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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

For the transition period from                      to                     

Commission File Number 1-8489

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

(804) 819-2000

(Registrant’s telephone number)

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

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

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes  x    No  ¨

The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $20.8 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of the registrant’s most recently completed second fiscal quarter.

As of February 1, 2005, Dominion had 340,591,545 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

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Dominion Resources, Inc.

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Part 1

Item 1. Business

The Company

Dominion Resources, Inc. (Dominion) 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).

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.

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.

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 operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. CNG is also a transporter, distributor and retail marketer of natural gas, serving customers in Pennsylvania, Ohio, West Virginia and other states. CNG also operates a liquefied natural gas (LNG) import and storage facility in Maryland. DEI is involved in merchant generation, energy trading and marketing and natural gas and oil exploration and production.

As of December 31, 2004, Dominion and its subsidiaries had approximately 16,500 full-time employees. Approximately 6,000 employees are subject to collective bargaining agreements. The contracts of employees represented by the Utility Workers’ Union of America, United Gas Workers’ Local 69-II, AFL-CIO (Local 69-II) expire April 1, 2005. Dominion and Local 69-II have begun negotiations for new contracts.

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

Operating Segments

Dominion manages its operations through four primary business lines that integrate its electric and gas services, streamline operations and position it for long-term growth in the competitive marketplace: Dominion Delivery, Dominion Energy, Dominion Exploration & Production and Dominion Generation. Dominion also reports Corporate and Other functions as a segment. While Dominion manages its daily operations as described below, its assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Note 27 to the Consolidated Financial Statements.

Dominion Delivery

Dominion Delivery includes Dominion’s electric and gas distribution systems and customer service operations as well as retail energy marketing operations. Electric distribution operations serve residential, commercial, industrial and governmental 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 operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest regions.

Competition

Within Dominion’s certificated service territory in Virginia and North Carolina, there is no competition for electric distribution service.

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 Public Utilities Commission of Ohio (Ohio Commission). West Virginia does not require customer choice in its retail natural gas markets at this time. See Regulation—State Regulations for additional information.

Regulation

Dominion Delivery’s electric retail service, including the rates it may charge to customers, is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). See Regulation—State Regulations-Electric for additional information.

Dominion Delivery’s gas distribution service, including rates that it may charge customers, is regulated by the Ohio Commission, the Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission). See Regulation—State Regulations-Gas for additional information.

Properties

Dominion Delivery’s electric distribution network includes approximately 54,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The right-of-way grants for most electric lines have been obtained from the apparent owner of real estate, 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.

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Dominion Delivery’s investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network involves approximately 27,000 miles of pipe, exclusive of service pipe, and 203 billion cubic feet (bcf) of underground gas storage capacity in Ohio, Pennsylvania and West Virginia. See Dominion Energy—Properties for additional information regarding Dominion Delivery’s storage properties.

Sources of Fuel Supply

Dominion Delivery’s supply of electricity to serve its retail customers is primarily provided by Dominion Generation. See Dominion Generation for additional information.

Dominion Delivery is engaged in the sale and storage of natural gas through its operating subsidiaries. Dominion Delivery’s gas supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from Dominion’s and third party underground storage fields.

Seasonality

Dominion Delivery’s business typically varies seasonally based on 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

Dominion Energy includes the following operations:

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenues and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities in the Dominion Generation segment.

Competition

Dominion Energy’s electric transmission business is not subject to competition for transmission service to loads served within its Virginia and North Carolina service territories. In connection with transmission service to loads outside of its electric service territory, Dominion’s electric transmission business competes with other electric transmission providers, primarily on the basis of rates and availability of service.

Dominion Energy’s gas transmission operations compete 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.

Regulation

Dominion Energy’s electric transmission operations are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Virginia Commission and the North Carolina Commission. FERC also regulates Dominion’s natural gas pipeline transmission, storage and LNG operations. See State Regulations and Federal Regulations in Regulation for additional information.

Properties

Dominion Energy has approximately 6,000 miles of electric transmission lines located in the states of North Carolina, Virginia and West Virginia. 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 maintains major electric transmission 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 Regional Transmission Organization (RTO) in Future Issues and Other Matters in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

Dominion Energy has approximately 7,900 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia.

Dominion’s storage operations involve both the Dominion Delivery and Dominion Energy segments. Storage operations include 26 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with more than 2,000 storage wells and approximately 372,000 acres of operated leaseholds. Dominion Energy and Dominion Delivery together have more than 100 compressor stations with approximately 626,000 installed compressor horsepower. The total designed capacity of the underground storage fields is approximately 965 bcf of which 203 bcf is operated by Dominion Delivery and 762 bcf is operated by Dominion Energy. Six of the 26 storage fields are jointly-owned with other companies and have a capacity of 243 bcf. Dominion Energy also has approximately 8 bcf of above ground storage capacity at its Cove Point LNG facility.

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

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Sources of Energy Supply

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 accessibility to supplies nationwide.

Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Midwest, Mid-Atlantic and Northeast regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.

Seasonality

Dominion Energy’s business is affected by seasonal changes in the prices of commodities that it actively markets and trades.

Dominion Exploration & Production

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.

Competition

Dominion Exploration & Production’s competitors range from major, international oil companies to smaller, independent producers. Dominion Exploration & Production faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Dominion Exploration & Production 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 Exploration & Production sells most of its deliverable natural gas and oil into short and intermediate-term markets. Dominion Exploration & Production 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 Exploration & Production 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.

Regulation

Dominion’s exploration and production operations are subject to regulation by numerous federal and state authorities. The pipeline transportation of Dominion’s natural gas production is regulated by FERC and pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands

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Act, which requires open-access, non-discriminatory pipeline facilities. Dominion’s production operations in the Gulf of Mexico and most of its operations in the western United States are located on federal oil and gas leases administered by the Minerals Management Service (MMS) or the Bureau of Land Management. These leases are issued through a competitive bidding process and require Dominion’s compliance with stringent regulations. Offshore production facilities must comply with MMS regulations relating to engineering, construction and operational specifications and the plugging and abandonment of wells. Dominion’s production operations are also subject to numerous environmental regulations including regulations relating to oil spills into navigable waters of the United States. See Regulation—Federal Regulations and Regulation—Environmental Regulation for additional information.

Properties

Dominion Exploration & Production owns 5.9 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 leaseacreage, 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 3.0 million acres, with another 2.2 million acres held for future exploration and development drilling opportunities. See also Item 2. Properties for additional information on Dominion Exploration & Production’s properties.

Seasonality

Dominion Exploration & Production’s business can be affected by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for unhedged Dominion natural gas and oil production, can be affected by seasonal weather changes and weather effects.

Dominion Generation

Dominion Generation includes more than 28,000 Mw of generation capability for Dominion’s electric utility and merchant fleet. The generation mix 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 completed the acquisition of three USGen New England Inc. (USGen) power stations located in Massachusetts and Rhode Island during January 2005 and expects to complete the acquisition of the Kewaunee nuclear power plant located in northeastern Wisconsin during the first half of 2005. In addition, as discussed above, as a result of the reorganization of the

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Clearinghouse, Dominion Generation’s 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities by the Clearinghouse that were previously reported in the Dominion Energy segment.

Competition

For Dominion Generation’s electric utility subsidiary, retail choice has been available for all of Dominion’s Virginia electric customers since January 1, 2003; however, to date, competition in Virginia has not developed to the extent originally anticipated. See Regulation—State Regulations. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation’s merchant generation fleet owns and operates three large facilities in the Midwest. These generating 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 ISOs. 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 sell 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 within any given ISO. However, management believes that Dominion has the expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to like assets within the region.

Regulation

In Virginia and North Carolina, Dominion’s electric utility generation facilities, along with power purchases, are used to serve its utility service area obligations. Due to 2004 deregulation legislation, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and the related fuel costs for the generating fleet, including power purchases, are subject to a fixed rate recovery through July 1, 2007 when a one-time prospective adjustment will be considered. During this transition period, the risk of fuel factor-related cost recovery shortfalls may adversely impact Dominion’s cost structure. Conversely, Dominion may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs. Subject to market conditions, any generation remaining after meeting utility system needs is sold outside of Dominion’s service area. See Regulation—State Regulations and Regulation—Federal Regulations—Environmental Regulation for additional information.

Properties

For a listing of Dominion Generation’s generation facilities, see Item 2. Properties.

Sources of Fuel Supply

Dominion Generation 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 Generation utilizes primarily long-term contracts 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 Generation 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-fired generation are used primarily to support heavier system generation loads during very cold or very hot weather periods. Additional utility requirements are purchased mainly under short-term spot agreements.

Dominion Generation uses natural gas as needed throughout the year for Dominion’s utility and merchant generation facilities. Dominion’s gas supply is obtained from various sources including: purchases from major and independent producers in the Mid-continent and Gulf Coast 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 Dominion Generation’s facilities. Dominion Generation’s capacity portfolio allows flexible natural gas deliveries to its gas turbine fleet, while minimizing costs.

Seasonality

Dominion Generation’s sales of electricity typically vary seasonally based on demand for electricity by residential and commercial customers for cooling and heating use based on changes in temperature.

Nuclear Decommissioning

Dominion Generation 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 nonregulated 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. Amounts collected from ratepayers and placed in trusts are being invested to fund future 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

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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 selected minor decommissioning activities are being performed. Millstone Unit 1 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.

Corporate and Other

Dominion also has a Corporate and Other segment that includes:

Business Developments

In January 2005, the Public Service Commission of Wisconsin granted Dominion’s request to rehear the case involving Dominion’s proposed purchase of the Kewaunee nuclear power plant, located in northeastern Wisconsin. The commission had voted to deny the sale in November 2004. During the fourth quarter of 2003, Dominion reached an agreement to buy the Kewaunee nuclear power plant from Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WP&L), a subsidiary of Alliant Energy Corporation for an aggregate purchase price of $220 million in cash, including $35 million for nuclear fuel. If approved by the commission, the transaction is expected to close in the first half of 2005.

In January 2005, Dominion closed on its purchase of three electric power generation facilities from USGen for $642 million. The acquisition was part of a bankruptcy court-approved divestiture of generation assets by USGen. The plants include the 1,521-megawatt Brayton Point Station in Somerset, Massachusetts; the 743-megawatt Salem Harbor Station in Salem, Massachusetts; and the 426- megawatt Manchester Street Station in Providence, Rhode Island.

In February 2005, Dominion paid $42 million in cash and assumed $62 million in debt in connection with the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary, LP, a non-utility generator, to provide electricity to Dominion.

See Kewaunee Power Plant, USGen Power Stations and Restructuring of Contract with Non-Utility Generator in Future Issues and Other Matters in MD&A for additional information on the above business developments.

Regulation

Dominion is subject to regulation by the SEC, FERC, the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, and other federal, state and local authorities.

State Regulations

Electric

Dominion’s electric retail service is subject to regulation by the Virginia Commission and the 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, 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

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functions through the creation of divisions within Virginia Power. 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 April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

The risk of fuel factor-related cost recovery shortfalls may adversely impact its cost structure during the transition period and Dominion could realize the negative economic impact of any such adverse event. Conversely, Dominion may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs for its electric utility generation-related operations.

Dominion anticipates that its unhedged natural gas and oil production will act as a natural internal hedge for natural gas and oil fuel costs associated with electric generation. If natural gas and oil prices rise, it is expected that Dominion’s exploration and production operations will earn greater profits that will offset higher fuel costs and lower profits in Dominion’s electric generation operations. Conversely, if gas and oil prices fall, it is expected that Dominion’s electric generation operations will incur lower fuel costs and earn higher profits that will offset lower profits in Dominion’s exploration and production operations. Dominion also anticipates that the fixed fuel rate will lessen the impact of seasonally mild weather on its electric generation operations. During periods of mild weather it is expected that electric generation operations will burn less high-cost fuel because customers will use less electricity, thereby offsetting decreased revenues. Alternatively, in periods of extreme weather, Dominion’s higher fuel costs from running costlier plants are expected to be mitigated by additional revenue as customers use more electricity.

Other amendments to the Virginia Restructuring Act were also enacted with respect to a minimum stay exemption program, a wires charge exemption program and allowing the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kW or greater would be exempt from the twelve month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider.

The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges when selecting supply service from a competitive service provider by agreeing to market-based pricing upon return to the incumbent electric utility. Customers electing this option would waive the right to return to capped rate service from the incumbent electric utility. The program is limited to the first 1,000 Mw of load or eight percent of the utility’s prior year Virginia adjusted peak load in the first 18 months of the program.

In January 2005, Dominion filed compliance plans and the required market-based pricing methodology for both programs. To encourage a successful program and the development of retail competition, Dominion has proposed that customers that enroll with a competitive service provider in the wires charge exemption program in 2005 be allowed to return to service with Dominion at capped rates after October 2007 instead of market-based pricing. The Virginia Commission must approve these proposals prior to implementation.

In December 2004, Dominion filed its annual market prices/wires charges compliance plan with the Virginia Commission. Calculation of the 2005 wires charges in accordance with the formula approved by the Virginia Commission produced zero wires charges for 2005 for all but a few smaller rate classes. As a result, Dominion voluntarily agreed to forego the collection of any wires charges during 2005. Dominion’s decision to forego wires charges in 2005 is not intended to set a precedent for subsequent periods. Dominion intends to collect wires charges in future periods should the Virginia Commission-approved methodology determine that wires charges are applicable.

See Regulation—Federal Regulations—Federal Energy Regulatory Commission and Status of Electric 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

The three retail access pilot programs, approved by the Virginia Commission in 2003, continue to be available to customers. These 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 potential participation of more than 65,000 customers from a variety of customer classes.

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 was recovered in 2004 with $85 million to be recovered in 2005, $87 million in 2006 and $43 million in the first six months of 2007.

As a result of amendments to the Virginia Restructuring Act in 2004, Dominion’s capped based rates were extended to December 31, 2010. In addition, Dominion’s fuel factor provisions were frozen until July 1, 2007, after which they can be only adjusted once more through December 31, 2010. See Status of Electric Deregulation in Virginia above for additional information regarding the Virginia Restructuring Act amendments.

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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 before 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. However in April 2004, the North Carolina Commission commenced an investigation into Dominion’s North Carolina base rates and subsequently ordered Dominion to file a general rate case to show cause why its North Carolina base rates should not be reduced. The rate case was filed in September 2004 and in February 2005, Dominion reached a tentative settlement with parties in the case that is subject to North Carolina Commission approval before becoming effective.

Gas

Dominion’s gas distribution service is regulated by the Ohio Commission, the Pennsylvania Commission and the 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, 2004, approximately 548,000 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, 2004, approximately 88,000 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 one, three 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.

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 recovers all eligible bad debt expenses through the bad debt tracker and removes bad debt from base rates. Annually, Dominion assesses the need to adjust the tracker based on the preceding year’s actual bad debt expense.

Pennsylvania—In July 2004, the Pennsylvania Commission approve a settlement agreement between Dominion and the Office of Consumer Advocate (OCA) in which the OCA agreed to drop its appeal of a previous Pennsylvania Commission order that allowed Dominion to recover approximately $16.5 million in unrecovered purchased gas costs. As part of the settlement, all customer service and delivery charges will be fixed through December 31, 2008. Gas costs will continue to pass through to the customer through the purchased gas cost adjustment mechanism.

Federal Regulations

Public Utility Holding Company Act of 1935

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 businesses 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 exit of the core operating businesses of 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

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 addition, Dominion’s electric utility subsidiary has 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

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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. In October 2004, FERC issued an order conditionally approving Dominion’s application to join PJM, and in November 2004, the Virginia Commission approved Dominion’s application to join PJM subject to certain terms and conditions. The North Carolina Commission evidentiary hearing was held in January 2005. Dominion cannot predict the outcome of this matter at this time.

In a separate order issued in September 2004, FERC granted authority to Dominion subsidiaries with market based rate authority to charge market based rates for sales of electric energy and capacity to loads located within the Company’s service territory upon its integration into PJM. For additional information, see RTO in Future Issues and Other Matters in MD&A.

Dominion is also subject to FERC’s Standards of Conduct that govern conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The rule defines 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.

In June 2004, FERC approved Dominion’s filing to provide optional backup supply service to competitive service providers serving retail customers, including the retail pilot programs, in Dominion’s service territory in Virginia. The filing addressed competitive service providers’ concerns with the availability of transmission capacity to move energy into Virginia. The backup supply service will allow competitive service providers to continue to serve their customers in Dominion’s service area in Virginia during periods of supply interruption. This is an interim solution until Dominion is integrated into PJM.

In August 2004, Dominion and FERC announced a settlement of a self-reported infraction of FERC regulations involving data sharing of non-public gas storage information. Under the settlement, Dominion paid a $500,000 civil penalty and refunded $4.5 million to its non-affiliated natural gas storage customers. In addition, Dominion agreed to enhance internal training and oversight of employees who handle non-public, market-sensitive data.

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. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate gas pipeline subsidiaries, including Dominion Transmission, Inc. (DTI) and Dominion Cove Point LNG, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

FERC Order 636 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 Pipeline Safety Act of 2002, which includes 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. Dominion has evaluated its natural gas transmission and storage properties under the final regulations issued in December 2003 and has developed the required implementation plan including identification, testing and potential remediation activities.

Dominion implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2004. In all material respects, these filings were approved by FERC in the form requested by Dominion and were subject to only minor modifications.

Environmental Regulations

Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For a 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 22 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 January 2004, the EPA proposed 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 to address regional haze, are expected to be finalized in 2005 and 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.

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In March 2004, the State of North Carolina filed a petition under Section 126 of the Clean Air Act seeking the EPA to impose additional nitrogen oxide (NO_X) and sulfur dioxide (SO₂) reductions from electrical generating units in thirteen states, claiming emissions from the electrical generating units in those states are contributing to air quality problems in North Carolina. Dominion has electrical generating units in six of the states. The issues raised by North Carolina are already being addressed by the EPA in current regulatory initiatives. The EPA is expected to respond to the petition in 2005. Given the highly uncertain outcome and timing of future action, if any, by the EPA on this issue, Dominion cannot predict the financial impact, if any, on its operations at this time.

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 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In July 2004, the EPA published new regulations that govern existing utilities that employ a cooling water intake structure, and whose flow levels exceed a minimum threshold. The EPA’s rule presents several compliance options. Dominion is evaluating information from certain of its existing power stations and expects to spend approximately $16 million over the next 5 years conducting studies and technical evaluations. Dominion cannot predict the outcome of the EPA regulatory process or state with any certainty what specific controls may be required.

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 Dominion Generation—Nuclear Decommissioning and Note 11 to the Consolidated Financial Statements.

Where You Can Find More Information About Dominion

Dominion files its annual, quarterly and current reports, proxy statements and other information with the 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.

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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 and in Item 1. Business.

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

Information detailing Dominion’s gas and oil operations presented below and on the following page includes the activities of the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc.(DTI), 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:

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, 2004 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:

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 2004, 2003 and 2002 was $4.14, $3.98 and $3.41, respectively. The respective average prices without hedging results per mcf of gas produced were $5.66, $5.02 and $3.04. The respective average sales prices realized for oil with hedging results were $24.99, $24.30 and $23.29 per barrel and the respective average prices without hedging results were $39.06, $29.82 and $24.45 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2004, 2003 and 2002 was $0.91, $0.80 and $0.60, respectively.

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Acreage

Gross and net developed and undeveloped acreage at December 31, 2004 was:

Net Wells Drilled in the Calendar Year

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

As of December 31, 2004, 133 gross (92 net) wells were in process of being drilled, 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, 2004, follows:

The number of productive wells includes 297 gross (117 net) multiple completion gas wells and 29 gross (12 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes.

Dominion’s Power Generation

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, Massachusetts, North Carolina, Ohio, Pennsylvania, Rhode Island, Virginia and West Virginia or through purchased power contracts when needed. The following table lists Dominion’s generating units and capability, including the generating plants acquired from USGen effective January 1, 2005.

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Dominion’s Power Generation

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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 imposed upon or agreed to by Dominion and its subsidiaries, 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, Future Issues and Other Matters in MD&A, and Note 22 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 Hidalgo 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 have filed a motion to dismiss.

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. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied the defendant’s motion to dismiss on jurisdictional grounds in January 2005. Discovery may begin in the matter in the spring of 2005.

In August 2004, DTI received a proposed Consent Order and Agreement (COA) from the Pennsylvania Department of Environmental Protection (PADEP) which would supersede a 1990 COA between the parties. The proposed COA would resolve groundwater contamination issues at several DTI compressor stations in Pennsylvania. The draft COA proposes penalties to be paid to PADEP and the Pennsylvania Department of Conservation and Natural Resources to resolve alleged violations. The proposed COA has not been accepted by DTI and is subject to ongoing negotiations with the agencies. Management believes that the ultimate resolution of the COA will not have a material effect on Dominion.

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

None.

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Executive Officers of the Registrant

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.

In May 2004, Dominion sold its telecommunications subsidiary, Dominion Telecom, Inc., to a third party and Dominion Telecom, Inc. became Elantic Telecom, Inc. Subsequent to the sale, Elantic Telecom, Inc. filed for protection under Chapter 11 of the U.S. Federal Bankruptcy code. Messrs. Johnson and Hetzer served as executive officers of Dominion Telecom, Inc. during the two years prior to its sale.

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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, 2004, there were approximately 170,000 registered shareholders, including approximately 79,000 certificate holders. The quarterly information concerning stock prices and dividends is incorporated by reference from Note 29 to the Consolidated Financial Statements. Restrictions on the payment of dividends by Dominion are discussed in Note 20 to the Consolidated Financial Statements.

During 2004, Dominion issued 111 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.

The following table presents registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock during the fourth quarter of 2004.

Item 6. Selected Financial Data

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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:

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 differ materially 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, differ materially 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 allows 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.

Dominion’s businesses are managed through four primary operating segments: Dominion Generation, Dominion Energy, Dominion Delivery and Dominion Exploration & Production. 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 generation mix 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 completed the acquisition of three USGen New England Inc. (USGen) power stations located in Massachusetts and Rhode Island during January 2005 and expects to complete the acquisition of the Kewaunee nuclear power plant located in northeastern Wisconsin in the first half of 2005.

Utility generation operations represent Dominion Generation’s primary source of revenue and cash flow. These operations are sensitive to external factors, primarily weather and fuel prices. 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 2010. Under capped rates, changes in Dominion Generation’s operating costs, particularly with respect to fuel, relative to costs used to establish the capped rates, will impact Dominion’s earnings. Dominion Generation has reduced costs by terminating certain long-term power purchase agreements.

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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 both short-term and long-term fixed-price sales and purchase contracts.

Variability in expenses for Dominion Generation relates primarily to the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.

As discussed in further detail below, as a result of the reorganization of the Dominion Energy Clearinghouse (Clearinghouse), Dominion Generation’s 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities performed by the Clearinghouse that were previously reported in the Dominion Energy segment.

Dominion Energy includes the following operations:

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

Revenue and cash flow provided by regulated electric and gas transmission operations and the LNG 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 and the demand for services. 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.

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenues and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities in the Dominion Generation segment.

Dominion Delivery includes Dominion’s electric and gas distribution systems and customer service operations as well as retail energy marketing operations. Electric distribution operations serve residential, commercial, industrial and governmental 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 operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest.

Revenue and cash flow provided by electric and gas distribution operations are based primarily on rates established by state regulatory authorities and state law. 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 cost 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 and 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). 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 maintains an active and ongoing 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.

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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 factors including drilling success, timing of development projects, as well as external factors such as the storm-related damage caused by Hurricane Ivan. 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 or decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related exploration and production service industry costs, while severance and property taxes vary based on 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:

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. Management has discussed the development, selection and disclosure of each of these with Dominion’s Audit Committee.

Accounting for derivative contracts at fair value

Dominion uses derivative contracts (primarily forward purchases and sales, swaps, options and futures) to buy and sell energy-related commodities and to manage its commodity and financial markets risks. Derivative contracts, with certain exceptions, are subject to fair value accounting and are reported on the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies.

Fair value of derivatives 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 use of statistical methods. 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. Dominion uses other option models when contracts involve different commodities or commodity locations and 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. If pricing information is not available from external sources, judgment is required to develop estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

For cash flow hedges of forecasted transactions, Dominion must estimate the future cash flows represented by the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for reclassification of gains or losses on cash flow hedges from accumulated other comprehensive income (loss) (AOCI) into earnings.

Use of estimates in goodwill impairment testing

As of December 31, 2004, Dominion reported $4.3 billion of goodwill on its Consolidated Balance Sheet, a significant portion of which resulted from the acquisition of CNG in 2000. Substantially all of this goodwill is allocated to Dominion’s Generation, Transmission, Delivery and Exploration & Production reporting units. In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if impairment indicators are present. The 2004 annual test did not result in the recognition of any impairment of goodwill, as the estimated fair values of Dominion’s reporting units exceeded their respective carrying amounts. During the fourth quarter of 2004, Dominion tested $72 million of goodwill allocated to the Clearinghouse reporting unit after management decided to exit certain energy trading activities and change the focus of the business, which resulted in a reduction of the unit’s expected future cash flows. This interim test indicated that no impairment existed and approximately $8 million of the unit’s goodwill was reallocated to other reporting units as of December 31, 2004 in connection with management’s reorganization of that business. In 2003 and 2002, impairment charges of $78 million and $13 million, respectively, were recognized as a result of interim tests conducted for certain DCI subsidiaries and Dominion’s telecommunications business.

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Dominion estimates the fair value of its reporting units by using a combination of discounted cash flow analyses, based on its internal five-year strategic plan, and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on subjective factors such as 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. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in management’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the 2004 annual test had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units, indicating no impairment was present.

Use of estimates in long-lived asset impairment testing

Impairment testing for an individual or group of long-lived assets or intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves management’s judgment in areas such as identifying circumstances indicating an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including the selection of an appropriate discount rate. Although cash flow estimates used by Dominion would be 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. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed.

During 2004, Dominion did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may exist. 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. Dominion sold its telecommunications business in 2004.

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 Dominion makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported on Dominion’s Consolidated Balance Sheets 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. Dominion did not recognize any new, significant AROs in 2004. In the future, if Dominion revises any assumptions used to calculate the fair value of existing AROs, Dominion will adjust the carrying amount of both the ARO liability and related long-lived asset. Dominion records accretion expense, increasing the ARO liability, with the passage of time. In 2004 and 2003, Dominion recognized $91 million and $86 million, respectively, of accretion expense, and expects to incur $95 million in 2005.

A significant portion of Dominion’s AROs relate to the future decommissioning of its nuclear facilities. At December 31, 2004, nuclear decommissioning AROs, which are reported in the Dominion Generation segment, totaled $1.4 billion, representing approximately 82% 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, 2004 for its AROs related to nuclear decommissioning would have been $269 million higher.

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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 and the anticipated rate of increase in health care costs and participant compensation, 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 expected long-term rates of return on plan assets, discount rates and medical cost trend rates 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:

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. Dominion calculated its pension cost using an expected return on plan assets assumption of 8.75% for 2004 and 2003, compared to 9.5% for 2002. Dominion calculated its 2004 other postretirement benefit cost using an expected return on plan assets assumption of 7.79%, compared to 7.78% and 7.82% for 2003 and 2002, respectively. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets and because other postretirement benefit activity, unlike the pension activity, is partially taxable.

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. Due to declines in bond yields and interest rates, Dominion reduced the discount rate used to calculate 2004 pension and other postretirement benefit cost to 6.25% compared to the 6.75% and 7.25% discount rates that it used to calculate 2003 and 2002 pension and other postretirement benefit cost, respectively.

The medical cost trend rate assumption is established based on analyses performed by a third party actuarial firm of various factors including the specific provisions of Dominion’s medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s medical cost trend rate assumption as of December 31, 2004 is 9% and is expected to gradually decrease to 5% in later years.

The following table illustrates the effect on cost of changing the critical actuarial assumptions discussed above, while holding all other assumptions constant:

In addition to the effects on cost, a 0.25% decrease in the discount rate would increase the projected pension benefit obligation by $122 million and would increase the accumulated postretirement benefit obligation by $45 million.

Accounting for regulated operations

Dominion’s accounting for its regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion is required to reflect the effect of rate regulation in its Consolidated Financial Statements. Specifically, Dominion’s regulated businesses record assets and liabilities that nonregulated companies would not report under accounting principles generally accepted in the United States of America. When it is probable that regulators will allow for the recovery of current costs through future rates charged to customers, Dominion defers these costs that otherwise would be expensed by nonregulated companies and recognizes regulatory assets in its financial statements. Likewise, Dominion recognizes regulatory liabilities in its financial statements when it is probable that regulators will require reductions in revenue associated with customer credits through future rates and when revenue is collected from customers for expenditures that are not yet incurred.

Management evaluates whether or not recovery of its regulatory assets through future regulated rates is probable and makes various assumptions in its analyses. 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, the regulatory asset will be written off and an expense will be recorded in the period such assessment is made. Management currently believes the recovery of its regulatory assets is probable. See Notes 2 and 14 to the Consolidated Financial Statements.

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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 the units-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. 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 pricing adjusted for cash flow hedges in place. 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. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a country.

Dominion’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. 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 that is used to calculate the ceiling could change in the near term.

The process to estimate reserves is imprecise, and estimates are subject to revision. In the last five years, revisions to Dominion’s estimates of proved developed and undeveloped reserves have averaged approximately 3% of the previous year’s estimate. If there is a significant variance in any of its estimates or assumptions in the future and revisions to the value of its proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2 and 28 to the Consolidated Financial Statements.

Income Taxes

Judgment is required in developing Dominion’s provision for income taxes, including the determination of deferred tax assets and any related valuation allowance. Dominion evaluates the probability of realizing its deferred tax assets on a quarterly basis by reviewing its forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies might affect the ultimate realization of deferred tax assets.

Newly Adopted Accounting Standards

During 2004 and 2003, Dominion was required to adopt several new accounting standards, the requirements of which are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The accounting standards adopted during 2003 affect the comparability of Dominion’s Consolidated Statements of Income. The following discussion is presented to provide an understanding of the impacts of those standards on that comparability.

FIN 46R

The adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affected the comparability of Dominion’s 2004 Consolidated Statement of Income to prior years as follows:

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 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

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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 related 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, 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 Statement of Income for 2002 was 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 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

Other

Dominion enters into buy/sell and related agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. Dominion typically enters into either a single or a series of buy/sell transactions in which it sells its crude oil production at the offshore field delivery point and buys similar quantities at Cushing, Oklahoma for sale to third parties. Dominion is able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, one of the largest crude oil markets in the world, versus restricting sales to a limited number of refinery purchasers in the Gulf of Mexico. These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counter party nonperformance risk.

Under the primary guidance of EITF Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, Dominion presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF is evaluating whether these types of transactions should be presented net in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on Dominion’s results of operations or cash flows. The portion of Dominion’s operating revenue related to buy/sell activity for the years 2004, 2003, and 2002 was 2.1%, 1.5%, and 1.6% respectively. Reported production volumes are not impacted, as only the initial sale of Dominion’s production is included in reported production volumes. It is estimated that approximately 55% of Dominion’s 2004 oil production was marketed through the use of one or more crude oil buy/sell agreements. See Note 2 to the Consolidated Financial Statements.

Results of Operations

Presented below is a summary of contributions by operating segments to net income:

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Overview

2004 vs. 2003

Dominion earned $3.78 per diluted share on net income of $1.2 billion, an increase of $2.78 per diluted share and $931 million. The per share amount includes approximately $0.14 of share dilution, reflecting an increase in the average number of common shares outstanding during 2004.

The combined net income contribution of Dominion’s primary operating segments increased $50 million during 2004. See Note 27 to the Consolidated Financial Statements for information about Dominion’s operating segments. The increase is primarily due to:

In addition to the higher contribution by the operating segments in 2004, the consolidated results include the impact of several specific items recognized in 2004 and reported in the Corporate and Other segment, including:

Additionally, the improved consolidated results reflect the impact of significant specific items recognized in 2003. These items were reported in the Corporate and Other segment and are discussed in further detail below.

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 $1.0 billion. 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. 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:

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Analysis of Consolidated Operations

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

An analysis of Dominion’s results of operations for 2004 compared to 2003 and 2003 compared to 2002 follows.

2004 vs. 2003

Operating Revenue

Regulated electric sales revenue increased 6% to $5.2 billion, primarily reflecting:

Regulated gas sales revenue increased 13% to $1.4 billion, largely resulting from a $198 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices and a $20 million increase resulting from the return of customers from Energy Choice programs, partially offset by an $87 million decrease associated with milder weather and lower industrial sales. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas, net expense.

Nonregulated electric sales revenue increased 11% to $1.2 billion, primarily reflecting the combined effects of:

Nonregulated gas sales revenue increased 21% to $2.1 billion, predominantly due to:

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Gas transportation and storage revenue increased 8% to $802 million, primarily reflecting:

Gas and oil production revenue increased 9% to $1.6 billion as a result of:

Other revenue increased 88% to $1.6 billion, largely due to:

These increases in other revenue were largely offset by corresponding increases in Liquids, pipeline capacity and other purchases expense. Other revenue for 2004 also includes $100 million from the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan.

Operating Expenses and Other Items

Electric fuel and energy purchases, net expense increased 30% to $2.2 billion, primarily reflecting:

Purchased gas, net expense increased 35% to $2.9 billion, principally resulting from:

Liquids, pipeline capacity and other purchases expense increased 115% to $1.0 billion, primarily reflecting a $348 million increase in the cost of coal purchased for resale, a $105 million increase in emission credits purchased and a $108 million increase related to purchases of oil by exploration and production operations, each of which are discussed in Other revenue.

Other operations and maintenance expense decreased 6% to $2.7 billion, resulting from:

These benefits were partially offset by the following charges and incremental expenses recognized in 2004:

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Depreciation, depletion and amortization expense (DD & A) increased 7% to $1.3 billion, largely due to incremental depreciation expense resulting from property additions, including those resulting from the consolidation of certain variable interest entities as a result of adopting FIN 46R at December 31, 2003.

Other taxes increased 9% to $519 million, primarily due to higher gross receipts taxes and higher severance and property taxes associated with increased commodity prices.

Other income increased to $186 million from a net loss of $40 million, primarily reflecting:

Income taxes—Dominion’s effective tax rate decreased 3.0% to 35.6% for 2004, reflecting an increase in the valuation allowance for 2003 with no comparable increase in 2004, partially offset by increases in 2004 in utility plant differences and other factors.

Loss from discontinued operations decreased to $15 million from $642 million, primarily reflecting the sale of Dominion’s discontinued telecommunications operations during May 2004 and the impact of the following charges recognized in 2003:

2003 vs. 2002

Operating Revenue

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

Regulated gas sales revenue increased 44% to $1.3 billion, primarily due to the combined impact of a $289 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices and a $79 million increase associated with comparably colder weather in the first and fourth quarters of 2003. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas, net expense.

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

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

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:

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Operating Expenses and Other Items

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