Virginia Commission approval. FERC requires each public utility that owns or operates transmission facilities to make certain filings with respect to RTO formation, but relies on voluntary formation of RTOs to advance its energy policies. By joining an RTO, Dominion’s regulated electric utility subsidiary, Virginia Power, would transfer functional control of its transmission assets to a third-party RTO.

In September 2002, Dominion and PJM Interconnection, LLC (PJM) entered into the PJM South Implementation Agreement. The agreement provides that, subject to regulatory approval and certain provisions, Dominion will become a member of PJM, transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region and integrate its control area into the PJM energy markets. The agreement also allocates costs of implementation of the agreement among the parties.

In June 2003, Dominion made a filing as required by the Virginia Restructuring Act requesting authorization from the Virginia Commission to become a member of PJM on November 1, 2004. In September 2003, the Virginia Commission issued an order directing Dominion to provide additional information concerning the application. Hearings on Dominion’s application are scheduled to begin in October 2004. Dominion intends to file for FERC and North Carolina Commission approval to join PJM in the future.

Dominion has incurred and will continue to incur integration and operating costs associated with joining an RTO. Dominion has deferred certain of these costs for future recovery and is giving further consideration to seeking regulatory approval to defer the balance of such costs.

Recovery of Stranded Costs

Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market. At December 31, 2003, Dominion’s exposure to potentially stranded costs consisted of long-term purchased power contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. Dominion believes capped electric retail rates and, where applicable, wires charges will provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Recovery of Dominion’s potentially stranded costs remains subject to numerous risks even in the capped-rate environment. These include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs, and recovery of certain other items.

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

In January 2004, the Commission on Electric Utility Restructuring adopted a resolution related to the monitoring of stranded costs.

Changes to Cost Structure—While the Virginia Restructuring Act did not define specific generation-related costs to be recovered, it did provide for generation-related cash flows (through the combination of capped rates and wires charges billed to customers) through July 1, 2007, unless terminated earlier pursuant to the Virginia Restructuring Act (the transition period). The generation-related cash flows provided by the Virginia Restructuring Act are intended to compensate Dominion for continuing to provide generation services and to allow Dominion management to incur costs to restructure such operations during the transition period. As a result, during the tran -

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sition period, Dominion may increase earnings to the extent that management can reduce operating costs for its utility generation-related operations. Conversely, the same risks affecting the recovery of Dominion’s stranded costs, discussed above, may also adversely impact its cost structure during the transition period. Accordingly, Dominion could realize the negative economic impact of any such adverse event. In addition to managing the cost of its generation-related operations, Dominion may also seek opportunities to sell available electric energy and capacity to customers beyond its electric utility service territory. Using cash flows from operations during the transition period, Dominion may further alter its cost structure or choose to make additional investment in its business.

The capped rates were derived from rates established as part of the 1998 Virginia rate settlement and do not provide for specific recovery of particular generation-related expenditures, except for certain regulatory assets. To the extent that Dominion manages its operations to reduce its overall operating costs below those levels included in the capped rates, Dominion’s earnings may increase. Since the enactment of the Virginia Restructuring Act, Dominion has been reviewing its cost structure to identify opportunities to reduce the annual operating expenses of its generation-related operations. For example, the reduction in future fixed capacity payments, resulting from the termination of certain long-term power purchase agreements during 2001 and 2003, is expected to increase annual after- tax earnings by approximately $48 million during the transition period.

Also in 2002 and 2001, Dominion revised the estimated useful lives of its electric generation assets. The changes in estimates were based upon expected life-extensions of nuclear plants and new engineering studies of the other assets. As a result of these changes, annual after-tax earnings will increase by approximately $67 million during the transition period, as a result of lower depreciation expense for these assets.

FERC Standard Market Design Proposal

In 2002, FERC issued proposed rules that would establish a standardized transmission service and wholesale electric market design for entities participating in wholesale electric markets. FERC proposed to exercise jurisdiction over the transmission component of bundled retail transactions, modify the existing electric transmission tariff to include a single tariff service applicable to all transmission customers and provide a standard market design for wholesale electric markets. FERC also proposed that transmission owners that have not yet joined an RTO must contract with a separate entity, an independent transmission provider, to operate their transmission facilities. FERC scheduled a number of technical conferences and meetings with interested parties and has indicated that the market design and timing of the rule is subject to change.

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

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, Dominion recovered such costs arising from regulated electric operations through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period ending June 30, 2007, in excess of the level currently included in the Virginia jurisdictional electric retail rates, Dominion’s results of operations will decrease. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations. Dominion also may seek recovery through regulated rates for environmental expenditures related to regulated gas transmission and distribution operations.

Environmental Protection and Monitoring Expenditures

Dominion incurred approximately $113 million, $123 million and $116 million of expenses (including depreciation) during 2003, 2002 and 2001, respectively, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $120 million in 2004. In addition, capital expenditures related to environmental controls were $210 million, $335 million and $221 million for 2003, 2002 and 2001, respectively. The estimated amount for these expenditures is $100 million for 2004.

Clean Air Act Compliance

The Clean Air Act requires Dominion to reduce its emissions of sulfur dioxide (SO₂ ) and nitrogen oxide (NO_X ), which are gaseous by-products of fossil fuel combustion. The Clean Air Act’s SO₂ and NO_X reduction programs include:

n The issuance of a limited number of SO₂ emission allowances. Each allowance permits the emission of one ton of SO₂ into the atmosphere. The allowances may be transacted with a third party; and

n The issuance of a limited number of NO_X emission allowances to comply with NO_X emission requirements applicable during ozone season months of May through September. Each allowance permits the emission of one ton of NO_X into the atmosphere.

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Implementation of projects to comply with SO₂ and NO_X limitations are ongoing and will be influenced by changes in the regulatory environment, availability of allowances, various state and federal control programs, and emission control technology. In response to these requirements, Dominion expects to make the following capital expenditures at its affected generating facilities:

n $350 million during the period 2004 through 2008 on SO₂ emission control equipment; and

n $72 million during 2004 through 2005 on NO_X reduction equipment. Total costs are expected to be $708 million, of which approximately $636 million has been incurred through December 31, 2003.

The majority of these cost estimates are also included in the capital cost expenditure estimate contemplated by the Consent Decree, described below.

In relation to a Notice of Violation received by Virginia Power in 2000 from the Environmental Protection Agency (EPA) and related proceedings, Virginia Power, the U.S. Department of Justice, the EPA, and the states of Virginia, West Virginia, Connecticut, New Jersey and New York agreed to a settlement in April 2003 in the form of a proposed Consent Decree. The Virginia federal district court entered the final Consent Decree in October 2003, resolving the underlying actions. 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.

Other

As part of its reissuance of a pollution discharge permit for the Millstone Power Station, the Connecticut Department of Environmental Protection is evaluating the ecological impacts of the cooling water intake system. Until the permit is reissued, it is not possible to predict the financial impact, if any, that may result.

Future Environmental Regulations

In December 2003, the EPA announced plans to propose additional regulations addressing pollution transport from electric generating units 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.

Under authority of the Clean Water Act, the EPA has announced the publication of new regulations governing utilities that employ a cooling water intake structure, with flow levels that exceed a minimum threshold. As announced, the EPA’s rule presents several control options. Dominion is evaluating facility information from affected power stations. Dominion cannot predict the future impact on its operations at this time.

The U.S. 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.

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

Other Matters

Telecommunications Operations

In December 2003, Dominion classified the assets and related liabilities of DTI as held-for-sale, and its results of operations as discontinued operations. The current plan of sale anticipates a closing by the end of June 2004. In addition DTI has long-term obligations, including leases, maintenance agreements and other contracts, that must be considered in the sale and may result in additional losses in future periods depending upon the final terms of the sale.

Millstone Operating Licenses

In January 2003, Dominion filed with the Nuclear Regulatory Commission to renew the operating licenses of its two nuclear units at Millstone Power Station. If renewed, Unit 2 would continue to operate until 2035 and Unit 3 until 2045.

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Kewaunee Power Plant

During the fourth quarter of 2003, Dominion announced an agreement with Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WP&L), a subsidiary of Alliant Energy Corporation, to purchase the Kewaunee Power Plant, a nuclear power station in northeastern Wisconsin. Under terms of the agreement, the aggregate purchase price is $220 million in cash, including $35 million for nuclear fuel. Dominion will sell 100% of the facility’s output to WPS (59%) and WP&L (41%) under a power purchase agreement that expires in 2013. The transaction is expected to close in the second half of 2004, pending applicable federal and state regulatory approvals. Kewaunee will be included in the Dominion Generation operating segment.

Future Acquisitions

Because Dominion’s industry is rapidly changing, there are many opportunities for acquisitions of assets, as well as for business combinations. Dominion investigates any opportunity that may increase shareholder value and build on existing businesses, with an objective to enter into transactions that would be immediately accretive to earnings per share. Dominion has participated in the past—and its security holders may assume that at any time Dominion may be participating—in bidding or other negotiations for such transactions. Such participation may or may not result in a transaction for Dominion. However, any such transaction that does take place may involve consideration in the form of cash, debt or equity securities. It may also involve payment of a premium over book or market values. Such transactions or payments could affect the market prices and rates for Dominion’s securities.

Market Rate Sensitive Instruments and Risk Management

Dominion’s financial instruments, commodity contracts and related derivative financial instruments are exposed to potential losses due to adverse changes in interest rates, equity security prices, foreign currency exchange rates and commodity prices. Interest rate risk generally is related to Dominion’s outstanding debt. Commodity price risk is present in Dominion’s electric operations, gas production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts in prices received and paid for natural gas, electricity and other commodities. Dominion uses derivative commodity contracts to manage price risk exposures for these operations. In addition, Dominion is exposed to equity price risk through various portfolios of equity securities.

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

Commodity Price Risk—Trading Activities

As part of its strategy to market energy and to manage related risks, Dominion manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. Dominion uses established policies and procedures to manage the risks associated with these price fluctuations and uses derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions. In addition, Dominion may use its generation capacity to satisfy commitments to sell energy when not needed to serve customers in its service territory.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $56 million and $12 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2003 and December 31, 2002, respectively.

Commodity Price Risk—Non-Trading Activities

Dominion manages the price risk associated with purchases and sales of natural gas, oil and electricity by using derivative commodity instruments including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of Dominion’s non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange. A hypothetical 10% unfavorable change in market prices of Dominion’s non-trading commodity-based derivative financial instruments would have resulted in a decrease in fair value of approximately $424 million and $357 million as of December 31, 2003 and December 31, 2002, respectively.

The impact of a change in energy commodity prices on Dominion’s non-trading derivative commodity instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are substantially offset by recognition of the hedged transaction, such as revenue from sales.

Interest Rate Risk

Dominion manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. Dominion also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2003, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $10 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2002, would have resulted in a decrease in annual earnings of approximately $4 million.

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In addition, Dominion, through subsidiaries, retains ownership of mortgage investments, including subordinated bonds and interest-only residual assets retained from securitizations of mortgage loans originated and purchased in prior years. Note 27 to the Consolidated Financial Statements discusses the impact of changes in value of these investments.

Foreign Exchange Risk

Dominion’s Canadian natural gas and oil exploration and production activities are relatively self-contained within Canada. As a result, Dominion’s exposure to foreign currency exchange risk for these activities is limited primarily to the effects of translation adjustments that arise from including that operation in its Consolidated Financial Statements. Dominion’s management monitors this exposure and believes it is not material. In addition, Dominion manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, Dominion’s exposure to foreign currency risk is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $19 million and $22 million in the fair value of currency forward contracts held by Dominion at December 31, 2003 and 2002, respectively.

Investment Price Risk

Dominion is subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. Dominion recognized a net realized loss (net of investment income) of $10 million and a net unrealized gain of $263 million on decommissioning trust investments for the year ended 2003. For the year ended December 31, 2002, Dominion recognized a net realized gain (including investment income) of $32 million and a net unrealized loss of $166 million.

Dominion also sponsors employee pension and other postretirement benefit plans that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in Dominion’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans. During 2003, Dominion’s pension plans experienced net realized and unrealized gains of $627 million and in 2002 net realized and unrealized losses of $241 million.

Risk Management Policies

Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on credit policies and the December 31, 2003 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

Risk Factors and Cautionary Statements That May Affect Future Results

Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; inherent risk in the operation of nuclear facilities; fluctuations in energy-related commodities prices and the effect these could have on Dominion’s earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; the transfer of control over electric transmission facilities to a regional transmission organization; political and economic conditions (including inflation and deflation); and completing the divestiture of investments held by DCI, CNG International Corporation and DFV. Other more specific risk factors are as follows:

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

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

43

existing laws or regulations, may require Dominion to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed Dominion’s estimates. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, Dominion may be a responsible party for environmental clean-up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

Dominion is exposed to cost-recovery shortfalls because of capped base rates in effect in Virginia through mid-2007 for its regulated electric utility. Under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations is open to competition and resulting uncertainty. Under the Virginia Restructuring Act, Dominion’s base rates (excluding, generally, fuel costs and certain other allowable adjustments) remain unchanged until July 2007 unless modified or terminated consistent with the Virginia Restructuring Act. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates period, Dominion remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, tax law changes, costs related to hurricanes or other weather events, inflation and increased capital costs. In addition, under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations is open to competition and is no longer subject to cost-based regulation. To date, the competitive market has been slow to develop and it is difficult to predict the pace at which the competitive environment will evolve and the extent to which Dominion will face increased competition and be able to operate profitably within this competitive environment. Additional uncertainty arises from several legislative proposals currently under consideration by the 2004 Virginia General Assembly. These proposals range from extending for three and a half years the period during which capped rates are in effect but with certain limitations on changes in the fuel factor, to suspending customer choice and returning to cost-based regulation. See Future Issues and Other Matters—Status of Deregulation in Virginia in MD&A and Note 23 to the Consolidated Financial Statements for additional information.

Dominion’s merchant power business is operating in a challenging market. The success of Dominion’s merchant power business depends upon its ability to find buyers willing to enter into power purchase agreements at prices sufficient to cover its operating costs. Depressed spot and forward wholesale power prices and excess capacity in the industry could result in lower than expected revenues in Dominion’s merchant power business.

There are inherent risks in the operation of nuclear facilities. These risks include the cost of and Dominion’s ability to maintain adequate reserves for decommissioning, plant maintenance costs, threat of terrorism, spent nuclear fuel disposal costs and exposure to potential liabilities arising out of the operation of these facilities. Dominion maintains decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses. Dominion uses derivative instruments, including futures, forwards, options and swaps, 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. In the future, Dominion could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management and Notes 2 and 8 to the Consolidated Financial Statements.

Dominion is exposed to market risks beyond its control in its energy clearinghouse operations. Dominion’s energy clearinghouse and risk management operations are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. Many industry participants have experienced severe business downturns resulting in some companies exiting or curtailing participation in the energy trading markets. This has led to a reduction in the number of trading partners and lower industry trading revenues. Declining creditworthiness of some of Dominion’s trading counterparties may limit the level of its trading activities with these parties and increase the risk that these parties may not perform under a contract.

Successfully executing Dominion’s exit from the telecommunications business is dependent upon market conditions and timing. In September 2003, Dominion announced it would recognize impairment charges related to DTI, its telecommunications investment, and that it plans to exit the telecommunications business. Continued depressed market conditions in the telecommunications industry may make it difficult for Dominion to sell the business as a whole, resulting in sales of telecommunications assets that may not include a transfer of all associated liabilities. Additionally, the difficulty in

44

finding suitable buyers for the telecommunications business and in obtaining required state and federal regulatory approvals could delay the sale of the business. If Dominion fails to sell its telecommunications business quickly, DTI risks the loss of current customers and key employees. DTI requires external sources of liquidity for its operating funds. Dominion has advanced, and anticipates making additional advances of, operating funds to DTI. Given its current financial and operating position, it is unlikely that DTI would be able to secure funds from other sources, so it is dependent on continued funding from Dominion to sustain its operations. Any additional funds provided by Dominion may not be recovered from a sale of the telecommunications business. Until a sale occurs, Dominion’s investment in the telecommunications business may continue to be adversely affected and could be subject to further impairment charges.

Dominion’s exploration and production business is dependent on factors that cannot be predicted or controlled. Factors that may affect Dominion’s financial results include fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, Dominion’s ability to acquire additional land positions in competitive lease areas as well as inherent operational risks that could disrupt production. Dominion’s liquidity may also be impacted by margin requirements that result from financial derivatives used to hedge future sales of gas and oil production and require the deposit of funds and other collateral with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Short- term market declines in natural gas and oil prices may also result in the permanent write-down of Dominion’s gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test), in a given country, at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

An inability to access financial markets could affect the execution of Dominion’s business plan. Dominion relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from its operations. Management believes that Dominion and its subsidiaries will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of Dominion’s control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to Dominion’s credit ratings. Restrictions on Dominion’s ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing rating agency requirements could negatively affect Dominion’s growth and business strategy. As of February 2, 2004, Dominion’s senior unsecured debt was rated BBB+, negative outlook, by Standard & Poor’s and Baa1, stable outlook, by Moody’s. Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, Dominion may find it necessary to take steps or modify its business plans in ways that may adversely affect its growth and earnings per share. A reduction in Dominion’s credit ratings by either Standard & Poor’s or Moody’s could increase its borrowing costs and adversely affect operating results.

Potential changes in accounting practices may adversely affect Dominion’s financial results. Dominion cannot predict the impact future changes in accounting standards or practices may have on public companies in general or the energy industry or its operations specifically. New accounting standards could be issued that could change the way Dominion records revenue, expenses, assets and liabilities. These changes in accounting standards could adversely affect Dominion’s reported earnings or could increase reported liabilities.

I tem 7A. Quantitative and Qualitative Disclosures About Market Risk

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

45

Item 8. Financial Statements and Supplementary Data

Index

	Page No.
Report of Management’s Responsibilities	47
Independent Auditors’ Report	48
Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001	49
Consolidated Balance Sheets at December 31, 2003 and 2002	50
Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income at December 31, 2003, 2002 and 2001 and for the years then ended	52
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001	53
Notes to Consolidated Financial Statements	54

46

Report of Management’s Responsibilities

The management of Dominion Resources, Inc. is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements. Certifications by Dominion’s chief executive officer and chief financial officer required by Section 302 of the Sarbanes-Oxley Act of 2002 have been filed as Exhibits 31.1 and 31.2 in the Form 10-K.

Management maintains a system of internal controls designed to provide reasonable assurance, at a reasonable cost, that Dominion’s and its subsidiaries’ assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control, and therefore cannot provide absolute assurance that the objectives of the established internal controls will be met.

This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 2003 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who were designated by the Audit Committee of the Board of Directors. Deloitte & Touche LLP’s audits were conducted in accordance with auditing standards generally accepted in the United States of America and include a review of Dominion’s and its subsidiaries’ accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.

The Audit Committee of the Board of Directors of Dominion Resources, Inc., composed entirely of independent directors meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

Management recognizes its responsibility for fostering a strong ethical climate so that Dominion’s affairs are conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in Dominion’s code of ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information, and full disclosure of public information.

DOMINION RESOURCES, INC. /s/    THOS. E. CAPPS Thos. E. Capps Chief Executive Officer
/s/    THOMAS N. CHEWNING Thomas N. Chewning Executive Vice President and Chief Financial Officer	/s/    STEVEN A. ROGERS Steven A. Rogers Vice President, Controller and Principal Accounting Officer

47

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, common shareholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees in 2003; goodwill and intangible assets in 2002; and derivative contracts and hedging activities in 2001.

/s/    DELOITTE & TOUCHE LLP

Richmond, Virginia

February 26, 2004

48

Consolidated Statements of Income

Year Ended December 31,	2003			2002			2001
(millions, except per share amounts)
Operating Revenue	$	12,078		$	10,218		$	10,558
Operating Expenses
Electric fuel and energy purchases, net		1,667			1,447			1,369
Purchased electric capacity		607			691			680
Purchased gas, net		2,175			1,159			1,822
Liquids, pipeline capacity and other purchases		468			159			219
Restructuring and other acquisition-related costs		—			(8	)		105
Other operations and maintenance		2,908			2,198			2,938
Depreciation, depletion and amortization		1,216			1,258			1,245
Other taxes		476			429			395
Total operating expenses		9,517			7,333			8,773
Income from operations		2,561			2,885			1,785
Other income (loss)		(40	)		103			126
Interest and related charges:
Interest expense		849			826			899
Distributions—mandatorily redeemable trust preferred securities		111			103			75
Subsidiary preferred dividends		15			16			23
Total interest and related charges		975			945			997
Income before income taxes		1,546			2,043			914
Income tax expense		597			681			370
Income from continuing operations before cumulative effect of changes in accounting principles		949			1,362			544
Loss from discontinued operations (net of income taxes of $15)		(642	)		—			—
Cumulative effect of changes in accounting principles (net of income taxes of $7)		11			—			—
Net Income	$	318		$	1,362		$	544
Earnings Per Common Share—Basic:
Income from continuing operations before cumulative effect of changes in accounting principles	$	2.99		$	4.85		$	2.17
Loss from discontinued operations		(2.02	)		—			—
Cumulative effect of changes in accounting principles		.03			—			—
Net income	$	1.00		$	4.85		$	2.17
Earnings Per Common Share—Diluted:
Income from continuing operations before cumulative effect of changes in accounting principles	$	2.98		$	4.82		$	2.15
Loss from discontinued operations		(2.01	)		—			—
Cumulative effect of changes in accounting principles		.03			—			—
Net income	$	1.00		$	4.82		$	2.15
Dividends paid per common share	$	2.58		$	2.58		$	2.58

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

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Consolidated Balance Sheets

At December 31,	2003			2002
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	126		$	291
Customer accounts receivable (net of allowance of $51 and $63)		3,091			2,568
Other accounts receivable		828			486
Inventories:
Materials and supplies		296			269
Fossil fuel		154			137
Gas stored—current portion		420			231
Derivative and energy trading assets		1,436			1,365
Margin deposit assets		157			149
Prepayments		202			347
Escrow account for debt refunding		—			500
Other		471			482
Total current assets		7,181			6,825
Investments
Available for sale securities		413			564
Nuclear decommissioning trust funds		1,872			1,599
Other		802			1,011
Total investments		3,087			3,174
Property, Plant and Equipment, Net
Property, plant and equipment		37,107			32,631
Accumulated depreciation, depletion and amortization		(11,257	)		(10,289	)
Total property, plant and equipment, net		25,850			22,342
Deferred Charges and Other Assets
Goodwill, net		4,300			4,301
Regulatory assets		832			584
Prepaid pension cost		1,939			1,710
Derivative and energy trading assets		402			482
Other		595			580
Total deferred charges and other assets		8,068			7,657
Total assets		$44,186			$39,998

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Consolidated Balance Sheets (continued)

At December 31,	2003			2002
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,252		$	2,125
Short-term debt		1,452			1,193
Accounts payable, trade		2,712			2,310
Accrued interest, payroll and taxes		619			606
Derivative and energy trading liabilities		2,082			1,609
Other		750			600
Total current liabilities		8,867			8,443
Long-Term Debt
Long-term debt		14,336			11,968
Junior subordinated notes payable to affiliated trusts(1)		1,440			—
Other notes payable to affiliates		—			92
Total long-term debt		15,776			12,060
Deferred Credits and Other Liabilities
Deferred income taxes		4,471			4,099
Deferred investment tax credits		92			110
Asset retirement obligations		1,651			1,538
Derivative and energy trading liabilities		1,185			690
Regulatory liabilities		587			551
Other		762			640
Total deferred credits and other liabilities		8,748			7,628
Total liabilities		33,391			28,131
Commitments and Contingencies (see Note 23)
Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts(1)		—			1,397
Subsidiary Preferred Stock Not Subject To Mandatory Redemption		257			257
Common Shareholders’ Equity
Common stock—no par(2)		10,052			9,051
Other paid-in capital		61			47
Retained earnings		1,054			1,561
Accumulated other comprehensive loss		(629	)		(446	)
Total common shareholders’ equity		10,538			10,213
Total liabilities and shareholders’ equity	$	44,186		$	39,998

(1) Junior subordinated notes issued by Dominion Resources, Inc. and certain subsidiaries constitute 100% of the trusts’ assets; trusts no longer subject to consolidation, effective December 31, 2003.

(2) 500 million shares authorized; 325 million shares and 308 million shares outstanding at December 31, 2003 and December 31, 2002, respectively.

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

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Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income

	Common Stock					Other Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Amount
(millions)
Balance at December 31, 2000	246		$	5,979		$	16		$	1,028		$	(23	)	$	7,000
Comprehensive income:
Net income										544						544
Net deferred derivative gains—hedging activities, net of $263 tax expense													465			465
Unrealized gains on investment securities, net of $10 tax expense													11			11
Foreign currency translation adjustments													(9	)		(9	)
Minimum pension liability adjustment, net of $3 tax expense													4			4
Cumulative effect of a change in accounting principle, net of $106 tax benefit													(183	)		(183	)
Amounts reclassified to net income:
Net realized gains on investment securities, net of $6 tax expense													(8	)		(8	)
Net derivative losses—hedging activities, net of $19 tax benefit													32			32
Total comprehensive income										544			312			856
Issuance of stock and stock options—Louis Dreyfus acquisition	14			894												894
Issuance of stock—employee and direct stock purchase plans	3			185												185
Stock awards and stock options exercised (net of change in unearned compensation)	2			79												79
Tax benefit from stock options exercised							12									12
Dividends and other adjustments				(8	)					(650	)					(658	)
Balance at December 31, 2001	265			7,129			28			922			289			8,368
Comprehensive income:
Net income										1,362						1,362
Net deferred losses on derivatives—hedging activities, net of $345 tax benefit													(663	)		(663	)
Unrealized losses on investment securities, net of $41 tax benefit													(68	)		(68	)
Foreign currency translation adjustments													6			6
Minimum pension liability adjustment, net of $1 tax benefit													(2	)		(2	)
Amounts reclassified to net income:
Net derivative gains—hedging activities, net of $4 tax expense													(8	)		(8	)
Total comprehensive income										1,362			(735	)		627
Issuance of stock—public offering	38			1,712												1,712
Issuance of stock—employee and direct stock purchase plans	3			199												199
Stock awards and stock options exercised (net of change in unearned compensation)	3			113												113
Stock repurchase and retirement	(1	)		(66	)											(66	)
Accrued contract payments—equity-linked securities				(36	)											(36	)
Tax benefit from stock options exercised							21									21
Dividends and other adjustments							(2	)		(723	)					(725	)
Balance at December 31, 2002	308			9,051			47			1,561			(446	)		10,213
Comprehensive income:
Net income										318						318
Net deferred derivative losses—hedging activities, net of $479 tax benefit													(791	)		(791	)
Unrealized gains on investment securities, net of $78 tax expense													112			112
Foreign currency translation adjustments													68			68
Amounts reclassified to net income:
Net realized losses on investment securities, net of $29 tax benefit													49			49
Net losses on derivatives—hedging activities, net of $225 tax benefit													379			379
Total comprehensive income										318			(183	)		135
Issuance of stock—public offering	11			683												683
Issuance of stock—employee and direct stock purchase plans	3			206												206
Stock awards and stock options exercised (net of change in unearned compensation)	3			112												112
Tax benefit from stock options exercised							14									14
Dividends and other adjustments										(825	)					(825	)
Balance at December 31, 2003	325		$	10,052		$	61		$	1,054		$	(629	)	$	10,538

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

52

Consolidated Statements of Cash Flows

Year Ended December 31,	2003			2002			2001
(millions)
Operating Activities
Net income	$	318		$	1,362		$	544
Adjustments to reconcile net income to net cash from operating activities:
Impairment of telecommunications assets		566			—			—
DCI impairment losses		85			13			281
Impairment of CNG’s international operations assets		84			—			—
Net unrealized gains on energy trading contracts		(54	)		(5	)		(140	)
Depreciation, depletion and amortization		1,334			1,379			1,322
Deferred income taxes and investment tax credits, net		452			714			201
Other adjustments for non-cash items		22			34			—
Changes in:
Accounts receivable		(531	)		(814	)		463
Inventories		(234	)		(55	)		(170	)
Deferred fuel and purchased gas costs, net		(244	)		(143	)		293
Prepaid pension cost		(229	)		(198	)		(122	)
Purchase and origination of mortgages		—			—			(1,528	)
Proceeds from sale and principal collections of mortgages		—			—			993
Accounts payable, trade		396			527			(25	)
Accrued interest, payroll and taxes		42			58			(111	)
Margin deposit assets and liabilities		(18	)		(186	)		346
Other operating assets and liabilities		366			(238	)		105
Net cash provided by operating activities		2,355			2,448			2,452
Investing Activities
Plant construction and other property additions		(2,138	)		(1,339	)		(1,224	)
Additions to gas and oil properties, including acquisitions		(1,300	)		(1,489	)		(944	)
Proceeds from sales of gas and oil properties		305			15			8
Acquisition of businesses		—			(410	)		(2,215	)
Proceeds from sales of loans and securities		912			572			788
Purchases of securities		(777	)		(462	)		(630	)
Escrow release (deposit) for debt refunding		500			(500	)		—
Purchase of Dominion Fiber Ventures senior notes		(633	)		—			—
Advances to lessor for project under construction		(385	)		(240	)		(49	)
Other		143			(107	)		24
Net cash used in investing activities		(3,373	)		(3,960	)		(4,242	)
Financing Activities
Issuance of common stock		990			2,020			245
Repurchase of common stock		—			(66	)		—
Issuance of preferred securities by subsidiary trusts		—			400			747
Repayment of preferred securities of subsidiary trusts		—			(135	)		—
Issuance of long-term debt and preferred stock		3,393			2,434			7,365
Repayment of long-term debt and preferred stock		(2,922	)		(1,904	)		(4,193	)
Issuance (repayment) of short-term debt, net		259			(666	)		(1,620	)
Common dividend payments		(825	)		(723	)		(649	)
Other		(42	)		(43	)		21
Net cash provided by financing activities		853			1,317			1,916
(Decrease) increase in cash and cash equivalents		(165	)		(195	)		126
Cash and cash equivalents at beginning of period		291			486			360
Cash and cash equivalents at end of period	$	126		$	291		$	486
Supplemental cash flow information:
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	941		$	912		$	952
Income taxes		(32	)		(8	)		284
Noncash transactions from investing and financing activities:
Exchange of debt securities		500			567			—
Stock and stock option issuance—Louis Dreyfus acquisition		—			—			894

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

53

Notes to Consolidated Financial Statements

1. Nature of Operations

Dominion Resources, Inc. (Dominion) is a holding company headquartered in Richmond, Virginia. Its principal subsidiaries are Virginia Electric and Power Company (Virginia Power), Consolidated Natural Gas Company (CNG), and Dominion Energy, Inc. (DEI). Dominion and CNG are registered public utility holding companies under the Public Utility Holding Company Act of 1935 (1935 Act).

Virginia Power is a regulated public utility that generates, transmits and distributes electricity within a 30,000-square-mile area in Virginia and northeastern North Carolina. Virginia Power sells electricity to approximately 2.2 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. Virginia Power has trading relationships beyond its retail service territory and buys and sells wholesale electricity and natural gas off-system.

CNG operates in all phases of the natural gas business. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline system serves each of its distribution subsidiaries, non-affiliated utilities and end use customers in the Midwest, Mid-Atlantic and Northeast. CNG’s exploration and production operations are located in several major natural gas and oil producing basins in the United States, both onshore and offshore. CNG also provides a variety of energy marketing services.

DEI is involved in merchant generation, energy trading and marketing and natural gas and oil exploration and production.

Dominion has substantially exited the core operating businesses of Dominion Capital, Inc. (DCI), as required by the Securities and Exchange Commission (SEC) under the 1935 Act. Currently, Dominion is required to divest all remaining DCI holdings by January 2006. DCI’s primary business was financial services, including loan administration, commercial lending and residential mortgage lending.

Dominion manages its daily operations along four primary operating segments: Dominion Generation, Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In addition, Dominion also reports the operations of DCI, its telecommunications business and its corporate and other operations as a segment. Assets remain wholly owned by its legal subsidiaries.

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.

2. Significant Accounting Policies

General

Dominion makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

The Consolidated Financial Statements represent Dominion’s accounts after the elimination of intercompany transactions. Dominion follows the equity method of accounting for investments with a 50% or less interest in partnerships and corporate joint ventures when Dominion is able to significantly influence the financial and operating policies of the investee. Dominion reports its equity earnings from these investments in other income. For all other investments, the cost method is applied.

Certain amounts in the 2002 and 2001 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2003 presentation.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion’s customer accounts receivable at December 31, 2003 and 2002 included $342 million and $334 million, respectively, of accrued unbilled revenue based on estimated amounts of electric energy or natural gas delivered but not yet billed to its utility customers. Dominion estimates unbilled utility revenue based on weather factors and, for electric customers, total daily electric generation supplied after adjusting for estimated losses of energy during transmission, taking into consideration historical usage and applicable customer rates.

The primary types of sales and service activities reported as operating revenue include:

n Regulated electric sales consist primarily of state-regulated retail electric sales and federally regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation;

n Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

n Nonregulated electric sales consist primarily of sales of electricity from utility and merchant generation facilities at market-based rates and electric trading revenue;

n Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas sales and gas trading revenue;

54

Notes to Consolidated Financial Statements, Continued

n Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;

n Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by Dominion. Gas and oil production revenue is reported net of royalties and

n Other revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations; sales of coal, brokered oil and other extracted products; gas and oil processing and gas transmission pipeline capacity release.

See Derivative Instruments below for a discussion of accounting changes, effective January 1, 2003 and October 1, 2003, that impacted the recognition and classification of changes in fair value, including settlements, of contracts held for energy trading and other purposes.

Electric Fuel, Purchased Energy and Purchased Gas—Deferred Costs

Where permitted by regulatory authorities, the differences between actual electric fuel, purchased energy and purchased gas expenses and the levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods.

Income Taxes

Dominion and its subsidiaries file a consolidated federal income tax return. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of SFAS No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are amortized over the service lives of the properties giving rise to the credits.

Dominion establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.

Dominion has not provided for U.S. deferred income taxes or foreign withholding taxes on its remaining undistributed earnings of $116 million of its non-U.S. subsidiaries since these earnings are intended to be reinvested indefinitely.

Stock-based Compensation

Dominion sponsors two stock plans that provide stock-based awards to directors, executives and other key employees. Under the plans, Dominion grants stock options and restricted stock awards that vest over periods ranging from three to five years. Options have contractual terms that range from seven to ten years. Forty million shares of common stock may be issued under the plans and approximately 12 million of these shares are available for new grants as of December 31, 2003.

Dominion measures compensation cost for stock-based awards issued to its employees in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation expense is measured based on the intrinsic value, the difference between fair market value of Dominion common stock and the exercise price of the underlying award, on the date when both the price and number of shares the recipient is entitled to receive are known, generally the grant date. Compensation expense is recognized on a straight-line basis over the stated vesting period of the award.

The following table illustrates the pro forma effect on net income and earnings per share if Dominion had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, to stock-based employee compensation:

Year Ended December 31,	2003			2002			2001
(millions)
Net income—as reported	$	318		$	1,362		$	544
Add: actual stock-based compensation expense, net of tax(1)		10			5			18
Deduct: pro forma stock-based compensation expense, net of tax		(36	)		(52	)		(49	)
Net income—pro forma	$	292		$	1,315		$	513
Basic EPS—as reported	$	1.00		$	4.85		$	2.17
Basic EPS—pro forma		0.92			4.68			2.05
Diluted EPS—as reported		1.00			4.82			2.15
Diluted EPS—pro forma		0.92			4.65			2.03

(1) Actual stock-based compensation expense reflects primarily the issuance of restricted stock. For 2001, stock-based compensation expense also includes an after-tax charge of $11 million for stock options modified in the 2001 restructuring initiative discussed in Note 6.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2003 and 2002, accounts payable included the net effect of checks outstanding but not yet presented for payment of $123 million and $101 million, respectively. For purposes of the Consolidated Statements of Cash Flows, Dominion considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Inventories

Materials and supplies and fossil fuel inventories are valued using primarily the weighted-average cost method. Stored gas inventory used in local gas distribution operations is valued using the last-in-first-out (LIFO) method. Under the LIFO method, those inventories were valued at $59 million and $52 million at December 31, 2003 and December 31, 2002, respectively.

55

Notes to Consolidated Financial Statements, Continued

Based on the average price of gas purchased during 2003, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $265 million. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted average cost method.

Derivative Instruments

Dominion uses derivative instruments such as futures, swaps, forwards and options to manage the commodity, currency exchange and financial market risks of its business operations. Dominion also manages a portfolio of commodity contracts held for trading purposes as part of its strategy to market energy and to manage related risks.

All derivatives not qualifying for the normal purchase and normal sales exception are reported on the Consolidated Balance Sheets at fair value. Commodity contracts representing unrealized gain positions and purchased options are reported as derivative and energy trading assets. Commodity contracts representing unrealized losses and options sold are reported as derivative and energy trading liabilities. For derivatives that are not designated as hedging instruments, any changes in fair value are recorded in earnings.

Valuation Methods

Fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, Dominion seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, Dominion must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.

For options and contracts with option-like characteristics where pricing information is not available from external sources, Dominion generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Other option models are used by Dominion under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, Dominion estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value.

Derivative Instruments Designated as Hedging Instruments

Dominion designates a substantial portion of derivative instruments, held for purposes other than trading, as fair value or cash flow hedges for accounting purposes. For all derivatives designated as hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument. Dominion assesses whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value of the hedged item is recognized currently in earnings. Also, in the case of options that are designated as hedging instruments, management may elect to exclude changes in time value from the measurement of hedge effectiveness, thus requiring that such changes be recorded currently in earnings. Dominion discontinues hedge accounting prospectively for derivatives that have ceased to be highly effective hedges.

Cash Flow Hedges—A significant portion of Dominion’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas, oil and other commodities. Dominion also uses foreign currency forward contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge variable interest rates on long-term debt. For cash flow hedge transactions in which Dominion is hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (AOCI) until earnings are affected by the hedged item.

Fair Value Hedges—Dominion also engages in fair value hedges by using derivative instruments to mitigate the fixed price exposure inherent in firm commodity commitments and certain natural gas inventory. In addition, Dominion has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt. For fair value hedge transactions, changes in the fair value of the derivative will generally be offset currently in earnings by changes in the hedged item’s fair value.

Statement of Income Presentation—Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in the Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and any gains or losses attributable to the changes in the time value of options, excluded from the measurement of effectiveness, are included in other operations and maintenance expense.

56

Notes to Consolidated Financial Statements, Continued

Derivative Instruments Held for Trading and Other Purposes

As part of its strategy to market energy and to manage related risks, Dominion manages a portfolio of commodity-based derivative instruments held for trading purposes, primarily natural gas and electricity. Dominion uses established policies and procedures to manage the risks associated with the price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

Certain derivative instruments are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent Dominion does not hold offsetting positions for such derivatives, management believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.

Statement of Income Presentation:

n Derivatives Held for Trading Purposes: All changes in fair value, including amounts realized upon settlement, are presented in revenue on a net basis as nonregulated electric sales, nonregulated gas sales and other revenue.

n Financially-Settled Derivatives—Not Held for Trading Purposes or Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in other operations and maintenance expense on a net basis.

n Physically-Settled Derivatives—Not Held for Trading Purposes or Designated as Hedging Instruments: Effective October 1, 2003, all statement of income related

amounts for physically settled derivative sales contracts are presented in revenue, while all statement of income related amounts for physically settled derivative purchase contracts are reported in expenses. For the nine months ended September 30, 2003, unrealized changes in fair value for physically settled derivative contracts are presented in other operations and maintenance expense on a net basis.

Non-derivative energy-related contracts are no longer subject to fair value accounting, effective January 1, 2003. Dominion recognizes revenue or expense on a gross basis at the time of contract performance, settlement or termination. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value reported in revenue on a net basis.

Investment Securities

Dominion accounts for and classifies investments in marketable equity and debt securities in two categories. Debt and equity securities purchased and held with the intent of selling them in the near term are classified as trading securities. Trading securities are reported at fair value with net realized and unrealized gains and losses included in earnings. All other debt and equity securities are classified as available-for-sale securities. These are reported at fair value with realized gains and losses included in earnings and unrealized gains and losses reported as a component of accumulated other comprehensive income, net of tax.

Dominion analyzes all securities classified as available-for-sale to determine whether a decline in its fair value should be considered other-than-temporary. Dominion uses several criteria to evaluate other-than-temporary declines including length of time over which the market value has been lower than its cost, the percentage of the decline as compared to its average cost and the expected fair value of the security. If the market value of the security has been less than cost for greater than nine months and the decline in value is greater than 50% of its average cost, the security is written down to its expected recovery value. If only one of the above criteria is met, a further analysis is performed to evaluate the expected recovery value based on third party price targets. If the third party price quotes are below the security’s average cost and one of the other criteria has been met, the decline is considered other-than-temporary and the security is written down to its expected recovery value.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, other direct costs and capitalized interest. The costs of repairs and maintenance, including minor additions and replacements, are charged to expense as incurred. In 2003, 2002 and 2001, Dominion capitalized interest costs of $96 million, $95 million and $41 million, respectively.

For electric and gas distribution and transmission property subject to cost-of-service utility rate regulation, the cost of such property, less salvage, is charged to accumulated depreciation at retirement. Amounts related to cost of removal collections and expenditures are recorded as regulatory liabilities or regulatory assets.

For generation-related property, cost of removal not associated with asset retirement obligations is charged to expense as incurred. Dominion records gains and losses upon retirement of generation-related property based upon the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.

57

Notes to Consolidated Financial Statements, Continued

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s depreciation rates on property, plant and equipment are as follows:

	2003	2002	2001
(percent)
Generation	1.95	2.34	2.78
Transmission	2.22	2.26	2.58
Distribution	3.18	3.27	3.43
Storage	2.81	2.47	2.57
Gas gathering and processing	2.39	2.31	2.19
General and other	5.67	5.74	4.94

Amortization of nuclear fuel used in electric generation is provided on a units-of-production basis sufficient to fully amortize, over the estimated service life, the cost of the fuel plus permanent storage and disposal costs.

In 2002, Dominion extended the estimated useful lives of most of its fossil fuel power stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. In 2001, Dominion increased the estimate of the useful lives of its nuclear property by 20 years in connection with license extensions already received from the Nuclear Regulatory Commission (NRC) and current filings of applications for other units. The changes reduced depreciation expense as follows:

	2003		2002		2001
(millions)
Nuclear	$	94	$	94	$	78
Fossil fuel, electric transmission and distribution		68		42		—

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. These capitalized costs are subject to a quarterly “ceiling test.” Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end hedge-adjusted prices. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-country basis. Approximately 14% of Dominion’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2003.

Depreciation of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depreciable base of costs subject to amortization also 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 costs of investments in unproved properties 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. See Asset Retirement Obligations for a discussion of gas and oil abandonment and dismantlement costs.

Goodwill and Intangible Assets

Goodwill is subject to review for impairment rather than periodic amortization. Dominion evaluates goodwill for impairment at least annually and whenever an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. Prior to the adoption of SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002, goodwill arising from acquisitions completed before July 1, 2001 was amortized on a straight-line basis over periods up to 40 years.

Impairment of Long-Lived and Intangible Assets

Dominion performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amounts.

Regulatory Assets and Liabilities

For utility operations subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by non-regulated companies. The economic effects of practices prescribed by regulatory authorities for rate-making purposes must be considered in the application of generally accepted accounting principles.

Asset Retirement Obligations

Beginning in 2003, Dominion recognizes its asset retirement obligations at fair value as incurred, capitalizing these amounts as costs of the related tangible long-lived assets. Due to the absence of relevant market information, fair value is estimated using discounted cash flow analyses. Dominion reports the accretion of the liabilities due to the passage of time as an

58

Notes to Consolidated Financial Statements, Continued

operating expense. In addition, beginning in 2003, Dominion classifies all investments held by its decommissioning trusts as available-for-sale, and recognizes realized and unrealized gains and losses in other income (loss) and other comprehensive income (loss), as appropriate.

Nuclear Decommissioning—2002 and 2001

Utility Nuclear Plants—In accordance with the accounting policy recognized by regulatory authorities having jurisdiction over its electric utility operations, Dominion recognized an expense for the future cost of decommissioning in amounts equal to amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of Dominion’s utility nuclear plants. The trust investments were reported at fair value with the accumulated provision for decommissioning reported as a liability. Net realized and unrealized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommissioning, was recorded as a component of other income (loss).

Merchant Nuclear Plant—Dominion recognized, as a liability on the Consolidated Balance Sheet, an obligation to decommission its merchant nuclear plant. The obligation was based upon its estimated fair value, using discounted cash flows of expected costs to perform the decommissioning activities. Accretion of the obligation was reported as depreciation expense. The external trusts were accounted for as available-for-sale investments with realized and unrealized earnings recognized in other income and other comprehensive income, as appropriate.

Gas and Oil Dismantlement and Abandonment Costs—2002 and 2001

Through 2002, Dominion’s accounting and reporting practices for future dismantlement and restoration activities for its gas and oil wells and platforms recognized such costs as a component of depletion expense and included them in accumulated depreciation, depletion and amortization.

Amortization of Debt Issuance Costs

Dominion defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and amortized over the lives of the new issues.

3. Newly Adopted Accounting Standards

2003

SFAS No. 143

Effective January 1, 2003, Dominion adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The effect of adopting SFAS No. 143 for 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $201 million. The increase is comprised of a $180 million after-tax gain, representing the cumulative effect

of a change in accounting principle and an increase in income before the cumulative effect of a change in accounting principle of $21 million.

EITF 02-3

On January 1, 2003, Dominion adopted 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, that rescinded EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Adopting EITF 02-3 resulted in the discontinuance of fair value accounting for non-derivative contracts held for trading purposes. Those contracts are recognized as revenue or expense at the time of contract performance, settlement or termination. The EITF 98-10 rescission was effective for non-derivative energy trading contracts initiated after October 25, 2002. For all non-derivative energy trading contracts initiated prior to October 25, 2002, Dominion recognized a loss of $67 million (after taxes of $43 million) as the cumulative effect of this change in accounting principle on January 1, 2003.

EITF 03-11

Dominion adopted EITF Issue No. 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, on October 1, 2003. EITF 03-11 addresses classification of income statement related amounts for derivative contracts. Income statement amounts related to periods prior to October 1, 2003 are presented as originally reported. See Note 2.

Statement 133 Implementation Issue No. C20

In connection with a request to reconsider an interpretation of SFAS No. 133, FASB issued Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. Issue C20 establishes criteria

59

Notes to Consolidated Financial Statements, Continued

for determining whether a contract’s pricing terms that contain broad market indices (e.g., the consumer price index) could qualify as a normal purchase or sale and, therefore, not be subject to fair value accounting. Dominion has several contracts that qualify as normal purchase and sales contracts under the Issue C20 guidance. However, the adoption of Issue C20 required the contracts to be initially recorded at fair value as of October 1, 2003, and the recognition of an after-tax charge of $75 million, representing the cumulative effect of the change in accounting principle. As normal purchase and sales contracts, no further changes in fair value will be recognized.

SFAS No. 149

Dominion adopted SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 reflects decisions made by FASB and its Derivatives Implementation Group in connection with issues raised about the application of SFAS No. 133. Generally, changes resulting from SFAS No. 149 apply to contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The initial adoption of SFAS 149 did not have a material impact on Dominion’s results of operations and financial position.

FIN 46R

On December 31, 2003, Dominion adopted FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in special purpose entities. FIN 46R addresses the consolidation of variable interest entities (VIEs), which are entities that are not controllable through voting interests or in which the VIEs’ equity investors do not bear the residual economic risks and rewards.

Under FIN 46R, Dominion consolidated several special purpose lessor entities through which Dominion had constructed, 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. The cumulative effect of adopting FIN 46R for its interests in special purpose entities was an after-tax charge of $27 million, representing depreciation expense and amortization associated with the consolidated assets. Annual depreciation expense for these assets is expected to be approximately $31 million.

From 1997 through 2002, Dominion established five capital trusts that sold trust preferred securities to third party investors. Dominion received the proceeds from the sale of the trust preferred securities in exchange for various junior subordinated notes issued by Dominion to be held by the trusts. Upon adoption of FIN 46R, Dominion’s Consolidated Balance Sheet at December 31, 2003 reports the junior subordinated notes held by the trusts as long-term debt, rather than the trust preferred securities.

Dominion is required to adopt FIN 46R for its interests in VIEs that are not considered special purpose entities no later than March 31, 2004. Dominion is still evaluating the impact that adopting FIN 46R for these interests may have on its future results of operations or financial condition.

FIN 45

In November 2002, FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—An Interpretation of FASB Statements No. 5, 57 and 107 (FIN 45). Under FIN 45, issuers of certain types of guarantees must recognize a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. In addition, FIN 45 requires increased disclosures for specific types of guarantees.

FIN 45’s initial recognition requirements apply only to guarantees issued or modified after December 31, 2002. Dominion does not anticipate any material impact on its future results of operations or financial condition as a result of recording newly issued or modified guarantees at fair value.

2002 and 2001

SFAS No. 142

Dominion adopted SFAS No. 142 on January 1, 2002. The discontinuance of goodwill amortization under SFAS No. 142 resulted in an increase in net income of $95 million in 2002.

SFAS No. 133

Dominion adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, on January 1, 2001 and recorded an after-tax charge to accumulated other comprehensive income of $183 million, net of taxes of $106 million.

Pro Forma Information Reflecting Adoption of New Standards

Disclosure requirements associated with the adoption of FIN 46R, SFAS Nos. 143 and 142, require a presentation of pro forma net income and earnings per share for 2002 and 2001 as if Dominion had applied the provisions of those standards as of January 1, 2001. Other standards adopted during 2003 do not require pro forma information and are excluded from the amounts presented below.

	Amount		Basic EPS		Diluted EPS
(in millions, except per share amounts)
2002
Reported net income	$	1,362	$	4.85	$	4.82
Adjusted net income		1,363		4.85		4.82
2001
Reported net income		544		2.17		2.15
Adjusted net income		658		2.63		2.60

60

Notes to Consolidated Financial Statements, Continued

SFAS No. 143 also requires a pro forma presentation of asset retirement obligations as if Dominion had applied the provisions of SFAS No. 143 as of January 1, 2001. Those amounts are as follows:

	2001		2002
(millions)
Pro forma asset retirement obligations at January 1,	$	810	$	1,447
Pro forma asset retirement obligations at December 31,	$	1,447	$	1,543

4. Acquisitions

Cove Point LNG Limited Partnership

In September 2002, Dominion acquired 100% ownership of Cove Point LNG Limited Partnership (Cove Point), a cost-based rate-regulated entity, from a subsidiary of The Williams Companies for $225 million in cash. Dominion recorded $75 million of goodwill representing the excess of the purchase price over the regulatory basis of Cove Point’s assets acquired and liabilities assumed. Cove Point’s assets include a liquefied natural gas import facility located near Baltimore, Maryland, a liquefied natural gas storage facility and an approximately 85-mile natural gas pipeline. Cove Point became fully operational in 2003. Cove Point is included in the Dominion Energy operating segment and the goodwill arising from the acquisition was allocated to that segment for purposes of impairment testing under SFAS No. 142.

Mirant State Line Ventures, Inc.

In June 2002, Dominion acquired 100% ownership of Mirant State Line Ventures, Inc. (State Line) from a subsidiary of Mirant Corporation for $185 million in cash. State Line’s assets include a 515-megawatt coal-fired generation facility located near Hammond, Indiana. Its operations are included in the Dominion Generation operating segment.

Louis Dreyfus Natural Gas Corp.

In November 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. The aggregate purchase price was $1.8 billion, which consisted of approximately 14 million shares of Dominion common stock valued at $881 million, $902 million in cash and employee stock options with a fair value on the date of grant of approximately $13 million. Dominion recorded $543 million of goodwill, representing the excess of purchase price over the fair value of the Louis Dreyfus assets acquired and liabilities assumed. The operations of Louis Dreyfus are included in the Dominion Exploration & Production operating segment. All of the goodwill arising from the acquisition was allocated to that segment for purposes of impairment testing under SFAS No. 142.

Millstone Power Station

In March 2001, Dominion acquired Millstone Power Station (Millstone), a nuclear power station located in Waterford, Connecticut. The aggregate purchase price was $1.3 billion in cash, consisting of approximately $1.2 billion for plant assets and $105 million for nuclear fuel. Dominion recorded $302 million of goodwill representing the excess of the purchase price over amounts allocated to Millstone’s assets acquired and liabilities assumed. The operations of Millstone are included in the Dominion Generation operating segment and all of the goodwill arising from the acquisition has been allocated to that segment for purposes of impairment testing under SFAS No. 142.

5. Operating Revenue

	2003		2002		2001
Year Ended December 31,
(millions)
Regulated electric sales	$	4,876	$	4,856	$	4,619
Regulated gas sales		1,258		876		1,409
Nonregulated electric sales		1,130		1,017		1,022
Nonregulated gas sales		1,718		778		1,073
Gas transportation and storage		740		705		702
Gas and oil production		1,503		1,334		1,057
Other		853		652		676
Total operating revenue	$	12,078	$	10,218	$	10,558

6. Restructuring Activities

In 2001, after fully integrating CNG’s organization and operations with those of Dominion, management initiated a focused review of Dominion’s combined operations. As a result, Dominion recognized the following restructuring costs and related liabilities during 2001:

	Amount
(millions)
Severance and related costs	$	42
Nonqualified plan benefits, settlement and other costs		46
Lease termination and restructuring		13
Other		4
Total restructuring costs	$	105

61

Notes to Consolidated Financial Statements, Continued

The change in the liabilities for severance and related costs and lease termination costs during 2003 and 2002 are presented below:

	Severance Liability			Lease Liabilities
(millions)
Balance at December 31, 2001	$	42		$	10
Amounts paid		(24	)		(1	)
Revision of estimate		(8	)		—
Balance at December 31, 2002		10			9
Amounts paid		(9	)		(3	)
Balance at December 31, 2003	$	1		$	6

7. Income Taxes

Income from continuing operations before provision for income taxes (pre-tax income), classified by source of income, and the details of income tax expense were as follows:

	2003			2002			2001
Year Ended December 31,
(millions)
Income before provision for taxes:
U.S.	$	1,506		$	2,018		$	816
Non-U.S.		40			25			98
Total		1,546		$	2,043		$	914
Income tax expense:
Current
Federal		121			(46	)		104
State		22			13			62
Non-U.S.		1						3
Total current		144			(33	)		169
Deferred
Federal		433			654			151
State		32			65			24
Non-U.S.		6			13			45
Total deferred		471			732			220
Amortization of deferred investment tax credits—net		(18	)		(18	)		(19	)
Total income tax expense	$	597		$	681		$	370

The statutory U.S. federal income tax rate reconciles to the effective income tax rates as follows:

Year Ended December 31,	2003(1)		2002(2)		2001
U.S. statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Valuation allowance	4.0		—		—
State taxes, net of federal benefit	2.2		2.5		5.9
Utility plant differences	(0.4	)	(0.1	)	0.5
Preferred dividends	0.4		0.3		0.9
Amortization of investment tax credits	(0.9	)	(0.7	)	(1.7	)
Nonconventional fuel credit	—		(1.8	)	(4.6	)
Other benefits and taxes related to foreign operations	(0.5	)	0.2		3.0
Goodwill amortization	—		—		3.3
Employee pension and other benefits	(0.7	)	(0.6	)	(1.4	)
Employee stock ownership plan deduction	(0.7	)	(0.8	)	—
Other, net	0.2		(0.7	)	(0.5	)
Effective tax rate	38.6	%	33.3	%	40.4	%

(1) Dominion’s effective tax rate increased in 2003, reflecting the effects of the expiration of nonconventional fuel tax credits, an increase in valuation allowances related to federal loss carryforwards at CNG International and DCI that are not expected to be utilized and an impairment of goodwill associated with the telecommunications investment, partially offset by a reduction in Canadian tax rates applied to deferred tax balances.

(2) Dominion’s effective income tax rate decreased in 2002, reflecting the effect of including certain subsidiaries in Dominion’s consolidated state income tax returns. In addition, the effective tax rate decreased for foreign earnings, the impact of discontinuing goodwill amortization for book purposes and other factors.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Dominion’s net deferred income taxes consist of the following:

At December 31,	2003			2002
(millions)
Deferred income tax assets:
Other comprehensive income	$	397		$	246
Deferred investment tax credits		31			37
Loss and credit carryforwards		424			204
Valuation allowance		(338	)		(8	)
Other		—			18
Total deferred income tax assets		514			497
Deferred income tax liabilities:
Depreciation method and plant basis differences		2,085			1,833
Income taxes recoverable through future rates		16			15
Partnership basis differences		485			352
Investee earnings reported in different tax periods		208			149
Postretirement and pension benefits		604			517
Intangible drilling costs		833			777
Geological, geophysical and other exploration differences		220			196
Deferred state income taxes		432			347
Other		5			321
Total deferred income tax liabilities		4,888			4,507
Total net deferred income tax liabilities(1)	$	4,374		$	4,010

⁽¹⁾ At 2003 and 2002, total net deferred income tax liabilities include $97 million and $89 million, respectively, of current deferred tax assets included in other current assets on the Consolidated Balance Sheets.

62

Notes to Consolidated Financial Statements, Continued

At December 31, 2003, Dominion had the following loss and credit carryforwards:

• Federal loss carryforwards of $499 million that expire if unutilized during 2004 through 2007. A valuation allowance on $251 million has been established due to the uncertainty of realizing the future deductions;

• State net operating loss carryforwards of $1.3 billion that expire if unutilized during 2008 through 2022. A valuation allowance on $446 million has been established for these carryforwards; and

• Federal minimum tax credits of $113 million that do not expire and other federal and state income tax credits of $54 million that will expire if unutilized during 2006 through 2009.

8. Hedge Accounting Activities

Dominion is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as well as currency exchange and financial market risks of its business operations. Dominion uses derivative instruments to mitigate its exposure to these risks and designates derivative instruments as fair value or cash flow hedges for accounting purposes. Selected information about Dominion’s hedge accounting activities follows:

	2003			2002			2001
(millions)
Portion of pre-tax gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$	(3	)	$	2		$	(1	)
Cash flow hedges		7			(31	)		3
Net ineffectiveness	$	4		$	(29	)	$	2
For options used as hedging instruments, change in options’ time value excluded from measurement of effectiveness and included in net income:
Fair value hedges	$	1		$	(1	)		—
Cash flow hedges		7			(1	)		(47	)
Total change in options’ time value	$	8		$	(2	)	$	(47	)

The following table presents selected information related to cash flow hedges included in AOCI in the Consolidated Balance Sheet at December 31, 2003:

	Accumulated Other Comprehensive Income (Loss) After Tax			Portion Expected to be Reclassified to Earnings during the Next 12 Months			Maximum Term
(millions)
Commodities:
Gas	$	(590	)	$	(257	)	50 months
Oil		(82	)		(40	)	36 months
Electricity		(107	)		(66	)	48 months
Interest Rate		(25	)		—		270 months
Foreign Currency		36			4		47 months
Total	$	(768	)	$	(359	)

The actual amounts that will be reclassified to earnings in 2004 will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

In connection with the December 2, 2001 Enron bankruptcy filing, Dominion’s Enron derivatives designated as cash flow hedges of anticipated purchases and sales of natural gas no longer qualified for hedge accounting and, accordingly, were de-designated from their hedging relationships for accounting purposes.

9. Discontinued Operations—Telecommunications Operations

Dominion Fiber Ventures, LLC (DFV) is a joint venture originally formed by Dominion and a third-party investor trust (Investor Trust) to fund the development of its principal subsidiary, Dominion Telecom, Inc. (DTI). DTI is a facilities-based interchange and emerging local carrier, providing

broadband solutions to wholesale customers throughout the eastern United States. In connection with its formation, DFV issued $665 million of 7.05% senior secured notes due March 2005 which were secured in part by Dominion convertible preferred stock held in trust. Dominion is the beneficial owner of the trust and thus does not present the convertible preferred stock in its Consolidated Balance Sheets. Also, as described below, Dominion acquired substantially all of DFV’s senior notes in early 2003, reducing the likelihood that the remarketing of the Dominion convertible preferred stock held in trust would ever occur.

63

Notes to Consolidated Financial Statements, Continued

At inception, Dominion’s strategy for DTI was to focus primarily on delivering lit capacity, dark fiber and collocation services to under-served markets. With the markets for these services not growing at rates originally contemplated and the continuing downward pressure on prices, resulting from excess capacity in the telecommunications industry, Dominion reconsidered its investment strategy during 2003. Reflecting a revision in long-term expectations for potential growth in telecommunications service revenue, Dominion approved a strategy to sell its interest in the telecommunications business and does not expect to have any significant participation in the business once sold. Dominion has engaged outside parties to assist in marketing DTI and expects a sale to occur in 2004.

As a result, DTI’s assets (network assets and inventories) and liabilities, both totaling $13 million are classified as held-for-sale, and are included in other current assets and liabilities on the Consolidated Balance Sheet as of December 31, 2003. DTI’s results of operations, including revenue of $11 million, operating expenses of $638 million and income tax expense of $15 million, are presented as discontinued operations, on a net basis, on the Consolidated Statement of Income for 2003. Dominion has guarantees related to DTI in the amount of $17 million. In addition, bidders may choose not to acquire all of the operating leases of DTI which may ultimately be abandoned.

2003—Asset Impairments

The change in strategy in 2003 included a review of DTI’s network assets and related inventories for impairment. As a result, Dominion recognized a $566 million impairment of network assets and related inventories, reflecting the excess of the assets carrying amount over their estimated fair values. This amount included the allocation of $16 million to the Investor Trust, representing its minority interest share of these charges. Management determined the estimated fair values with the assistance of an independent appraiser and subsequently updated the fair values based on preliminary bids received in connection with the sale of DTI.

Since realization of tax benefits related to the impairment charges will be dependent upon Dominion’s future tax profile and taxable earnings, management established a valuation allowance that completely offsets the deferred tax benefits. In addition, Dominion increased the valuation allowance on deferred tax assets previously recognized, resulting in a $48 million increase in deferred income tax expense.

2003-Additional Investments in DFV

The DFV senior notes contained certain stock price and credit downgrade triggers that could have resulted in the issuance of the convertible preferred stock held in trust. In the first quarter of 2003, Dominion purchased $633 million of DFV senior notes and, in connection with the purchase, obtained consent to remove the triggers from the indenture. Dominion paid a total of $664 million for the notes acquired and recognized a pre-tax charge of $57 million, reported in other expenses on the Consolidated Statement of Income. The charge consisted of the premium paid to acquire the notes, the consent fee paid to the note holders and the recognition of previously unamortized debt costs. After the transaction, Dominion owned a total of $644 million of DFV senior notes with the remaining $21 million of outstanding notes held by third parties.

Dominion began consolidating the results of DFV in its Consolidated Financial Statements in February 2003, as a result of acquiring substantially all of DFV’s outstanding senior notes. Prior to this acquisition, Dominion accounted for DFV as an equity-method investment, due to the Investor Trust’s equity investment and veto rights.

In the fourth quarter of 2003, Dominion purchased the Investor Trust’s interest in DFV for $62 million, including $2 million for accrued dividends. This transaction was accounted for as a purchase of a minority interest and $60 million was recognized as goodwill and impaired. The purchase enabled Dominion to proceed with its strategy to sell DTI and, accordingly, classify the business as discontinued operations as of December 31, 2003.

2003—Other

Also early in 2003, Dominion recognized a $27 million charge for the reallocation of DFV’s equity losses between the Investor Trust and Dominion. Based on updated projections of DFV’s expected net losses, Dominion and the Investor Trust revised the allocation of equity losses, using cash allocations and liquidation provisions of the underlying limited liability company agreement rather than voting interests.

2002 and 2001 Transactions

For periods in which DFV was accounted for under the equity method, Dominion’s Consolidated Financial Statements reflected the following transactions between Dominion and DFV and DTI:

n Loans from DTI and DFV to Dominion of $140 million at December 31, 2002;

n Equity losses of $32 million and $3 million for 2002 and 2001, respectively;

n Interest expense on the affiliated loans of $13 million and $23 million for 2002 and 2001, respectively; and

n Management and other support services billed by Dominion to DTI of $35 million and $20 million in 2002 and 2001, respectively.

64

Notes to Consolidated Financial Statements, Continued

10. Earnings Per Share

The following table presents Dominion’s basic and diluted earnings per share (EPS) calculation:

Year Ended December 31,	2003			2002		2001
(millions, except per share amounts)
Income from continuing operations before cumulative effect of changes in accounting principles	$	949		$	1,362	$	544
Loss from discontinued operations		(642	)		—		—
Cumulative effect of changes in accounting principles		11			—		—
Net income	$	318		$	1,362	$	544
Basic EPS
Average shares of common stock outstanding—basic		317.5			281.0		250.2
Income from continuing operations before cumulative effect of changes in accounting principle	$	2.99		$	4.85	$	2.17
Loss from discontinued operations		(2.02	)		—		—
Cumulative effect of changes in accounting principles		.03			—		—
Net income	$	1.00		$	4.85	$	2.17
Diluted EPS
Average shares of common stock outstanding		317.5			281.0		250.2
Net effect of dilutive stock options(1)		1.3			1.6		2.3
Average shares of common stock outstanding—diluted		318.8			282.6		252.5
Income from continuing operations before cumulative effect of changes in accounting principles	$	2.98		$	4.82	$	2.15
Loss from discontinued operations		(2.01	)		—		—
Cumulative effect of changes in accounting principles		.03			—		—
Net income	$	1.00		$	4.82	$	2.15
Average anti-dilutive shares excluded from the EPS calculation		9.5			11.0		3.0

(1) Represents the effect of “in-the-money” stock options on the calculation of average outstanding shares of common stock.

11. Available-For-Sale and Other Investment Securities

Dominion holds marketable debt and equity securities in nuclear decommissioning trust funds and retained interests from prior securitizations of financial assets. These investments are classified as available-for-sale. As described below, prior to adopting SFAS No. 143, Dominion did not record unrealized gains and losses in AOCI for investments held for decommissioning its utility nuclear plants; those investments are not presented in the tables below for 2002 or 2001.

Available-for-sale securities as of December 31, 2003 and 2002 are summarized below:

	Fair Value		Total Unrealized Gains Included in AOCI		Total Unrealized Losses Included in AOCI
(millions)
2003
Equity securities	$	1,092	$	157	$	9
Debt securities		1,102		22		12
Total		2,194		179		21
2002
Equity securities		489		1		118
Debt securities		758		14		14
Total	$	1,247	$	15	$	132

The following table presents the fair value and gross unrealized losses of Dominion’s available-for-sale securities, aggregated by investment category and the length of time the securities have been in a continuous loss position, at December 31, 2003:

	Equity Securities				Debt Securities
	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
(millions)
Less than 12 months	$	54	$	4	$	52	$	2
12 months or more		60		5		55		10
Total	$	114	$	9	$	107	$	12

65

Notes to Consolidated Financial Statements, Continued

Debt securities backed by mortgages and loans do not have stated contractual maturities as borrowers have the right to call or repay obligations with or without call or prepayment penalties. At December 31, 2003, these debt securities totaled $413 million. The fair value of all other debt securities at December 31, 2003 by contractual maturity are as follows:

	Amount
(millions)
Due in one year or less	$	6
Due after one year through five years		245
Due after five years through ten years		262
Due after ten years		176
Total	$	689

Presented below is selected information regarding the sales of investment securities. In determining realized gains and losses, the cost of these securities was determined on a specific identification basis.

	2003(1)		2002			2001
(millions)
Available-for-sale securities:
Proceeds from sales	$	832	$	506		$	484
Realized gains		62		58			18
Realized losses		102		58			4
Trading securities:
Net unrealized gain (loss)(2)		12		(10	)		21

(1) Beginning in 2003, after adopting SFAS No. 143, Dominion accounts for its utility decommissioning trust investments as available-for-sale.

(2) For 2002, $5 million of net realized and unrealized pre-tax losses related to retained interests were reported in earnings. Effective May 1, 2002, Dominion reclassified its retained interests from trading to available-for-sale based on a determination that the retained interests were not readily marketable on terms that would be acceptable to Dominion.

Decommissioning Trust Investments—Utility Plants 2002 and 2001

Prior to adopting SFAS No. 143, Dominion recognized an expense for the future cost of decommissioning its utility nuclear plants in amounts equal to amounts collected from ratepayers and earnings on trust investments dedicated to funding the decommissioning of those plants. The trusts were reported at fair value with realized and unrealized earnings on the trust investments, as well as an offsetting expense to increase the accumulated provision for decommissioning, recorded as a component of other income (loss). At December 31, 2002, the balance of investments held in these trusts was $838 million. Dominion recognized net realized gains and interest income of $11 million for 2002 and $32 million for 2001, and recognized net unrealized losses of $67 million for 2002 and $61 million for 2001.

12. Property, Plant and Equipment

Major classes of property, plant and equipment and their respective balances are:

At December 31,	2003		2002
(millions)
Utility
Generation	$	9,780	$	8,497
Transmission		3,308		3,283
Distribution		7,713		7,347
Storage		999		781
Nuclear fuel		757		740
Gas gathering and processing		416		341
General		795		830
Plant under construction		698		972
Total utility		24,466		22,791
Nonutility
Exploration and production properties:
Proved		7,561		6,265
Unproved		1,721		1,440
Merchant generation properties—nuclear		929		921
Nuclear fuel		175		146
Merchant generation properties—other		1,214		629
Other—including plant under construction		1,041		439
Total nonutility		12,641		9,840
Total property, plant and equipment	$	37,107	$	32,631

Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2003, and the years in which such excluded costs were incurred, follow:

	Total		2003		2002		2001		Years Prior
(millions)
Property acquisition costs	$	863	$	84	$	84	$	645	$	50
Exploration costs		171		76		43		32		20
Capitalized interest		120		53		52		8		7
Total	$	1,154	$	213	$	179	$	685	$	77

Amortization rates for capitalized costs under the full cost method of accounting for Dominion’s United States and Canadian cost centers were as follows:

Year Ended December 31,	2003		2002		2001
(Per Mcf Equivalent)
United States cost center	$	1.20	$	1.13	$	1.13
Canadian cost center		1.00		0.85		0.78

66

Notes to Consolidated Financial Statements, Continued

Volumetric Production Payment Transaction

In 2003, Dominion received $266 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period August 2003 through August 2007. The sale reduced Dominion’s natural gas reserves by approximately 66 billion cubic feet (bcf). While Dominion is obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and rights to future development drilling. If production from the properties is inadequate to deliver approximately 66 bcf of natural gas scheduled for delivery to the purchaser, Dominion has no obligation to make up the shortfall. Cash proceeds received from this volumetric production payment transaction were recorded as deferred revenue. Dominion will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser.

Classification of Mineral Rights

Companies with gas and oil exploration and production operations have become aware that a question has arisen about whether contractual mineral rights should be classified as intangible assets rather than tangible assets on the balance sheet as a result of SFAS Nos. 141, Business Combinations, and 142. If, as a result of the resolution of this issue, reclassification of the costs associated with its mineral rights is required, Dominion’s net intangible assets would increase and its net property, plant and equipment would decrease. As of December 31, 2003, the amount subject to reclassification was approximately $4.2 billion. While resolution of this issue may affect the balance sheet classification of these assets, there would be no impact on Dominion’s results of operations or cash flows.

Jointly-Owned Utility Plants

Dominion’s proportionate share of jointly-owned utility plants at December 31, 2003 follows:

	Bath County Pumped Storage Station			North Anna Power Station			Clover Power Station
(millions, except percentages)
Ownership interest		60.0	%		88.4	%		50.0	%
Plant in service	$	1,019		$	2,064		$	546
Accumulated depreciation		360			864			103
Nuclear fuel					348
Accumulated amortization of nuclear fuel					286
Construction work in progress		17			28			1

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly owned facilities in the same proportion as their respective ownership interest. Dominion reports its share of operating costs in the appropriate operating expense (fuel, other operations and maintenance, depreciation, and other taxes, etc.) in the Consolidated Statements of Income.

67

Notes to Consolidated Financial Statements, Continued

13. Goodwill and Intangible Assets

The changes in the carrying amount of goodwill during 2003 are presented below:

	Dominion Generation		Dominion Energy			Dominion Delivery			Dominion E&P		Corporate and Other			Total
(millions)
Balance at December 31, 2002	$	1,472	$	585		$	1,344		$	879	$	21		$	4,301
Acquisition of controlling interest in previously unconsolidated telecom and DCI businesses		—		—			—			—		87			87
Telecom impairment loss		—		—			—			—		(60	)		(60	)
DCI impairment losses		—		—			—			—		(18	)		(18	)
Purchase accounting adjustments		—		2			—			—		(12	)		(10	)
Reallocation of goodwill due to transfer of electric transmission operations from Dominion Delivery to Dominion Energy		—		168			(168	)		—		—			—
Reallocation of goodwill due to transfer of Dominion Retail operations from Dominion Energy to Dominion Delivery		—		(7	)		7			—		—			—
Balance at December 31, 2003	$	1,472	$	748		$	1,183		$	879	$	18		$	4,300

Goodwill Impairments

In 2003, Dominion recorded goodwill impairment charges of $18 million related to the DCI reporting unit. During 2003, a DCI subsidiary received an unfavorable arbitration ruling that resulted in lower margins for services provided. Another DCI subsidiary experienced delays in expanding marketing and stabilizing production efforts. As a result of these unfavorable developments, Dominion performed goodwill impairment tests, using discounted cash flow analyses, which indicated that the goodwill associated with those entities was impaired.

Also in 2003, as described in Note 9, Dominion purchased the remaining equity interest in DFV for $62 million, including $2 million for accrued dividends. This transaction was accounted for as a purchase of a minority interest and $60 million was recognized as goodwill and immediately impaired. The purchase enabled Dominion to proceed with its strategy to sell DTI.

In 2002, Dominion recorded a goodwill impairment charge of $13 million related to a DCI subsidiary that received an unfavorable arbitration ruling that affected its ability to recover disputed amounts for past and future performance under a contract with a major customer. Dominion performed a goodwill impairment test, using discounted cash flow analysis, which indicated that the goodwill was impaired.

Other Intangible Assets

All of Dominion’s intangible assets, other than goodwill, are subject to amortization. Amortization expense for intangible assets was $54 million, $53 million and $44 million for 2003, 2002 and 2001, respectively. There were no material acquisitions of intangible assets during 2003 and 2002. Intangible assets are included in other assets on the Consolidated Balance Sheets. The components of intangible assets at December 31, 2003 and 2002 were as follows:

	2003				2002
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Software and software licenses	$	543	$	237	$	464	$	200
Other		73		23		68		19
Total	$	616	$	260	$	532	$	219

Annual amortization expense for intangible assets is estimated to be $54 million for 2004, $49 million for 2005, $43 million for 2006, $36 million for 2007 and $24 million for 2008.

68

Notes to Consolidated Financial Statements, Continued

14. Regulatory Assets and Liabilities

Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process or amounts that have been collected from customers and not yet expended.

Dominion’s regulatory assets and liabilities include the following at December 31, 2003 and 2002:

At December 31,	2003		2002
(millions)
Unrecovered gas costs	$	55	$	32
Regulatory assets:
Other postretirement benefit costs(1)		102		106
Income taxes recoverable through future rates(2)		227		203
Deferred cost of fuel used in electric generation		335		133
Cost of decommissioning DOE uranium enrichment facilities(3)		27		34
Customer bad debts(4)		65		56
Other		76		52
Regulatory assets		832		584
Total regulatory assets		887		616
Regulatory liabilities
Provision for future cost of removal(5)		572		551
Estimated rate contingencies and refunds(6)		13		21
Other		18		13
Total regulatory liabilities	$	603	$	585

(1) Costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect the new method of accounting and the cost related to the accrued benefit obligation recognized as part of Dominion’s accounting for its acquisition of CNG.

(2) Income taxes recoverable through future rates resulting from the recognition of additional deferred income taxes, not previously recorded under past rate-making practices.

(3) Cost of decommissioning the Department of Energy’s uranium enrichment facilities, representing the unamortized portion of Dominion’s required contributions. Beginning in 1992, Dominion began making contributions over a 15-year period and collecting these costs in electric customers’ fuel rates.

(4) The Public Utilities Commission of Ohio has authorized the deferral of costs associated with certain uncollectible customer accounts not contemplated by current rates.

(5) Rates charged to customers by Dominion’s regulated businesses include a provision for the cost of future activities to remove assets expected to be incurred at the time of retirement.

(6) Estimated rate contingencies and refunds are associated with certain increases in prices by Dominion’s rate regulated utilities and other rate- making issues that are subject to final modification in regulatory proceedings.

The incurred costs underlying regulatory assets may represent past expenditures by Dominion’s rate regulated electric and gas operations or may represent the recognition of liabilities that ultimately will be settled at some future time. At December 31, 2003, approximately $403 million of Dominion’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of customer bad debts and a portion of deferred fuel costs. Deferred fuel costs have historically been recovered within two years; however, in connection with the settlement of the 2003 Virginia fuel rate proceeding, Dominion agreed to recover $307 million of previously incurred costs through June 30, 2007 without a return on unrecovered balances.

69

Notes to Consolidated Financial Statements, Continued

15. Asset Retirement Obligations

Dominion’s asset retirement obligations are primarily associated with the decommissioning of its nuclear generation facilities, abandoning certain natural gas pipelines and dismantling and removing gas and oil wells and platforms. In addition, Dominion has asset retirement obligations related to its natural gas gathering, storage, transmission and distribution systems, including approximately 2,300 gas storage wells in Dominion’s underground natural gas storage network. These obligations result from certain safety requirements to be performed at the time any pipeline or storage well is abandoned. However, Dominion expects to operate its natural gas gathering, storage, transmission and distribution systems in perpetuity. Thus, asset retirement obligations for those assets will not be reflected in Dominion’s Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur when expected retirement or abandonment dates for individual pipelines or storage wells are determined by Dominion’s operational planning. Asset retirement obligations recognized upon adoption of SFAS No. 143 and changes to Dominion’s asset retirement obligations during 2003 were as follows:

	Amount
(millions)
Obligations recognized upon adoption of SFAS No. 143	$	1,543
Obligations incurred during the period		31
Obligations settled during the period		(32	)
Accretion expense		86
Revisions in estimated cash flows		16
Other		9
Asset retirement obligations at December 31, 2003(1)	$	1,653

(1) Amount includes $2 million reported in other current liabilities.

Dominion has established trusts dedicated to funding the future decommissioning of its nuclear plants. At December 31, 2003 the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $1.9 billion.

At December 31, 2002, Dominion had recognized an accumulated provision for decommissioning activities of $1.5 billion. This amount was recognized under prior accounting policies and is reported as an asset retirement obligation on the Consolidated Balance Sheet at December 31, 2002.

16. Short-Term Debt and Credit Agreements

Joint Credit Facilities

In May 2003 and 2002, Dominion, Virginia Power and CNG entered into two joint credit facilities that allow aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2004 and a $750 million three-year revolving credit facility that terminates in May 2005. The 364-day facility includes an option to extend any borrowings for an additional period of one year to May 2005. These joint credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and CNG and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. Dominion expects to renew the 364-day revolving credit facility prior to its maturity in May 2004.

At December 31, 2003, total outstanding commercial paper supported by the joint credit facilities was $1.44 billion, with a weighted average interest rate of 1.20%. At December 31, 2002, total outstanding commercial paper supported by previous credit agreements was $1.2 billion, with a weighted average interest rate of 1.71%.

At December 31, 2003 and 2002, total outstanding letters of credit supported by the three-year facility were $85 million and $106 million, respectively.

CNG Credit Facility

In August 2003, CNG entered into a $1 billion 364-day revolving credit facility that terminates in August 2004. This credit facility is being used to support CNG’s issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by CNG in its risk management strategies for its gas and oil production. At December 31, 2003, outstanding letters of credit under this facility totaled $820 million. At December 31, 2002, outstanding letters of credit under the previous facility totaled $500 million.

In January 2004, CNG entered into a $200 million letter of credit agreement to support the issuance of a letter of credit to provide collateral required by a counterparty on derivative financial contracts used by CNG in its risk management strategies for its gas and oil production. The agreement terminates in May 2004 and is not expected to be renewed.

70

Notes to Consolidated Financial Statements, Continued

17. Long-Term Debt

At December 31,	2003 Weighted Average Coupon(1)		2003			2002
(millions, except percentages)
Dominion Resources, Inc.:
Unsecured Senior and Medium-Term Notes:
Variable Rate, due 2003				—		$	100
2.25% to 7.625%, due 2003 to 2008	5.17	%	$	1,740			2,350
5.0% to 8.125%, due 2009 to 2033(2) (3)	6.11	%		3,680			2,570
Unsecured Equity-Linked Senior Notes, 5.75% to 8.05%, due 2006 to 2008	7.03	%		743			743
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)				220			—
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041(5)	8.22	%		825			—
Unsecured Nonrecourse Debt, Variable Rate, due 2004	1.73	%		18			18
Consolidated Natural Gas Company:
Unsecured Debentures and Senior Notes:
5.375% to 7.25%, due 2003 to 2008	6.47	%		1,400			1,550
5.0% to 6.875%, due 2010 to 2027(3)	6.41	%		1,950			1,750
Unsecured Senior Subordinated Debt, 9.25%, due 2004				88			88
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.8%, due 2041(5)				206			—
Virginia Electric and Power Company:
Secured First and Refunding Mortgage Bonds:(6)
7.625% to 8.0%, due 2003 to 2007	7.83	%		465			665
7.0% to 8.625%, due 2023 to 2025	8.09	%		512			1,001
Unsecured Senior and Medium-Term Notes:
Variable Rate, due 2003				—			120
5.375% to 7.2%, due 2003 to 2008	5.65	%		1,445			1,485
4.50% to 5.25%, due 2009 to 2038	4.80	%		830			300
Unsecured Callable and Puttable Enhanced SecuritiesSM, 4.10%, due 2038(7)				225			—
Tax-Exempt Financings:(8)
Variable Rate, due 2008	1.33	%		60			60
Variable Rates, due 2015 to 2027	1.34	%		137			137
4.95% to 5.25%, due 2007 to 2008	5.21	%		107			107
2.174% to 5.875%, due 2009 to 2031	4.78	%		295			295
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.375%, due 2042(5)				412			—
Dominion Energy, Inc.:
Unsecured Medium-Term Notes, 5.72% to 6.1%, due 2005 to 2006(9)	5.94	%		243			199
Secured Senior Note, 7.33%, due 2020				238			246
Secured Bank Debt, Variable Rates, due 2006 to 2007(5)	1.60	%		951			—
Revolving Lines of Credit, Variable Rates, due 2003 to 2004	1.55	%		150			163
Dominion Capital, Inc.:
Notes, 7.6% to 12.5%, due 2003 to 2008	12.5	%		6			96
Note, Variable Rate, due 2003				—			22
Dominion Resources Services, Inc., Secured Bank Debt, Variable Rate, due 2006(5)				107			—
Dominion Fiber Ventures, Secured Senior Note, 7.05%, due 2005				21			—
				17,074			14,065
Fair value hedge valuation				43			75
Amounts due within one year	6.10	%		(1,252	)		(2,077	)
Unamortized discount and premium, net				(89	)		(95	)
				15,776			11,968
Other Unsecured Notes Payable to Affiliates:
6.0%, due 2005				—			126
Variable Rate, due 2006				—			14
Amounts due within one year				—			(48	)
							92
Total long-term debt			$	15,776		$	12,060

71

Notes to Consolidated Financial Statements, Continued

Footnotes to Long-term Debt table

⁽¹⁾ Represents weighted-average coupon rates for debt outstanding as of December 31, 2003.

⁽²⁾ $250 million of the 7.82% remarketable notes due September 15, 2014 will be either mandatorily purchased and remarketed by the remarketing agent or mandatorily redeemed by Dominion on September 15, 2004. Dominion has access to other means of long-term liquidity in the event of a failed remarketing.

⁽³⁾ At the option of holders in October 2006 and August 2015, $150 million of CNG’s 6.875% senior notes due 2026 and $510 million of Dominion’s 5.25% senior notes due 2033, respectively, are subject to redemption at 100% of the principal amount plus accrued interest.

⁽⁴⁾ Convertible into Dominion common stock at any time after March 31, 2004 when the average closing price of Dominion common stock is at least $88.32 per share. At the option of holders on December 15, 2006, December 15, 2008, December 15, 2013, or December 15, 2018, this security is subject to redemption at 100% of the principal amount plus accrued interest.

⁽⁵⁾ New debt reflected on Dominion’s Consolidated Balance Sheet as a result of FIN 46R.

⁽⁶⁾ Substantially all of Virginia Power’s property ($11.7 billion at December 31, 2003) is subject to the lien of the mortgage, securing its mortgage bonds.

⁽⁷⁾ On December 15, 2008, $225 million of the 4.10% Callable and Puttable Enhanced Securities^SM due 2038 are subject to redemption at par plus accrued interest, unless holders of related options exercise rights to purchase and remarket the notes.

⁽⁸⁾ Certain pollution control equipment at Virginia Power’s generating facilities has been pledged to support these financings. The variable rate tax-exempt financings are supported by a stand-alone $200 million three-year credit facility that terminates in May 2006.

⁽⁹⁾ Aggregate principal amount of CAD$335 million of securities denominated in Canadian dollars and presented in US dollars, based on exchange rates as of year-end.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2003 were as follows:

	2004			2005			2006			2007			2008			Thereafter			Total
	(millions, except percentages)
Secured First and Refunding Mortgage Bonds	$	250			—			—		$	215			—		$	512		$	977
Secured Senior Notes		8		$	29		$	9			10		$	10			193			259
Unsecured Senior Notes (including Medium-Term Notes)		725			1,340			1,656			850			1,000			6,680			12,251
Unsecured Callable and Puttable Enhanced SecuritiesSM		—			—			—			—			—			225			225
Tax-Exempt Financings		—			—			—			15			152			432			599
Secured Bank Debt		—			—			688			370			—			—			1,058
Unsecured Senior Subordinated Debt		88			—			—			—			—			—			88
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			1,443			1,443
Other		168			2			—			—			4			—			174
Total	$	1,239		$	1,371		$	2,353		$	1,460		$	1,166		$	9,485		$	17,074
Weighted average coupon		6.10	%		6.05	%		4.94	%		4.91	%		5.07	%		6.31	%

Dominion’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2003, there were no events of default under these covenants.

Equity—Linked Securities

In 2002 and 2000, Dominion issued equity-linked debt securities, consisting of stock purchase contracts and senior notes. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock from Dominion by a settlement date, two years prior to the senior notes’ maturity date. The purchase price is $50 and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The senior notes, or treasury securities in some instances, are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts. The holders may satisfy their obligations under the stock purchase contracts by allowing the senior notes to be remarketed with the proceeds being paid to Dominion as consideration for the purchase of stock. Alternatively, holders may choose to continue

72

Notes to Consolidated Financial Statements, Continued

holding the senior notes and use other resources as consideration for the purchase of stock under the stock purchase contracts.

Dominion makes quarterly interest payments on the senior notes and quarterly payments on the stock purchase contracts at the rates described below. Dominion has recorded the present value of the stock purchase contract payments as a

liability, offset by a charge to common stock in shareholders’ equity. Interest payments on the senior notes are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as interest expense. In calculating diluted earnings per share, Dominion applies the treasury stock method to the equity-linked debt securities. These securities did not have a significant effect on diluted earnings per share for 2003.

Under the terms of the stock purchase contracts, Dominion will issue between 6.7 million and 8.1 million shares of its common stock in November 2004 and between 4.1 million and 5.5 million shares of its common stock in May 2006. A total of 13.6 million shares of Dominion common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion’s equity-linked debt securities is presented below:

Date of Issuance	Units Issued	Total Net Proceeds		Total Long- term Debt		Senior Notes Annual Interest Rate		Stock Purchase Contract Annual Rate		Total Equity Charge		Stock Purchase Settlement Date	Maturity of Senior Notes
(millions, except percentages)
2000	8.3	$	400.1	$	412.5	8.05	%	1.45	%	$	20.7	11/04	11/06
2002	6.6	$	320.1	$	330.0	5.75	%	3.00	%	$	36.3	5/06	5/08

18. Subsidiary Preferred Stock

Dominion is authorized to issue up to 20 million shares of preferred stock. Dominion issued 665,000 shares of Series A mandatorily convertible preferred stock, liquidation preference $1,000 per share, to Piedmont Share Trust (Piedmont Trust) in connection with the formation of DFV and the issuance of senior notes by DFV. Dominion is the beneficial owner of the Piedmont Trust which is consolidated in the preparation of Dominion’s Consolidated Financial Statements, thus eliminating these outstanding shares of preferred stock.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share is entitled to receive $100 per share plus accrued dividends. Dividends are cumulative.

Holders of the outstanding preferred stock of Virginia Power are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, or upon default in dividends, or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).

In 2002, Virginia Power purchased and redeemed, at par, all shares of its variable rate preferred stock October 1988 Series, June 1989 Series, September 1992A Series and September 1992B Series for $250 million, at the redemption price of $100 per share. The dividend rates for these series were variable and set every 49 days via an auction process. The combined weighted average rates for all series outstanding during 2002 and 2001, including fees for broker/dealer agreements, were 4.00% and 4.32%, respectively.

In 2002, Virginia Power issued 1,250 units consisting of 1,000 shares per unit of cumulative preferred stock for $125 million. The preferred stock has a dividend rate of 5.50% until the end of the initial dividend period on December 20, 2007. The dividend rate for subsequent periods will be determined through periodic rate remarketing. The preferred stock has a liquidation preference of $100 per share plus accumulated and unpaid dividends. Except during the initial dividend period, and any non-call period, the preferred stock will be redeemable, in whole or in part, on any dividend payment date at the option of Virginia Power. Virginia Power may also redeem the preferred stock, in whole but not in part, if certain changes are made to federal tax law which reduce the dividends received deduction percentage.

Presented below are the series of Virginia Power preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2003.

Dividend	Issued and Outstanding Shares	Entitled Per Share Upon Liquidation
	(thousands)
$5.00	107	112.50
4.04	13	102.27
4.20	15	102.50
4.12	32	103.73
4.80	73	101.00
7.05	500	103.53	(1)
6.98	600	103.49	(2)
Flex MMP 12/02, Series A	1,250	100.00
Total	2,590
(1)  Through 7/31/04; $103.18 commencing 8/1/04; amounts decline in steps thereafter to $100.00. (2)  Through 8/31/04; $103.15 commencing 9/1/04; amounts decline in steps thereafter to $100.00.

73

Notes to Consolidated Financial Statements, Continued

19. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

From 1997 through 2002, Dominion established five subsidiary capital trusts, each as a finance subsidiary of the respective parent company, which holds 100% of the voting interests. The capital trusts sold trust preferred securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the capital trusts. In exchange for the funds realized from the sale of the trust preferred securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its trust preferred securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.

Under previous accounting guidance, Dominion consolidated the trusts in the preparation of its Consolidated Financial Statements. In accordance with FIN 46R, Dominion does not consolidate the trusts as of December 31, 2003 and instead reports on its Consolidated Balance Sheet the junior subordinated notes issued by Dominion and held by the trusts as long-term debt.

The following table provides summary information about the junior subordinated notes outstanding as of December 31, 2003 and the trust preferred securities outstanding as of December 31, 2002:

Date Established	Capital Trusts	Units	Rate		Trust Preferred Securities Amount			Common Securities Amount
		(thousands)			(millions)
December 1997	Dominion Resources Capital Trust I(1)	250	7.83	%	$	250		$	8
January 2001	Dominion Resources Capital Trust II(2)	12,000	8.4	%		300			9
January 2001	Dominion Resources Capital Trust III(3)	250	8.4	%		250			8
October 2001	Dominion CNG Capital Trust I(4)	8,000	7.8	%		200			6
August 2002	Virginia Power Capital Trust II(5)	16,000	7.375	%		400		$	12
						1,400
	Unamortized discount					(3	)
	Total at December 31, 2002				$	1,397

Junior subordinated notes/debentures held as assets by each capital trust were as follows:

(1) $258 million—Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(2) $309 million—Dominion Resources, Inc. 8.4% Debentures due 1/30/2041.

(3) $258 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

(4) $206 million—CNG 7.8% Debentures due 10/31/2041.

(5) $412 million—Virginia Power 7.375% Debentures due 7/30/2042.

Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the respective parent company that issued the debt instruments held by each trust, when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant trust preferred securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferred securities is solely dependent upon the payment of amounts by Dominion, Virginia Power or CNG when they are due on the junior subordinated debt instruments. If the payment on the junior subordinated notes is deferred, the company that issued them may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, it may not make any payments or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

20. Shareholders’ Equity

Issuance of Common Stock

During 2003, Dominion issued 17 million shares of common stock and received proceeds of $990 million. Of this amount, 11 million shares and proceeds of $683 million resulted from a public offering. Net proceeds were used for general corporate purposes, principally repayment of debt. The remainder of the shares issued and proceeds received in 2003 occurred through Dominion Direct^® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options.

Repurchases of Common Stock

Dominion is authorized by its Board of Directors to repurchase up to $650 million of Dominion common stock outstanding. As of December 31, 2003, Dominion had repurchased approximately 12 million shares for $537 million.

Shares Reserved for Issuance

At December 31, 2003, a total of 76 million shares was reserved and available for issuance pursuant to Dominion Direct^®, various employee and director stock award and savings plans, stock purchase contracts associated with equity-linked debt securities and Dominion’s Series A Mandatorily Convertible Preferred Stock. See Notes 9 and 18 for a discussion of Dominion’s issuance of 665,000 shares of Series A Mandatorily Convertible Preferred Stock, liquidation preference $1,000 per share to Piedmont Share Trust, in connection with DFV.

74

Notes to Consolidated Financial Statements, Continued

Accumulated Other Comprehensive Income

Presented in the table below is a summary of accumulated other comprehensive income by component:

	2003			2002
At December 31,
(millions)
Net unrealized losses on derivatives—hedging activities	$	(768	)	$	(356	)
Net unrealized gains (losses) on investment securities		89			(72	)
Minimum pension liability adjustment		(14	)		(14	)
Foreign currency translation adjustments		64			(4	)
Total accumulated other comprehensive loss	$	(629	)	$	(446	)

Stock-Based Awards

The following table provides a summary of changes in amounts of Dominion stock options outstanding as of and for the years ended December 31, 2003, 2002 and 2001. Generally, the exercise price of Dominion employee stock options equals the market price of Dominion common stock on the date of grant.

	Stock Options		Weighted- average Exercise Price		Weighted- average Fair Value
	(thousands)
Outstanding at December 31, 2000	10,331		$	41.77
Exercisable at December 31, 2000	6,967		$	41.51
Granted—2001(1)
Exercise price < market price on grant date	480		$	33.21	$	23.69
Exercise price = market price on grant date	11,471		$	61.20	$	11.24
Exercise price > market price on grant date	194		$	62.27	$	9.43
Exercised, cancelled and forfeited	(1,484	)	$	41.23
Outstanding at December 31, 2001	20,992		$	52.90
Exercisable at December 31, 2001	7,955		$	42.68
Granted—2002	3,122		$	62.28	$	10.91
Exercised, cancelled and forfeited	(3,057	)	$	44.54
Outstanding at December 31, 2002	21,057		$	55.49
Exercisable at December 31, 2002	8,586		$	47.95
Exercised, cancelled and forfeited	(2,513	)	$	44.39
Outstanding at December 31, 2003	18,544		$	56.97
Exercisable at December 31, 2003	11,604		$	54.44

(1) In connection with the acquisition of Louis Dreyfus, employee stock options of Louis Dreyfus were converted into employee stock options of Dominion. Based on the conversion formula, certain converted stock options had exercise prices that either exceeded or were less than the market price of Dominion common stock on the date of grant. The fair value of all converted stock options was included in the purchase price of Louis Dreyfus.

There were no options granted in 2003. The fair value of the options granted in 2002 and 2001 was estimated on the dates of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:

	2002		2001
Expected dividend yield	4.17	%	4.22	%
Expected volatility	22.67	%	22.19	%
Risk free interest rate	4.38	%	5.15	%
Contractual life	10 years		10 years
Expected life	6 years		6 years

The following table provides certain information about stock options outstanding as of December 31, 2003:

	Options Outstanding				Options Exercisable
Exercise Price	Shares Outstanding	Weighted- average Remaining Contractual Life	Weighted- average Exercise Price		Shares Exercisable	Weighted- average Exercise Price
	(thousands)	(years)			(thousands)
$ 0-$19.99	2	5.0	$	19.10	2	$	19.10
$20-$30.99	34	4.9	$	24.33	34	$	24.33
$31-$40.99	33	6.0	$	39.25	33	$	39.25
$41-$50.99	4,623	5.9	$	43.35	4,363	$	42.92
$51-$60.99	9,273	5.1	$	59.88	4,862	$	59.87
$61-$69	4,579	7.4	$	65.22	2,310	$	65.49
Total	18,544	5.9	$	56.97	11,604	$	54.44

During 2003, 2002 and 2001, respectively, Dominion granted approximately 402,000 shares, 14,000 shares, and 341,000 shares of restricted stock with weighted-average fair values of $56.08, $60.62 and $63.49.

21. Dividend Restrictions

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. Dominion received dividends from its subsidiaries of $1.1 billion, $945 million and $ $806 million in 2003, 2002 and 2001, respectively.

At December 31, 2003, Dominion’s consolidated subsidiaries had approximately $8.9 billion in capital accounts other than retained earnings, representing capital stock, additional paid in capital and accumulated other comprehensive income. Dominion Resources, Inc. had approximately $9.5 billion in capital accounts other than retained earnings at December 31, 2003. Generally, such amounts are not available for the payment of dividends by affected subsidiaries, or by Dominion itself, without specific authorization by the SEC.

75

Notes to Consolidated Financial Statements, Continued

In response to a Dominion request, the SEC granted relief in 2000, authorizing payment of dividends by CNG from other capital accounts to Dominion in amounts up to $1.6 billion, representing CNG’s retained earnings prior to Dominion’s acquisition of CNG. Furthermore, Dominion submitted a similar request to the SEC in 2002, seeking relief from this restriction in regard to its subsidiary into which Louis Dreyfus was merged. The application requests relief up to approximately $303 million, representing Louis Dreyfus’ retained earnings prior to Dominion’s acquisition of Louis Dreyfus. Dominion’s ability to pay dividends on its common stock at declared rates was not impacted by the restrictions discussed above during 2003, 2002 and 2001.

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate, if found not to be in the public interest. At December 31, 2003, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2003.

See Note 19 for a description of potential restrictions on dividend payments by Dominion and certain subsidiaries in connection with the deferral of distribution payments on trust preferred securities.

22. Employee Benefit Plans

Dominion and its subsidiaries provide certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion and its subsidiaries reserve the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and compensation. Dominion’s funding policy is to generally contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The pension program also provides benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. Certain of these nonqualified plans are funded through contributions to a grantor trust.

Dominion provides retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date and years of service. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Under the provisions of SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, presently enacted changes in relevant laws are required to be considered in current period measurements of postretirement benefit costs and the accumulated postretirement benefit obligation (APBO).

In January 2004, the FASB issued Staff Position No. FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which allowed plan sponsors to elect to defer recognizing the effects of the Act. Dominion elected not to defer recognition of the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending. When issued, that guidance could require Dominion to change previously reported information.

Based on an analysis performed by a third party actuary, Dominion has determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D and therefore expects to receive the federal subsidy offered under the Act. Dominion considered the passage of the Act a significant event requiring remeasurement of its APBO on December 8, 2003. The impact of remeasurement on the 2003 postretirement net periodic benefits cost was not material. Dominion will amortize the unrecognized actuarial gains associated with the benefits of the subsidy over the average remaining service period of plan participants in accordance with SFAS No. 106. This amortization will lower future annual net postretirement benefits costs by approximately $13 million beginning in 2004.

Dominion uses December 31 as its measurement date for virtually all of its employee benefit plans. Dominion uses a market-related value of pension plan assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses.

76

Notes to Consolidated Financial Statements, Continued

The following tables summarize the changes in Dominion’s pension and other postretirement benefit plan obligations and plan assets and a statement of the plans’ funded status:

	Pension Benefits						Other Postretirement Benefits
Year ended December 31,	2003			2002			2003			2002
(millions)
Expected benefit obligation at beginning of year	$	2,801		$	2,593		$	1,119		$	996
Other gain		(2	)		—			—			—
Acquired businesses		—			1			—			3
Change in benefit obligation:
Actual benefit obligation at beginning of year		2,799			2,594			1,119			999
Service cost		86			77			55			44
Interest cost		182			177			79			68
Benefits paid		(158	)		(148	)		(60	)		(58	)
Actuarial loss during the year		199			89			228			84
Actuarial gain related to Medicare Part D		—			—			(70	)		—
Plan amendments		2			12			—			(18	)
Expected benefit obligation at end of year		3,110			2,801			1,351			1,119
Change in plan assets:
Fair value of plan assets at beginning of year		3,074			3,352			443			446
Actual return on plan assets		627			(241	)		89			(31	)
Contributions		192			111			87			60
Benefits paid from plan assets		(159	)		(148	)		(32	)		(32	)
Fair value of plan assets at end of year		3,734			3,074			587			443
Funded status		624			273			(764	)		(676	)
Unrecognized net actuarial loss		1,244			1,374			392			308
Unrecognized prior service cost		18			14			4			4
Unrecognized net transition (asset) obligation		—			(1	)		82			93
Prepaid (accrued) benefit cost	$	1,886		$	1,660		$	(286	)	$	(271	)
Amounts recognized in the consolidated balance sheets at December 31:
Prepaid pension cost	$	1,939		$	1,710			—			—
Accrued benefit liability		(86	)		(84	)	$	(286	)	$	(271	)
Intangible asset		9			10			—			—
Accumulated other comprehensive loss		24			24			—			—
Net amount recognized	$	1,886		$	1,660		$	(286	)	$	(271	)

The accumulated benefit obligation for all defined benefit pension plans was $2.7 billion and $2.4 billion at December 31, 2003 and 2002, respectively. Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the third quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, the amount of contributions, if any, is determined at that time.

Dominion has nonqualified pension and supplemental pension plans that do not have “plan assets” as defined by generally accepted accounting principles. The total projected benefit obligation for these plans was $99 million and $97 million at December 31, 2003 and 2002, respectively, and is included in the table above. The total accumulated benefit obligation for these plans was $90 million and $88 million at December 31, 2003 and 2002, respectively. The additional minimum liability recognized relating to these plans was $34 million at December 31, 2003 and 2002.

77

Notes to Consolidated Financial Statements, Continued

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocation for Dominion’s pension fund is 45% U.S. equity securities; 8% non-U.S. equity securities; 22% debt securities; and 25% other, such as real estate and private equity investments. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. Dominion’s pension plans and other postretirement plans asset allocations at December 31, 2003 and 2002 are as follows:

	Pension Plans						Other Postretirement Plans
Year ended December 31,	2003			2002			2003			2002
	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total
(millions)
Equity securities:
U.S.	$	1,658	44	$	1,156	38	$	251	43	$	174	39
International		407	11		264	8		62	11		43	10
Debt securities		859	23		893	29		205	35		170	38
Real estate		264	7		242	8		14	2		12	3
Other		546	15		519	17		55	9		44	10
Total	$	3,734	100	$	3,074	100	$	587	100	$	443	100

The components of the provision for net periodic benefit cost were as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2003			2002			2001			2003			2002			2001
(millions)
Service cost	$	86		$	77		$	71		$	55		$	44		$	40
Interest cost		182			177			173			79			68			63
Expected return on plan assets		(332	)		(349	)		(331	)		(33	)		(34	)		(32	)
Amortization of prior service cost		2			1			2						1			(1	)
Amortization of transition obligation		(2	)		(4	)		(4	)		9			11			10
Amortization of net loss		20			2			3			20			5
Settlement loss								7
Special termination benefits								15
Curtailment loss								2
Net periodic benefit cost (credit)	$	(44	)	$	(96	)	$	(62	)	$	130		$	95		$	80

Significant assumptions used in determining the net periodic cost recognized in the Consolidated Statements of Income were as follows, on a weighted-average basis:

	Pension Benefits						Other Postretirement Benefits
	2003		2002		2001		2003		2002		2001
Discount rate	6.75	%	7.25	%	7.50	%	6.75	%	7.25	%	7.50	%
Expected return on plan assets	8.75	%	9.50	%	9.50	%	7.78	%	7.82	%	7.88	%
Rate of increase for compensation	4.70	%	4.60	%	5.00	%	4.70	%	4.60	%	5.00	%
Medical cost trend rate							9.00	%	9.00	%	9.00	%

Decreasing to 4.75% in 2007 and years thereafter

Significant assumptions used in determining the projected pension benefit and postretirement benefit obligations recognized in the Consolidated Balance Sheets were as follows, on a weighted-average basis:

	Pension Benefits				Other Postretirement Benefits
	2003		2002		2003		2002
Discount rate	6.25	%	6.75	%	6.25	%	6.75	%
Rate of increase for compensation	4.70	%	4.70	%	4.70	%	4.70	%

78

Notes to Consolidated Financial Statements, Continued

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.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Other Postretirement Benefits

	One percentage point increase		One percentage point decrease
(millions)
Effect on total service and interest cost components for 2003	$	22	$	(18	)
Effect on postretirement benefit obligation at December 31, 2003	$	182	$	(148	)

In addition, Dominion sponsors defined contribution thrift-type savings plans. During 2003, 2002 and 2001, Dominion recognized $27 million, $26 million and $27 million, respectively, as contributions to these plans.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain subsidiaries fund postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. The remaining subsidiaries do not prefund postretirement benefit costs but instead pay claims as presented.

23. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, Dominion and its subsidiaries are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have a material effect on its financial position, liquidity or results of operations.

Long-Term Purchase Contracts

Presented below is a summary of Dominion’s commitments as of December 31, 2003 under long-term term fixed quantity, fixed price purchase contracts:

	2004		2005		2006		2007		2008		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	589	$	584	$	571	$	547	$	516	$	4,176	$	6,983
Production handling for gas and oil production operations		44		59		58		53		36		43		293

(1) Reflects Dominion’s minimum commitments to purchase capacity from other utilities, qualifying facilities and independent power producers under contracts for electric generation. At December 31, 2003, the present value of the total commitment is $4.2 billion. Capacity payments under these contracts totaled $611 million, $661 million and $668 million for 2003, 2002, and 2001, respectively.

In 2003, Dominion paid $154 million for the purchase of a generating facility and the termination of two long-term power purchase contracts with non-utility generators. Dominion recorded the generating facility at its estimated fair value of $49 million and recorded an after-tax charge of $65 million for the termination of the power purchase contracts. In 2001, Dominion completed the purchase of three generating facilities and the termination of seven long-term power purchase contracts with non-utility generators. Dominion paid $207 million for the generating facilities and these contracts and recorded an after-tax charge of $136 million. The allocation of the purchase price was assigned to the assets and liabilities acquired based upon estimated fair values as of the date of acquisition.

79

Notes to Consolidated Financial Statements, Continued

Lease Commitments

Dominion leases various facilities, vehicles, and equipment under both operating and capital leases. Future minimum lease payments under noncancellable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2003 are as follows (in millions):

2004	2005		2006		2007		2008		Thereafter		Total
$70	$	55	$	40	$	34	$	26	$	57	$	282

Rental expense included in other operations and maintenance expense was $95 million, $84 million and $75 million for 2003, 2002, and 2001, respectively. Beginning in 2004, approximately $25 million will be recognized annually as interest expense associated with the debt obligations of newly consolidated VIEs resulting from the adoption of FIN 46R.

As of December 31, 2003, Dominion was party to an agreement with a voting interest entity (lessor) in order to construct and lease a new power generation project in Pennsylvania. Project costs totaled $695 million at December 31, 2003 of which $624 million was advanced to the lessor by Dominion. This project is expected to be completed in 2004 and will result in estimated annual lease commitments of approximately $58 million. A lease agreement has not yet been executed for this project, however, Dominion expects that, once executed, it will qualify as an operating lease.

Dominion has been appointed to act as the construction agent for the lessor and controls the design and construction of the facility. Dominion, in this role, is responsible for completing construction by a specified date. In the event a project is terminated before completion, Dominion has the option to either purchase the project for 100% of project costs plus fees or terminate the project and turn the project over to the lessor.

Environmental Matters

Dominion is subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

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

Superfund Sites—From time to time, Dominion may be identified as a potentially responsible party to a Superfund site. The Environmental Protection Agency (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 1987, the EPA identified Dominion and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. On October 6, 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Remediation design is ongoing for the Pennsylvania site, and total remediation costs are expected to be in the range of $13 million to $25 million. Based on allocation formulas and the volume of waste shipped to the site, Dominion has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, Dominion has determined that it is probable that the PRPs will fully pay their share of the costs. Dominion generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2003, any pending or possible claims were not recognized as an asset or offset against such obligations.

Other EPA Matters—In relation to a Notice of Violation received by Virginia Power in 2000 from the EPA and related proceedings, Virginia Power, the U.S. Department of Justice, the EPA, and the states of Virginia, West Virginia, Connecticut, New Jersey and New York agreed to a settlement in April 2003 in the form of a proposed Consent Decree. The Virginia federal district court entered the final Consent Decree in October 2003, resolving the underlying actions. 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.

80

Notes to Consolidated Financial Statements, Continued

Other—Before being acquired by Dominion, Louis Dreyfus was one of numerous defendants in a lawsuit consolidated and 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 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. Although the results of litigation are inherently unpredictable, Dominion does not expect the ultimate

outcome of the case to have a material adverse impact on its results of operations, cash flows or financial position.

Dominion has determined that it is associated with 20 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 20 former sites with which Dominion is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time, it is not known to what degree these sites may contain environmental contamination. Dominion is not able to estimate the cost, if any, that may be required for the possible remediation of these sites.

Nuclear Operations

Nuclear Decommissioning—Minimum Financial Assurance—The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of its nuclear facilities. Dominion’s 2003 NRC minimum financial assurance amount, aggregated for the nuclear units, was $2.5 billion and has been satisfied by a combination of surety bonds and the funds being collected and deposited in the trusts. Dominion executed a guarantee, effective March 31, 2003, to replace the surety bonds.

Nuclear Insurance—The Price-Anderson Act provides the public up to $10.9 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Dominion has purchased $300 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, Dominion could be assessed up to $100.6 million for each of its seven licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The Price-Anderson Act was first enacted in 1957 and has been renewed three times—in 1967, 1975 and 1998. The Price-Anderson Act expired on August 31, 2002, but operating nuclear reactors continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation. The expiration of the Price-Anderson Act has no impact on existing nuclear license holders.

Dominion’s current level of property insurance coverage ($2.55 billion for North Anna, $2.55 billion for Surry, and $2.75 for Millstone) exceeds the NRC’s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Dominion’s nuclear property insurance is provided by the Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $72 million. Based on the severity of the incident, the board of directors of Dominion’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion has the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Dominion purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Dominion is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $29 million.

Old Dominion Electric Cooperative, a part owner of North Anna Power Station, and Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation, part owners of Millstone’s Unit 3, are responsible for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

Spent Nuclear Fuel—Under provisions of the Nuclear Waste Policy Act of 1982, Dominion has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion’s contracts with the DOE. In January 2004, Dominion and certain of its direct and indirect subsidiaries filed lawsuits in the United States Court of Federal Claims against the DOE in connection with its failure to commence accepting spent nuclear fuel. Dominion will continue to safely manage its spent fuel until it is accepted by the DOE.

81

Notes to Consolidated Financial Statements, Continued

Litigation

Virginia Power and DTI are defendants in a class action lawsuit pending in the U.S. District Court in Richmond, Virginia. The plaintiffs claim that Virginia Power and DTI 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 outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

Enron Bankruptcy

Based on management’s evaluation of the estimated collectibility of amounts due from Enron Corp. and certain of its subsidiaries (Enron) and the valuation of Enron-related commodity contracts, Dominion recorded a pre-tax charge to earnings of approximately $151 million in the fourth quarter of 2001. This charge was comprised of approximately $9 million for net credit exposure on past energy sales to Enron for which payment had not been received and approximately $142 million related to the impaired fair value of natural gas forward and swap contracts with Enron. Management continues to believe that this charge substantially eliminates any further Enron-related earnings exposure.

During 2002, Dominion terminated all outstanding and open positions with Enron. Dominion has submitted a claim in the Enron bankruptcy case for the value of such contracts, measured at the effective dates of contract termination. Various contingencies, including developments in the Enron bankruptcy proceedings, may affect Dominion’s ultimate exposure to Enron.

Guarantees, Letters of Credit and Surety Bonds

Beginning in 2003, the issuance of certain types of guarantees requires the recognition of a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. Furthermore, any performance required by Dominion under such guarantees would result in the recognition of additional liabilities in Dominion’s Consolidated Financial Statements.

As of December 31, 2003, Dominion has guaranteed $57 million related to officers’ borrowings under executive stock loan programs, for which individual officers are personally liable for repayment. Substantially all of this guarantee is scheduled to expire in 2005. Because of new restrictions on corporate loans or guarantees under the Sarbanes-Oxley Act of 2002, Dominion has ceased its program of new third party loans to executives for the purpose of acquiring company stock.

As of December 31, 2003, Dominion and its subsidiaries had issued $6.8 billion of guarantees, including: $3.0 billion to support commodity transactions of subsidiaries; $2.0 billion for subsidiary debt; $626 million related to a subsidiary leasing obligation for a new power generation project, and $1.2 billion for guarantees supporting other agreements of subsidiaries. Dominion had also purchased $133 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $933 million. Dominion enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. While the majority of these guarantees do not have a termination date, Dominion may choose at any time to limit the applicability of such guarantees to future transactions. To the extent a liability subject to a guarantee has been incurred by a consolidated subsidiary, that liability is included in Dominion’s Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees on behalf of its subsidiaries in the Consolidated Financial Statements, unless performance is considered probable. No such liabilities have been recognized as of December 31, 2003. Dominion believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

Indemnifications

As part of commercial contract negotiations in the normal course of business, Dominion may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate Dominion have not yet occurred or, if any such event has occurred, Dominion has not been notified of its occurrence. However, at December 31, 2003, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

Stranded Costs

In 1999, Virginia enacted the Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act) that established a detailed plan to restructure Virginia’s electric utility industry. Under the Virginia Restructuring Act, the generation portion of Dominion’s Virginia jurisdictional operations is no longer subject to cost-based regulation. The legislation’s deregulation of generation was an event that required the discontinuance of SFAS No. 71 for Dominion’s generation operations in 1999. Dominion’s base rates (excluding fuel costs and certain other allowable adjustments) will remain capped until July 2007, unless terminated sooner or otherwise modified consistent with the Virginia Restructuring Act. Under the Virginia Restructuring Act, Dominion may request a termination of the capped rates at any time after January 1, 2004, and the Virginia State Corpo -

82

Notes to Consolidated Financial Statements, Continued

ration Commission may grant Dominion’s request to terminate the capped rates, if it finds that a competitive generation services market exists in Dominion’s service area. Dominion believes capped electric retail rates and, where applicable, wires charges provided under the Virginia Restructuring Act provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Stranded costs are those costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

Even in the capped rate environment, Dominion remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. At December 31, 2003, Dominion’s exposure to potentially stranded costs included: long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements.

24. Fair Value of Financial Instruments

Substantially all of Dominion’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Fair values have been determined using available market information and valuation methodologies considered appropriate by management. The financial instruments’ carrying amounts and fair values as of December 31, 2003 and 2002 were as follows:

	2003				2002
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
(millions)
Long-term debt(1)	$	15,588	$	16,514	$	14,185	$	14,990
Junior subordinated notes payable to affiliated trusts(2)		1,440		1,608		—		—
Preferred securities of subsidiary trusts(2)		—		—		1,397		1,441

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Fair value is based on market quotations.

25. Credit Risk

Credit risk is the risk of financial loss to Dominion if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion maintains credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds held by Dominion that resulted from various trading counterparties exceeding agreed-upon credit limits established by Dominion. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from Dominion exceeding agreed-upon credit limits established by the counterparties. As of December 31, 2003 and 2002, Dominion had margin deposit assets of $157 million and $149 million, respectively, and margin deposit liabilities (reported in other current liabilities) of $12 million and $22 million, respectively.

Dominion maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on Dominion’s credit policies and its December 31, 2003 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

As a diversified energy company, Dominion transacts with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States; however, management does not believe that this geographic concentration contributes significantly to Dominion’s overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from utility electric and gas operations, including transmission services, and retail energy sales.

Dominion’s exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy trading, marketing and commodity hedging activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy trading, marketing and hedging activities include proprietary trading activities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. At December 31, 2003, gross credit exposure related to these transactions totaled $879 million,

83

Notes to Consolidated Financial Statements, Continued

reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, Dominion’s credit exposure is reduced to $865 million. Of this amount, investment grade counterparties represent 82% and no single counterparty exceeded 9%.

26. Equity Method Investments and Affiliated Transactions

At December 31, 2003 and 2002, Dominion’s equity method investments totaled $437 million and $503 million, respectively, and equity earnings on these investments totaled $25 million in 2003, $11 million in 2002 and $36 million in 2001. Dominion’s equity method investments are reported on the Consolidated Balance Sheets in other investments. The amounts reported for 2002 include Dominion’s investment in DFV, which, as discussed in Note 9, Dominion began consolidating in 2003. See Note 27 for discussion of DCI’s equity method investments.

International Investments

CNG International (CNGI) was engaged in energy-related activities outside of the United States, primarily through equity investments in Australia and Argentina. After completing the CNG acquisition, Dominion’s management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on its core business. These assets are classified as part of assets held for sale in other current assets in the Consolidated Balance Sheets. As of December 31, 2002, the CNGI assets included investments in property, plant and equipment totaling $55 million and equity method investments totaling $83 million. During 2003, Dominion recognized impairment losses totaling $84 million ($69 million after-tax) related primarily to investments in a pipeline business located in Australia and a small generation facility in Kauai, Hawaii that was sold in December 2003 for cash proceeds of $42 million. These impairment losses represented adjustments to the assets’ carrying amounts to reflect Dominion’s current evaluation of fair market value less estimated costs to sell, which were derived from a combination of actual 2003 transactions, management estimates, and other fair market value indicators. Dominion expects to complete the sale of the remaining assets by December 31, 2004.

27. Dominion Capital, Inc. (DCI)

As of December 31, 2003, Dominion has substantially exited the core DCI financial services, commercial lending and residential mortgage lending businesses.

Securitizations of Financial Assets

At December 31, 2003 and 2002, DCI held $413 million and $470 million, respectively, of retained interests from the securitization of financial assets, which are classified as available-for-sale securities. The retained interests resulted from prior year securitizations of commercial loans receivable in collateralized loan obligation (CLO), collateralized debt obligation (CDO) and collateralized mortgage obligation (CMO) transactions.

In connection with Dominion’s ongoing efforts to divest its remaining financial services investments, Dominion executed certain agreements in the fourth quarter of 2003 that resulted in the sale of commercial finance receivables, a note receivable, an undivided interest in a lease and equity investments to a new CDO structure. In exchange for the sale of these assets with an aggregate carrying amount of $123 million, Dominion received $113 million cash and a $7 million 3% subordinated secured note in the new CDO structure and recorded an impairment charge of $3 million. The equity interests in the new CDO structure, a voting interest entity, are held by an entity that is not affiliated with Dominion.

Simultaneous with the above transaction, the new CDO structure acquired all of the loans held by two special purpose trusts that were established in 2001 and 2000 to facilitate DCI’s securitization of certain loan receivables. DCI’s original transfers of the loans to the CLO trusts qualified as sales under SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. Only after receiving consents from non-affiliated third parties, the CLO trusts’ governing agreements were amended to permit the sale of their financial assets into the new CDO structure in 2003. In consideration for the sale of loans to the new CDO structure, the trusts received $243 million of subordinated secured 3% notes in the new CDO structure and $119 million in cash, which was used by the CLO trusts to redeem all of their outstanding senior debt securities. As of December 31, 2003, Dominion still held residual interests in the CLO trusts, the value of which depended solely on the subordinated 3% notes issued by the new CDO. In connection with its assessment of revised cash flows expected to be received in relation to the residual CLO interests, Dominion performed an impairment analysis based on EITF Issue No. 99-20, Recognition of Interest Income and Impairment of Purchased and Retained Beneficial Interests in Secured Financial Assets (EITF 99-20), and recorded an impairment charge of $15 million. Dominion also expensed $19 million of deferred transaction and related costs that had been incurred in the original CLO securitization transactions. Both CLO trusts were liquidated in early 2004 and Dominion’s CLO residual interests were exchanged at that time for the aforementioned $243 million subordinated secured 3% notes. Dominion is obligated under the new CDO agreements to fund

84

Notes to Consolidated Financial Statements, Continued

up to $55 million through 2007 for certain outstanding revolving loan commitments transferred to the new CDO structure and to provide a liquidity facility to the new CDO structure of up to $30 million. Both Dominion facilities are senior in right of payment to existing subordinated notes and equity interests in the new CDO structure.

There were no mortgage securitizations in 2002 or 2003. Activity for the retained interests from securitizations of CMO, CLO and CDO retained interests is summarized as follows:

	CMO			Retained Interests— CLO/CDO
(millions)
Balance at January 1, 2002	$	269		$	283
Amortization		(5	)		—
Cash received		(45	)		(2	)
Loss on securities		(19	)		—
Fair value adjustment		(11	)		—
Balance at December 31, 2002		189			281
Retained securitization		—			7
Amortization		(2	)		—
Cash received		(10	)		(1	)
Fair value adjustment		(36	)		(15	)
Balance at December 31, 2003	$	141		$	272

Key Economic Assumptions and Sensitivity Analyses

Retained interests in CLOs and CDOs are subject to credit loss and interest rate risk. Retained interests in CMOs are subject to credit loss, prepayment and interest rate risk. Given the declining residual balances and the lower weighted-average lives due to the passage of time, adverse changes of up to 20% in assumed prepayment speeds, credit losses and interest rates are estimated in each case to have less than a $10 million pre-tax impact on future results of operations.

Impairment Losses

The table below presents a summary of asset impairment losses associated with DCI operations. All impairments recorded by the financial services subsidiary are reported as other operations and maintenance expense.

	2003		2002		2001
(millions)
Retained interests from CMO securitizations	$	36	$	11	$	21
Retained interests from CLO/CDO securitizations		15		—		81
Fourth quarter CDO transaction		23		—		—
Venture capital and other equity investments		16		—		64
Deferred tax assets		26		—		—
Goodwill impairment		18		13		—
Loans receivable		—		—		94
Real-estate projects and other		—		—		21
Total	$	134	$	24	$	281

2003

On a quarterly basis, Dominion assesses for impairment its retained interests from CMO securitizations using the guidance contained in EITF 99-20. As a result of economic conditions and historically low interest rates and the resulting impact on credit losses and prepayment speeds, Dominion recorded impairments totaling $36 million throughout 2003. Given the expected stabilization of credit losses and prepayment speeds in 2004 and beyond, Dominion’s remaining projected credit loss and prepayment experience is expected to track closely with the current assumptions, which were derived from actual 1996 – 2001 Saxon Mortgage, Inc. loss and prepayment experience.

Other assets acquired through foreclosures were determined to be impaired based on offers received. The fourth quarter impairment associated with the retained interests from CLO securitizations and the fourth quarter CDO transaction are discussed above. See Note 7 for discussion of deferred tax assets and Note 13 for discussion of goodwill impairments.

2002 and 2001

In 2002, Dominion recognized an $11 million impairment on retained interests in CMO securitizations to reflect revised prepayment speed assumptions as part of routine quarterly reviews. In addition, a DCI subsidiary received an unfavorable arbitration ruling that affected its ability to recover disputed amounts for past and future performance under a contract with a major customer. See Note 13 for discussion of goodwill impairments.

In 2001, DCI recognized impairment losses of $281 million on various investments at DCI. In light of actual loan loss experience and actual prepayment activity of certain mortgage and commercial loans in the securitization trusts, Dominion increased its loan loss and prepayment speed assumptions used to estimate the fair value of its retained interests in mortgage, CLO and CDO securitizations. The other impairments and loss provisions reflected Dominion’s estimate of net realizable values of loans and other investments associated with the dramatically weakened economy and increasing instances of bankruptcies, defaults and major restructurings that significantly diminished investment values. Dominion’s valuation methodologies and assumptions varied by investment and included cash flow analysis, signed contracts, independent third-party appraisals and, in certain cases, liquidation value.

85

Notes to Consolidated Financial Statements, Continued

Remaining DCI Assets

Dominion is required by the SEC under the 1935 Act to divest of all remaining DCI investment holdings by December 31, 2006. Dominion’s Consolidated Balance Sheet reflects the following DCI assets as of December 31, 2003:

(millions)
Current assets	$	38
Available for sale securities		413
Other long-term investments		122
Property, plant and equipment, net		26
Deferred charges and other assets		69
Total	$	668

28. Operating Segments

As a result of changes in the management reporting structure during the fourth quarter of 2003, the nature and composition of Dominion’s primary operating segments have changed, as follows:

n Dominion’s electric generation operations, formerly in the Dominion Energy segment, have been presented as a separate segment, Dominion Generation;

n Dominion retail energy marketing operations, formerly in the Dominion Energy segment, have been included in the Dominion Delivery segment and

n DFV and related discontinued operations, formerly in the Dominion Delivery segment, have been included in the Corporate and Other segment.

All segment information for prior years has been recast to conform to the new segment structure. Dominion segments are as follows:

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet.

Dominion Energy includes Dominion’s electric transmission, natural gas transmission pipeline and storage businesses, certain natural gas production, as well as Clearinghouse (energy trading and marketing) and field services (aggregation of gas supply and related wholesale activities) operations.

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

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

Corporate and Other includes the operations of DCI, DFV and related telecommunications operations, and Dominion’s corporate, service company and other operations (including unallocated debt). In addition, the contribution to net income by Dominion’s primary operating segments is determined based upon 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 the segment’s performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment and include:

n 2003 cumulative effect of changes in accounting principles;

n 2003 incremental restoration expenses associated with Hurricane Isabel;

n 2003 charges for the termination of a power purchase contract and restructuring of certain electric sales contracts;

n 2003 severance costs for workforce reductions;

n 2001 restructuring activities;

n 2001 charge for credit exposure associated with the bankruptcy of Enron

n 2001 charge related to the termination of certain long-term power purchase contracts.

Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.

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Notes to Consolidated Financial Statements, Continued

The following table presents segment information pertaining to Dominion’s operations:

	Dominion Generation		Dominion Energy		Dominion Delivery		Dominion E&P		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2003
Total revenue from external customers	$	4,217	$	2,128	$	3,287	$	1,841	$	149		$	456		$	12,078
Intersegment revenue		293		493		61		150		591			(1,588	)		—
Total operating revenue		4,510		2,621		3,348		1,991		740			(1,132	)		12,078
Interest and related charges		239		64		171		82		656			(237	)		975
Depreciation, depletion and amortization		229		104		302		532		49			—			1,216
Equity in earnings of equity method investees		14		11		—		6		(6	)		—			25
Income tax expense (benefit)		310		225		236		220		(394	)		—			597
Loss from discontinued operations, net of tax		—		—		—		—		(642	)		—			(642	)
Net income		508		350		453		415		(1,408	)		—			318
Investment in equity method investees		155		96		5		51		130			—			437
Capital expenditures		1,303		319		485		1,311		20			—			3,438
Total assets (billions)		14.3		8.2		8.8		9.0		13.8			(9.9	)		44.2
2002
Total revenue from external customers	$	4,410	$	1,008	$	2,707	$	1,629	$	250		$	214		$	10,218
Intersegment revenue		51		386		23		90		568			(1,118	)		—
Total operating revenue		4,461		1,394		2,730		1,719		818			(904	)		10,218
Interest and related charges		234		56		171		88		644			(248	)		945
Depreciation, depletion and amortization		296		98		302		502		60			—			1,258
Equity in earnings of equity method investees		19		10		—		5		(23	)		—			11
Income tax expense (benefit)		330		172		201		165		(187	)		—			681
Net income		561		268		422		380		(269	)		—			1,362
Investment in equity method investees		148		68		—		53		234			—			503
Capital expenditures		559		273		459		1,492		45			—			2,828
Total assets (billions)		11.7		6.7		7.9		7.8		13.4			(7.5	)		40.0
2001
Total revenue from external customers	$	4,344	$	1,423	$	3,179	$	1,354	$	258			—		$	10,558
Intersegment revenue		2		388		15		106		626			(1,137	)		—
Total operating revenue		4,346		1,811		3,194		1,460		884			(1,137	)		10,558
Interest and related charges		259		69		191		64		610			(196	)		997
Depreciation, depletion and amortization		311		108		299		364		163			—			1,245
Equity in earnings of equity method investees		24		10		—		5		(3	)		—			36
Income tax expense (benefit)		342		173		166		145		(456	)		—			370
Net income	$	511	$	268	$	311	$	320	$	(866	)		—		$	544

87

Notes to Consolidated Financial Statements, Continued

As of both December 31, 2003 and 2002, approximately 3% of Dominion’s total long-lived assets were associated with international operations. For the years ended December 31, 2003 and 2002, approximately 2% and 1%, respectively, of operating revenues were associated with international operations.

29. Gas and Oil Producing Activities (unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation, depletion and amortization, at December 31, 2003 and 2002 follow:

	2003		2002
(millions)
Capitalized costs of:
Proved properties	$	7,561	$	6,265
Unproved properties		1,721		1,440
		9,282		7,705
Accumulated depreciation of:
Proved properties		1,476		1,212
Unproved properties		126		151
		1,602		1,363
Net capitalized costs	$	7,680	$	6,342

Total Costs Incurred

The following costs were incurred in gas and oil producing activities during the years ended December 31, 2003, 2002 and 2001:

	2003						2002						2001
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Property acquisition costs:
Proved properties	$	181	$	181		—	$	243	$	243		—	$	1,586	$	1,586		—
Unproved properties		133		125	$	8		177		170	$	7		908		897	$	11
		314		306		8		420		413		7		2,494		2,483		11
Exploration costs		291		266		25		267		260		7		305		305		—
Development costs(1)		667		604		63		760		679		81		512		395		117
Total	$	1,272	$	1,176	$	96	$	1,447	$	1,352	$	95	$	3,311	$	3,183	$	128

(1) Development costs incurred for proved undeveloped reserves were $182 million, $223 million and $133 million for 2003, 2002 and 2001, respectively.

88

Notes to Consolidated Financial Statements, Continued

Results of Operations

Dominion cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.

	2003						2002						2001
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Revenue (net of royalties) from:
Sales to nonaffiliated companies	$	1,736	$	1,552	$	184	$	1,396	$	1,257	$	139	$	1,144	$	920	$	224
Transfers to other operations		185		185		—		97		97		—		114		114		—
Total		1,921		1,737		184		1,493		1,354		139		1,258		1,034		224
Less:
Production (lifting) costs		357		294		63		272		220		52		220		162		58
Depreciation, depletion and amortization		526		470		56		502		452		50		358		307		51
Income tax expense		356		350		6		222		209		13		208		162		46
Results of operations	$	682	$	623	$	59	$	497	$	473	$	24	$	472	$	403	$	69

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 2003, 2002 and 2001, and changes in the reserves during those years, are shown in the two schedules that follow.

	2003						2002						2001
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(billion cubic feet)
Proved developed and undeveloped reserves—Gas
At January 1	5,098		4,458		640		4,090		3,517		573		2,337		1,858		479
Changes in reserves:
Extensions, discoveries and other additions	821		767		54		874		769		105		503		394		109
Revisions of previous estimates	(147	)	(71	)	(76	)	158		145		13		(24	)	(64	)	40
Production	(396	)	(346	)	(50	)	(399	)	(346	)	(53	)	(295	)	(238	)	(57	)
Purchases of gas in place	133		133		—		381		379		2		1,578		1,576		2
Sales of gas in place	(140	)	(140	)	—		(6	)	(6	)	—		(9	)	(9	)	—
At December 31	5,369		4,801		568		5,098		4,458		640		4,090		3,517		573
Proved developed reserves—Gas
At January 1	4,035		3,549		486		3,466		3,026		440		1,954		1,593		361
At December 31	4,006		3,553		453		4,035		3,549		486		3,466		3,026		440
Proved developed and undeveloped reserves—Oil
(thousands of barrels)
At January 1	169,230		138,798		30,432		140,567		115,988		24,579		75,342		51,072		24,270
Changes in reserves:
Extensions, discoveries and other additions	13,223		7,818		5,405		24,326		24,273		53		40,676		37,401		3,275
Revisions of previous estimates	697		1,433		(736	)	11,165		4,293		6,872		(1,617	)	(165	)	(1,452	)
Production	(8,723	)	(7,642	)	(1,081	)	(9,725	)	(8,653	)	(1,072	)	(7,663	)	(6,134	)	(1,529	)
Purchases of oil in place	380		380		—		2,928		2,928		—		34,619		34,604		15
Sales of oil in place	(4,873	)	(4,873	)	—		(31	)	(31	)	—		(790	)	(790	)	—
At December 31	169,934		135,914		34,020		169,230		138,798		30,432		140,567		115,988		24,579
Proved developed reserves—Oil
At January 1	65,823		47,759		18,064		63,777		46,473		17,304		36,236		21,709		14,527
At December 31	59,754		42,347		17,407		65,823		47,759		18,064		63,777		46,473		17,304

89

Notes to Consolidated Financial Statements, Continued

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities owned by Dominion.

	2003						2002						2001
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Future cash inflows(1)	$	36,486	$	32,922	$	3,564	$	28,337	$	25,344	$	2,993	$	12,350	$	11,161	$	1,189
Less:
Future development costs(2)		1,505		1,391		114		1,092		1,005		87		845		770		75
Future production costs		5,582		4,765		817		3,603		2,979		624		3,571		3,091		480
Future income tax expense (benefit)		9,457		8,715		742		7,582		6,904		678		1,917		2,026		(109	)
Future cash flows		19,942		18,051		1,891		16,060		14,456		1,604		6,017		5,274		743
Less annual discount (10% a year)		10,709		9,745		964		8,255		7,436		819		2,804		2,513		291
Standardized measure of discounted future net cash flows	$	9,233	$	8,306	$	927	$	7,805	$	7,020	$	785	$	3,213	$	2,761	$	452

(1) Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year end.

(2) Estimated future development costs, excluding abandonment, for proven undeveloped reserves are estimated to be $381 million, $279 million, and $171 million for 2004, 2005 and 2006, respectively.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of Dominion’s proved reserves. Dominion cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.

	2003			2002			2001
(millions)
Standardized measure of discounted future net cash flows at January 1	$	7,805		$	3,213		$	8,176
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(1,563	)		(1,221	)		(1,038	)
Prices and production and development costs related to future production		480			3,975			(9,793	)
Extensions, discoveries and other additions, less production and development costs		1,920			2,039			767
Previously estimated development costs incurred during the year		182			223			134
Revisions of previous quantity estimates		(918	)		(152	)		62
Accretion of discount		1,149			426			1,117
Income taxes		(679	)		(2,639	)		2,949
Acquisition of Louis Dreyfus		—			—			1,347
Other purchases and sales of proved reserves in place		347			799			102
Other (principally timing of production)		510			1,142			(610	)
Standardized measure of discounted future net cash flows at December 31	$	9,233		$	7,805		$	3,213

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Notes to Consolidated Financial Statements, Continued

30. Quarterly Financial and Common Stock Data (unaudited)

A summary of the quarterly results of operations for the years ended December 31, 2003 and 2002 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. As described in Note 9, Dominion reported the operations of DTI as discontinued operations beginning in the fourth quarter of 2003. Prior quarters for 2003 have been restated to conform to this presentation. All differences between amounts previously reported in Dominion’s Quarterly Reports on Forms 10-Q during 2003 are a result of reporting the results of operations of Dominion’s telecommunications business as discontinued operations.

	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2003
Operating revenue	$	3,579	$	2,630	$	2,853		$	3,016		$	12,078
Income from operations		1,014		577		698			272			2,561
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		409		246		326			(32	)		949
Net income (loss)		508		240		(256	)		(174	)		318
Basic EPS:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		1.33		0.78		1.01			(0.10	)		2.99
Net income (loss)		1.64		0.76		(0.79	)		(0.54	)		1.00
Diluted EPS:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		1.32		0.78		1.01			(0.10	)		2.98
Net income (loss)		1.64		0.76		(0.79	)		(0.54	)		1.00
Dividends paid per share		0.645		0.645		0.645			0.645			2.58
Common stock prices (high-low)		58.62- $51.74		65.95- $54.75		64.28- $58.05			64.45- $59.27			65.95- $51.74
2002
Operating revenue	$	2,634	$	2,332	$	2,545		$	2,707		$	10,218
Income from operations		711		625		836			713			2,885
Net income		322		272		430			338			1,362
Basic EPS		1.21		0.98		1.55			1.12			4.85
Diluted EPS		1.20		0.97		1.54			1.12			4.82
Dividends paid per share		0.645		0.645		0.645			0.645			2.58
Common stock prices (high-low)		65.97- $56.39		67.06- $60.59		66.15- $47.97			55.74- $35.40			67.06- $35.40

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Item 9A. Controls and Procedures

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

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Part III

Item 10. Directors and Executive Officers of the Registrant

The following information is incorporated by reference from the 2004 Proxy Statement, File No. 1-8489, which will be filed on or around March 5, 2004 (the 2004 Proxy Statement):

n Information regarding the directors required by this item is found under the heading Election of Directors.

n Information regarding Dominion’s Audit Committee required by this item is found under the heading The Board.

n Information regarding Dominion’s Code of Ethics required by this item is found under the heading Governance.

The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of the Registrant.

Item 11. Executive Compensation

The information regarding executive compensation contained under the heading Executive Compensation and the information regarding director compensation contained under the heading The Board—Compensation and Other Programs in the 2004 Proxy Statement is incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the heading Share Ownership in the 2004 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation—Equity Compensation Plans in the 2004 Proxy Statement is incorporated by reference.

Item 13. Certain Relationships and Related Transactions

The information concerning certain transactions with executive officers under the heading Executive Compensation—Executive Stock Purchase Programs and other transactions contained under the heading Certain Relationships in the 2004 Proxy Statement is incorporated by reference.

Item 14. Principal Accountant Fees and Services

The information concerning principal accounting fees and services contained under the heading Auditors in the 2004 Proxy Statement is incorporated by reference.

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Part IV

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 46.

2. Financial Statement Schedules

	Page
Independent Auditors’ Report	100
Schedule I—Condensed Financial Information of Registrant	101
Schedule II—Valuation and Qualifying Accounts	107

All other schedules are omitted because they are not applicable, or the required information is shown in the financial statements or the related notes.

3. Exhibits

2.1	Agreement and Plan of Merger, dated September 9, 2001, by and among Dominion Resources, Inc., Consolidated Natural Gas Company, and Louis Dreyfus Natural Gas Corp. (Exhibit 2.1, Form 8-K filed September 10, 2001, File No. 1-3196, incorporated by reference).
2.2	Amendment No. 1 to Agreement and Plan of Merger, dated September 17, 2001, by and among Dominion Resources, Inc., Consolidated Natural Gas Company, and Louis Dreyfus Natural Gas Corp. (Exhibit 2.2, Schedule 13D of Dominion Resources, Inc. with respect to Louis Dreyfus Natural Gas Corp., filed September 19, 2001, incorporated by reference).
3.1	Articles of Incorporation as in effect August 9, 1999, as amended effective March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference).
3.2	Bylaws as in effect on October 20, 2000 (Exhibit 3, Form 10-Q for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference).
4.1	See Exhibit 3.1 above.
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference); Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 23, 1995, File No. 1-2255, incorporated by reference); and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference).

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4.3	Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
4.4	Indenture, dated April 1, 1988, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Second Supplemental Indenture, dated May 1, 1999 (Exhibit 4.2, Form S-3, File No. 333-7615, as filed on April 13, 1999, incorporated by reference).
4.5	Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as Trustee (Exhibit 4(a), Form S-3 Registration Statement File No. 333-20561 as filed on January 28, 1997, incorporated by reference), Form of Second Supplemental Indenture (Exhibit 4.6, Form 8-K filed August 20, 2002, No. 1-2255, incorporated by reference).
4.6	Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated January 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference).
4.7	Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement, File No. 333-50653, as filed on April 21, 1998, incorporated by reference); Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K, dated January 9, 2001, incorporated by reference).
4.8	Indenture, dated as of May 1, 1971, between Consolidated Natural Gas Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012, incorporated by reference); Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651, incorporated by reference); Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Eighteenth Supplemental Indenture dated as of December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Twentieth Supplemental Indenture dated as of March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-3196, incorporated by reference).
4.9	Indenture, dated as of April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to United States Trust Company of New York) (Exhibit (4) to Certificate of Notification at Commission File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4 A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to the 6.80% Debentures Due

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	December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004).
4.10	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4 (iii), Form S-3, Registration Statement, File No. 333-93187, incorporated by reference); First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K, dated June 21, 2000, File No. 1-8489, incorporated by reference); Second Supplemental Indenture, dated July 1, 2000 (Exhibit 4.2, Form 8-K, dated July 11, 2000, File No. 1-8489, incorporated by reference); Third Supplemental Indenture, dated July 1, 2000 (Exhibit 4.3, Form 8-K dated July 11, 2000, incorporated by reference); Fourth Supplemental Indenture and Fifth Supplemental Indenture dated September 1, 2000 (Exhibit 4.2, Form 8-K, dated September 8, 2000, incorporated by reference); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K, dated September 8, 2000, incorporated by reference); Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K, dated October 11, 2000, incorporated by reference); Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K, dated January 23, 2001, incorporated by reference); Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K, dated May 25, 2001, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1-8489, incorporated by reference.); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489, incorporated by reference); Thirteenth Supplemental Indenture dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489, incorporated by reference); Fourteenth Supplemental Indenture, dated August 20, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489, incorporated by reference); Forms of Fifteenth and Sixteenth Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed December 12, 2002, File No. 1-8489, incorporated by reference); Forms of Seventeenth and Eighteenth Supplemental Indentures (Exhibits 4.2. and 4.3 to Form 8-K filed February 11, 2003, File No. 1-8489, incorporated by reference); Forms of Twentieth and Twenty-first Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed March 4, 2003, File No. 1-8489, incorporated by reference); Form of Twenty-second Supplemental Indenture (Exhibit 4.2 to Form 8-K filed July 22, 2003, File No. 1-8489 incorporated by reference); Form of Twenty-Third Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 9, 2003, File No. 1-8489, incorporated by reference); Form of Twenty-Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference); Form of Twenty-Sixth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference).
4.11	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.1, Form S-3 File No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K, File dated April 12, 2001, File No. 1-3196 incorporated by reference); Second Supplemental Indenture, dated October 25, 2001 (Exhibit 4.1, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Third Supplemental Indenture, dated October 25, 2001 (Exhibit 4.3, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K, dated May 22, 2002, Form 1-3196, incorporated by reference) Form of Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196, incorporated by reference).
4.12	Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.2, Form S-3 Registration No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K, dated October 16, 2001, File No. 1-3196, incorporated by reference).
4.13	Indenture, dated as of June 15, 1994, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration and Production, Inc. and The Bank of New York (as successor trustee to Bank of Montreal Trust Company) (Exhibit 4.13, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001(Exhibit 4.7, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).

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4.14	Indenture, dated as of December 11, 1997, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration & Production, Inc., and La Salle Bank National Association (formerly LaSalle National Bank) (Exhibit 4.14, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001 (Exhibit 4.9, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).
4.15	Dominion Resources, Inc. agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of Dominion Resources, Inc.’s total consolidated assets.
10.1	Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit 10(v), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference).
10.2	DRI Services Agreement, dated January 28, 2000, by and between Dominion Resources, Inc., Dominion Resources Services, Inc. and Consolidated Natural Gas Service Company, Inc. (Exhibit 10(viii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8489, incorporated by reference).
10.2	Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).
10.3	PJM South Implementation Agreement between Virginia Electric and Power Company and PJM Interconnection, L.L.C., dated September 30, 2002, as amended December 6, 2002 (Exhibit 10.4, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.4	$1,250,000,000 364-Day Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 29, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).
10.5	$750,000,000 Three-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 30, 2002 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).
10.6	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Dominion (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489, incorporated by reference).
10.7*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, effective January 1, 1981 as amended and restated October 17, 2003 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).
10.8*	Dominion Resources, Inc.’s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8489, incorporated by reference).
10.9*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference).
10.10*	Dominion Resources, Inc. Executive Stock Purchase and Loan Plan II, dated February 15, 2000 (Exhibit 10.10, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.11*	Form of Employment Continuity Agreement for certain officers of Dominion, amended and restated July 15, 2003 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003, File No. 1-8489, incorporated by reference).
10.12*	Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference).

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10.13*	Dominion Resources, Inc. Retirement Benefit Restoration Plan as adopted effective January 1, 1991 as amended and restated October 17, 2003 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).
10.14*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, effective January 1, 1994 and as amended and restated July 15, 2003 (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.15*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (filed herewith).
10.16*	Dominion Resources, Inc. Directors’ Stock Compensation Plan, as amended February 27, 2004 (filed herewith).
10.17*	Dominion Resources, Inc. Directors Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002, incorporated by reference).
10.18*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference).
10.19*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, as amended and restated December 20, 2002 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.20*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003 (Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.21*	Arrangement with Thos. E. Capps regarding additional credited years of service for retirement and retirement life insurance purposes (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.22*	Employment Agreement dated September 30, 2002 between Dominion and Thos. E. Capps (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2002, File No. 1-8489, incorporated by reference) including supplemental letter, dated February 27, 2003 (Exhibit 10.22, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.23*	Form of Reimbursement Agreement between certain executive officers and Dominion (Exhibit 10(xxvii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).
10.24*	Letter agreement between Dominion and Thomas F. Farrell, II (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.25*	Letter agreement between Dominion and Thomas N. Chewning (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.26*	Offer of employment dated March 16, 2001 between Dominion and Duane C. Radtke (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
12	Ratio of earnings to fixed charges (filed herewith).
21	Subsidiaries of the Registrant (filed herewith)
23.1	Consent of Deloitte & Touche LLP (filed herewith).
23.2	Consent of Ralph E. Davis Associates, Inc. (filed herewith).
23.3	Consent of Ryder Scott Company, L.P. (filed herewith).

98

31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

* Indicates management contract or compensatory plan or arrangement.

(b) Reports on Form 8-K

The following Current Reports on Form 8-K were filed with the SEC:

1. Dominion filed a report on Form 8-K on December 9, 2003, relating to the sale of $200,000,000 aggregate principal amount of Dominion’s 2003 Series G 2.125% Convertible Senior Notes Due 2023.

2. Dominion filed a report on Form 8-K on January 14, 2004, relating to the sale of $200,000,000 aggregate principal amount of Dominion’s 2004 Series A 5.20% Senior Notes Due 2016 and $100,000,000 aggregate principal amount of Dominion’s 2004 Series B Floating Rate Senior Notes Due 2006.

The Current Reports of Form 8-K listed below were furnished to the SEC during the period covered by this report and shall not be deemed “filed” for purposes of the Securities Exchange Act of 1934, as amended, or incorporated by reference into any document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing:

1. Dominion furnished a report on Form 8-K on December 19, 2003, relating to its press release announcing the election of Thomas F. Farrell, II as President and Chief Operating Officer of Dominion.

2. Dominion furnished a report on Form 8-K on January 23, 2004, relating to its press release announcing unaudited earnings for the year ended December 31, 2003.

99

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the consolidated financial statements of Dominion Resources Inc. and subsidiaries as of December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, and have issued our report thereon dated February 26, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph as to changes in accounting principles for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees in 2003; goodwill and intangible assets in 2002; and derivative contracts and hedging activities in 2001); such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedules of Dominion Resources Inc. and subsidiaries, listed in Item 15. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/S/ DELOITTE & TOUCHE LLP

Richmond, Virginia

February 26, 2004

100

Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Statements of Income

Year Ended December 31,	2003			2002			2001
(millions)
Operating Expenses
Affiliated	$	22		$	22		$	15
Other		10			11			7
Total operating expense		32			33			22
Loss from operations		(32	)		(33	)		(22	)
Other income (expense):
Affiliated interest income		137			85			87
Other		(28	)		7			7
Total other income		109			92			94
Interest and related charges:
Affiliated interest expense		73			68			66
Other		408			353			339
Total interest and related charges		481			421			405
Loss before income taxes		(404	)		(362	)		(333	)
Income tax benefit		(163	)		(121	)		(117	)
Equity in undistributed earnings of subsidiaries		1,201			1,603			760
Income from continuing operations		960			1,362			544
Loss from discontinued operations (net of income taxes of $15)		(642	)		—			—
Net Income	$	318		$	1,362		$	544

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

101

Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Balance Sheets

At December 31,	2003			2002
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	9		$	74
Receivables and advances due from affiliates		2,831			2,201
Prepayments		47			68
Escrow account for debt refunding		—			500
Other		—			1
Total current assets		2,887			2,844
Investments
Investment in affiliates		14,543			13,966
Loans to affiliates		1,699			1,300
Other		32			26
Total investments		16,274			15,292
Property, Plant and Equipment, Net
Property, plant and equipment		6			6
Accumulated depreciation, depletion and amortization		(3	)		(3	)
Total property, plant and equipment, net		3			3
Deferred Charges and Other Assets		37			32
Total assets	$	19,201		$	18,171
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	268		$	1,548
Short-term debt		573			354
Payables and short-term borrowings due to affiliates		68			43
Accrued interest and taxes		109			97
Other		4			6
Total current liabilities		1,022			2,048
Long-Term Debt
Long-term debt		6,069			4,219
Notes payable to affiliates		848			914
Total long-term debt		6,917			5,133
Deferred Credits and Other Liabilities
Deferred income taxes		—			54
Other		59			58
Total deferred credits and other liabilities		59			112
Total liabilities		7,998			7,293
Preferred Stock		665			665
Common Shareholders’ Equity
Common stock, no par(1)		10,052			9,051
Other paid-in capital		61			47
Retained earnings		1,054			1,561
Accumulated other comprehensive income (loss)		(629	)		(446	)
Total common shareholders’ equity		10,538			10,213
Total liabilities and shareholders’ equity	$	19,201		$	18,171

(1) 500 million shares authorized; 325 million shares and 308 million shares outstanding at December 31, 2003 and 2002, respectively.

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

102

Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Statements of Cash Flows

Year Ended December 31,	2003			2002			2001
(millions)
Net Cash Provided By Operating Activities	$	690		$	547		$	408
Investing Activities
Investment in affiliates		(77	)		(95	)		(17	)
Affiliate (advances) repayment, net		(1,296	)		(2,435	)		327
Loans to affiliates		(220	)		—			(1,300	)
Purchase of Dominion Fiber Ventures senior notes		(633	)		—			—
Escrow release (deposit) for debt refunding		500			(500	)		—
Other		—			(3	)		(4	)
Net cash used in investing activities		(1,726	)		(3,033	)		(994	)
Financing Activities
Issuance of common stock		990			2,020			245
Repurchase of common stock		—			(66	)		—
Issuance of long-term debt		2,120			1,680			1,097
Repayment of long-term debt		(1,500	)		—			—
Issuance (repayment) of short-term debt, net		219			(294	)		(908	)
Issuance of notes payable to affiliates		—			—			1,276
Repayment of notes payable to affiliates		(15	)		(227	)		(345	)
Common dividends paid		(825	)		(723	)		(649	)
Other		(18	)		(11	)		—
Net cash provided by financing activities		971			2,379			716
Increase (decrease) in cash and cash equivalents		(65	)		(107	)		130
Cash and cash equivalents at beginning of the year		74			181			51
Cash and cash equivalents at end of the year	$	9		$	74		$	181
Supplemental cash flow information:
Noncash transactions from investing and financing activities:
Stock and stock option issuance—Louis Dreyfus acquisition							$	894
Conversion of short-term advances and other amounts receivable from subsidiaries to paid-in capital	$	1,220		$	959			86
Conversion of interest receivable from subsidiaries to long-term note receivable		125
Issuance of preferred stock to beneficially owned trust								665
Common stock received in exchange for reduction in amounts receivable from subsidiary					150
Exchange of debt securities					450

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

103

Dominion Resources, Inc. (Parent Company)

Schedule I — Condensed Financial Information of Registrant

Notes to Condensed Financial Statements

1. Basis of Presentation

Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Dominion Resources, Inc. (the Company) do not reflect all of the information and notes normally included with financial statements prepared in accordance with generally accepted accounting principles. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2003 Form 10-K, Part II, Item 8.

Accounting for subsidiaries—The Company has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.

Income Taxes—Income taxes are computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, and reflects the tax assets and liabilities of the Company on a stand alone basis. The Company also records the effect of filing consolidated state tax returns with its subsidiaries. Although the Company’s current income tax benefits are based on its taxable loss on a separate company basis, under the 1935 Public Utility Holding Company Act, the Company is restricted in the amount of cash reimbursements that it may receive from subsidiaries.

2. Long-Term Debt

At December 31,	2003 Weighted- average Coupon(1)		2003			2002
(millions)
Unsecured Senior and Medium-Term Notes:
Variable Rates, due 2003				—		$	100
2.25% to 7.625%, due 2003 to 2008	5.17	%	$	1,740			2,350
5.0% to 8.125%, due 2009 to 2033(2)(3)	6.11	%		3,680			2,570
Unsecured Mandatory Equity-Linked Senior Notes, 5.75% to 8.05%, due 2006 to 2008(4)	7.03	%		743			743
Unsecured Convertible Senior Notes, 2.125%, due 2023(5)				220			—
Unsecured Nonrecourse Debt:
Variable Rates, due 2004	1.73	%		18			18
				6,401			5,781
Fair value hedge valuation(6)				2			5
Amount due within one year				(268	)		(1,500	)
Unamortized discount				(66	)		(67	)
				6,069			4,219
Notes Payable—Affiliates:
Unsecured Other Affiliated Notes Payable, 6.0%, due 2005				26			126
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041	8.22	%		825			825
Unsecured Other Affiliated Notes Payable, Variable Rates, due 2006				—			14
				851			965
Amount due within one year				—			(48	)
Unamortized discount				(3	)		(3	)
				848			914
Total long-term debt			$	6,917		$	5,133

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2003.

(2) Includes $250 million of the 7.82 percent Series E Remarketable Notes due September 15, 2014, which will be either mandatorily purchased and remarketed by the remarketing agent or mandatorily redeemed by the Company on September 15, 2004. Dominion has access to other means of long-term liquidity in the event of a failed remarketing.

(3) At the option of holders in August 2015, $510 million of Dominion’s 5.25% senior notes due 2033, are subject to redemption at 100% of the principal amount plus accrued interest.

(4) See Note 3.

(5) Convertible into Dominion common stock at any time after March 31, 2004 when the average closing price of Dominion common stock is at least $88.32 per share. At the option of holders on December 15, 2006, December 15, 2008, December 15, 2013, or December 15, 2018, this security is subject to redemption at 100% of the principal amount plus accrued interest.

(6) Represents changes in fair value of certain fixed rate long-term debt associated with fair value hedging relationships.

Based on the stated maturity dates rather than the early redemption dates that could be elected by the instrument holders, noted above, the scheduled principal payments of long-term debt at December 31, 2003 were as follows (in millions):

2004	2005		2006		2007	2008		Thereafter		Total
$268	$	1,116	$	413	—	$	730	$	4,725	$	7,252

The Company’s long-term debt agreements contain customary covenants and default provisions. As of December 31, 2003, there were no events of default under those covenants.

3. Equity-Linked Securities

In 2002 and 2000, the Company issued equity-linked debt securities, consisting of stock purchase contracts and senior notes. The stock purchase contracts obligate the holders to purchase shares of the Company’s common stock from the Company by a settlement date, two years prior to the senior notes’ maturity date. The purchase price is $50 and the number of shares to be purchased will be determined under a formula based on the average closing price of the Company’s common stock near the settlement date. The senior notes, or treasury securities in some instances, are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts. The holders may satisfy their obligations under the stock purchase contracts by allowing the senior notes to be remarketed with the proceeds being paid to the Company as consideration for the purchase of stock. Alternatively, holders may choose to continue holding the senior notes and use other resources as consideration for the purchase of stock under the stock purchase contracts.

The Company makes quarterly interest payments on the senior notes and quarterly payments on the stock purchase contracts at the rates described below. The Company has recorded the present value of the stock purchase contract

104

Notes to Consolidated Financial Statements, Continued

payments as a liability, offset by a charge to common stock in shareholders’ equity. Interest payments on the senior notes are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as interest expense.

Under the terms of the stock purchase contracts, the Company will issue between 6.7 million and 8.1 million shares of its common stock in November 2004 and between 4.1 million and 5.5 million shares of its common stock in May 2006. A total of 13.6 million shares of the Company’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about the Company’s equity-linked debt securities is presented below (amounts other than percentages are in millions):

Date of Issuance	Units Issued	Total Net Proceeds		Total Long- term Debt		Senior Notes Annual Interest Rate		Stock Purchase Contract Annual Rate		Total Equity Charge		Stock Purchase Settlement Date	Maturity of Senior Notes
(millions, except percentages)
2000	8.3	$	400.1	$	412.5	8.05	%	1.45	%	$	20.7	11/04	11/06
2002	6.6	$	320.1	$	330.0	5.75	%	3.00	%	$	36.3	5/06	5/08

4. Guarantees, Letters of Credit and Surety Bonds

Beginning in 2003, the issuance of certain types of guarantees requires the recognition of a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. Furthermore, any performance required by the Company under such guarantees would result in the recognition of additional liabilities in the Company’s Financial Statements.

Guarantees Supporting Related Parties

As of December 31, 2003, the Company has guaranteed $57 million related to officers’ borrowings under executive stock loan programs, for which individual officers are personally liable for repayment. Substantially all of this guarantee is scheduled to expire in 2005. Because of new restrictions on corporate loans or guarantees under the Sarbanes-Oxley Act of 2002, the Company has ceased its program involving its guaranty of any new third party loans to executives for the purpose of acquiring Dominion stock. The Company has also guaranteed $22 million for obligations of certain equity method investments. There are no liabilities recorded for these guarantees as they were entered into prior to December 31, 2002.

Guarantees Supporting Subsidiaries

As of December 31, 2003, the Company had issued the following types of guarantees of behalf of its subsidiaries:

	Amount
(millions)
Subsidiary debt(1)	$	1,679
Commodity transactions(2)		2,050
Lease obligation for power generation facility(3)		626
Nuclear obligations(4)		484
Pipeline obligation(5)		288
Other lease obligations(6)		104
Miscellaneous		200
Total subsidiary obligations	$	5,431

(1) Guarantees of debt of Dominion Resource Services Company (DRS), Dominion Energy, Inc. (DEI) and Dominion Capital, Inc. (DCI). In the event of default by the subsidiaries, the Company would be obligated to repay such amounts.

(2) Guarantees related to energy marketing activities and other commodity commitments of certain subsidiaries of Virginia Electric and Power Company (Virginia Power) and Consolidated Natural Gas (CNG) and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any one of these subsidiaries fails to perform or pay under the contracts and the counterparties seek performance or payment, the Company would be obligated to satisfy such obligation. The Company and its subsidiaries receive similar guarantees as collateral for credit extended to others.

(3) Guarantee for a leasing obligation of a DEI subsidiary for a new power generation facility.

(4) Guarantees related to the future nuclear decommissioning obligations ($26 million) of certain DEI subsidiaries and potential retrospective premiums ($264 million) that could be assessed, if there is a nuclear incident under the Company’s nuclear insurance programs for the Millstone Power Station. Also, as part of satisfying certain Nuclear Regulatory Commission requirements concerned with ensuring adequate funding for Millstone’s operations, the Company has also agreed to provide up to $150 million to a DEI subsidiary, if requested by such subsidiary, to pay Millstone’s operating expenses. Also includes guarantees for Virginia Power’s commitment to buy nuclear fuel ($44 million).

(5) Guarantee related to a DEI subsidiary’s pipeline construction.

(6) Guarantees for leasing obligations related to fleet vehicles and computer hardware and software that are primarily for DRS and CNG.

Standby Letters of Credit

At December 31, 2003, the Company had authorized the issuance of standby letters of credit by financial institutions in the amounts of $85 million for the benefit of certain counterparties that had extended credit to DEI and Virginia Power. In the unlikely event that DEI or Virginia Power does not pay amounts when due under the covered contracts, any covered counterparty may present its claim for payment to the financial institution, which would then request payment from DEI or Virginia Power and the Company, as applicable. As of December 31, 2003, no amounts had been presented for payment under these letters of credit.

105

Notes to Consolidated Financial Statements, Continued

Surety Bonds

At December 31, 2003, the Company and its subsidiaries had purchased $76 million of surety bonds, $73 million of which was purchased for subsidiaries. Virginia Power, CNG and various other Company subsidiaries have purchased $10 million, $48 million and $15 million, respectively, of surety bonds primarily in relation to providing worker compensation benefits and obtaining licenses, permits and rights-of-way. Under the terms of the surety bonds, Virginia Power, CNG or DEI and then the Company, are obligated to indemnify the respective surety bond company for any amounts paid on their behalf.

Indemnifications

In addition, as part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2003, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

5. Preferred Stock

The Company is authorized to issue up to 20 million shares of preferred stock. The Company issued 665,000 shares of Series A mandatorily convertible preferred stock, liquidation preference $1,000 per share, to Piedmont Share Trust (Piedmont Trust) in connection with the formation of Dominion Fiber Ventures LLC (DFV) and the issuance of senior notes by DFV. The Company is the beneficial owner of the Piedmont Trust. For more information about the Company’s investment in DFV, see Note 9 to the Consolidated Financial Statements included in the 2003 Form 10-K, Part II, Item 8.

6. Dividend Restrictions

The Company received dividends from its consolidated subsidiaries in the amounts of $1.1 billion, $945 million, and $806 million for the years 2003, 2002, and 2001, respectively.

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. In response to the Company’s request, the SEC granted relief in 2000, authorizing payment of dividends by CNG from other capital accounts to the Company in amounts up to $1.6 billion, representing CNG’s retained earnings prior to the Company’s acquisition of CNG. Furthermore, the Company submitted a similar request to the SEC in 2002, seeking relief from this restriction with regard to its subsidiary, into which Louis Dreyfus was merged. The application requests relief of up to approximately $303 million, representing Louis Dreyfus’ retained earnings prior to the Company’s acquisition of Louis Dreyfus. The Company’s ability to pay dividends on its common stock at declared rates was not impacted by the restrictions discussed above during 2003, 2002 and 2001.

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate, if found not to be in the public interest. At December 31, 2003, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2003.

See Note 19 to the Consolidated Financial Statements included in the 2003 Form 10-K, Part II, Item 8., for a description of potential restrictions on dividend payments by Dominion and certain subsidiaries in connection with the deferral of distribution payments on trust preferred securities.

106

Schedule II—Valuation and Qualifying Accounts

Column A		Column B		Column C				Column D			Column E
				Additions
Description		Balance at Beginning of Period		Charged to Expense			Charged to Other Accounts	Deductions			Balance at End of Period
(millions)
Valuation and qualifying accounts which are deducted in the balance sheet from the assets to which they apply:
Allowance for doubtful accounts	2001	$	67	$	54		—	$	45	(a)	$	76
	2002		76		48		—		61	(a)		63
	2003		63		45		—		57	(a)		51
Allowance for loan losses	2001		56		178		—		158	(a)		76
	2002		76		—		—		10	(a)		66
	2003		66		1		—		67	(b)		—
Valuation allowance for commodity contracts	2001		19		(8	)(b)	—		—			11
	2002		11		(7	)(b)	—		—			4
	2003		4		(2	)(b)	—		—			2
Reserves:
Liability for pre-2001 workforce reductions	2001		3		—		—		3	(c)		—
	2002		—		—		—		—			—
	2003		—		—		—		—			—
Liabilities for restructuring costs:
2000 Plan
DCI exit strategies—Allowance for loan losses	2001		5		—		—		2	(a)		3
	2002		3		—		—		—			3
	2003		3		—		—		3	(a)		—
Severance and related costs	2001		29		(2	)(b)	—		24	(c)		3
	2002		3		—		—		3	(c)		—
	2003		—		—		—		—			—
Lease termination and restructuring	2001		8		—		—		7	(c)		1
	2002		1		—		—		1	(c)		—
	2003		—		—		—		—			—
2001 Plan
Severance and related costs	2001		—		42		—		—			42
	2002		42		(8	)(b)	—		24	(c)		10
	2003		10		—		—		9	(c)		1
Lease termination and restructuring	2001		—	$	13		—		3	(c)		10
	2002		10		—		—		1	(c)		9
	2003	$	9		—		—	$	3	(c)	$	6

(a) Represents net amounts charged-off as uncollectible.

(b) Represents adjustments reflecting changes in estimates.

(c) Represents payments of liabilities.

107

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

DOMINION RESOURCES, INC.
By:	/s/    THOS. E. CAPPS
	(Thos. E. Capps, Chairman of the Board of Directors and Chief Executive Officer)

Date: March 1, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 1st day of March, 2004.

Signature	Title
/s/    THOS. E. CAPPS Thos. E. Capps	Chairman of the Board of Directors and Chief Executive Officer
/s/    SUSAN B. ALLEN Susan B. Allen	Director
/s/    PETER W. BROWN Peter W. Brown	Director
/s/    RONALD J. CALISE Ronald J. Calise	Director
/s/    GEORGE A. DAVIDSON, JR. George A. Davidson, Jr.	Director, Retired Chairman of the Board of Directors
/s/    JOHN W. HARRIS John W. Harris	Director
/s/    ROBERT S. JEPSON, JR. Robert S. Jepson, Jr.	Director
/s/    BENJAMIN J. LAMBERT, III Benjamin J. Lambert, III	Director
/s/    RICHARD L. LEATHERWOOD Richard L. Leatherwood	Director
/s/    MARGARET A. MCKENNA Margaret A. McKenna	Director
/s/    K. A. RANDALL K. A. Randall	Director
/s/    FRANK S. ROYAL Frank S. Royal	Director
/s/    S. DALLAS SIMMONS S. Dallas Simmons	Director

108

Signature	Title
/s/    ROBERT H. SPILMAN Robert H. Spilman	Director
/s/    DAVID A. WOLLARD David A. Wollard	Director
/s/    THOMAS N. CHEWNING Thomas N. Chewning	Executive Vice President and Chief Financial Officer
/s/    STEVEN A. ROGERS Steven A. Rogers	Vice President, Controller and Principal Accounting Officer

109