Dominion Energy (D) 10-K 2004 FY Annual report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2004

OR

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

For the transition period from                      to                     

Commission File Number 1-8489

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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

(804) 819-2000

(Registrant’s telephone number)

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

Title of Each Class	Name of Each Exchange on Which Registered
Common stock, no par value	New York Stock Exchange
8.75% Equity income securities, $50 par	New York Stock Exchange
8.4% Trust preferred securities, $25 par	New York Stock Exchange

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

None

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

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

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

The aggregate market value of the common 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.

(a) Portions of the 2005 Proxy Statement are incorporated by reference in Part III.

Dominion Resources, Inc.

Item Number		Page Number
Part I
1.	Business	1
2.	Properties	11
3.	Legal Proceedings	14
4.	Submission of Matters to a Vote of Security Holders	14
Executive Officers of the Registrant		15
Part II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	16
6.	Selected Financial Data	16
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
7A.	Quantitative and Qualitative Disclosures About Market Risk	46
8.	Financial Statements and Supplementary Data	47
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
9A.	Controls and Procedures	93
9B.	Other Information	93
Part III
10.	Directors and Executive Officers of the Registrant	94
11.	Executive Compensation	94
12.	Security Ownership of Certain Beneficial Owners and Management	94
13.	Certain Relationships and Related Transactions	94
14.	Principal Accountant Fees and Services	94
Part IV
15.	Exhibits and Financial Statement Schedules	95

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. SeeRegulation—State Regulationsfor 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). SeeRegulation—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). SeeRegulation—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. SeeDominion 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. SeeDominion 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:

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

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

• An LNG import and storage facility in Maryland;

• Certain gas production operations located in the Appalachian basin; and

• Clearinghouse, which is responsible for energy trading, marketing, hedging, arbitrage, and gas aggregation activities.

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’selectric 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. SeeState Regulationsand Federal Regulations inRegulation 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 alsoRegional Transmission Organization (RTO) inFuture Issues and Other Matters inItem 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. SeeRegulation—Federal RegulationsandRegulation—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.

Note: Includes the activities of the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included the Dominion Energy segment.

Bcfe = billion cubic feet equivalent

Mmcfe = million cubic feet equivalent

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. Thegeneration 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. SeeRegulation—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. SeeRegulation—State Regulationsand 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 beingperformed. 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.

	Surry		North Anna		Millstone
	Unit 1	Unit 2	Unit 1	Unit 2	Unit 1		Unit 2	Unit 3	Total
(millions)
NRC license expiration year	2032	2033	2038	2040	(1	)	2015	2025
Current cost estimate (2002 dollars)	$375	$368	$391	$363	$531		$486	$518	$3,032
Funds in trusts at December 31, 2004	313	308	256	242	279		315	310	2,023
2004 contributions to trusts	11	11	7	7	—		—	—	36

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

Corporate and Other

Dominion also has a Corporate and Other segment that includes:

• Dominion’s corporate, service company and other operations, including unallocated debt;

• The remaining assets of Dominion Capital, Inc., (DCI) a financial services subsidiary, which are being divested in accordance with a Securities and Exchange Commission (SEC) order;

• The net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004; and

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

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 ofa 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.

SeeKewaunee Power Plant, USGen Power Stationsand Restructuring of Contract with Non-Utility Generatorin Future Issues and Other MattersinMD&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:

• Lock in Dominion’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

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

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.

SeeRegulation—Federal Regulations—Federal Energy Regulatory CommissionandStatus ofElectric Deregulation in Virginia inFuture Issues and Other Mattersin 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. SeeStatus of Electric Deregulation in Virginiaabove 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 asregulatory 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, seeRTO inFuture Issues and Other Mattersin 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, seeEnvironmental Matters inFuture 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, seeDominion 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:

	2004		2003		2002
	Proved Developed	Total Proved	Proved Developed	Total Proved	Proved Developed	Total Proved
Proved gas reserves (bcf)
United States	3,680	4,904	3,553	4,801	3,549	4,458
Canada	96	99	453	568	486	640
Total proved gas reserves	3,776	5,003	4,006	5,369	4,035	5,098
Proved oil reserves (000 bbl)
United States	87,382	128,924	42,347	135,914	47,759	138,798
Canada	11,459	19,674	17,407	34,020	18,064	30,432
Total proved oil reserves	98,841	148,598	59,754	169,934	65,823	169,230
Total proved gas and oil reserves (bcfe)	4,369	5,894	4,364	6,388	4,430	6,113

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 grossreserves 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:

	2004	2003	2002
Gas production (bcf)
United States	327	346	346
Canada	44	50	53
Total gas production	371	396	399
Oil production (000 bbls)
United States	8,800	7,642	8,653
Canada	1,201	1,081	1,072
Total oil production	10,001	8,723	9,725
Total gas and oil production (bcfe)	431	449	458

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:

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
(thousands)
United States	4,223	2,559	3,208	1,766
Canada	731	471	577	483
Total	4,954	3,030	3,785	2,249

Net Wells Drilled in the Calendar Year

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

	2004	2003	2002
Exploratory:
United States
Productive	7	8	12
Dry	7	7	12
Total United States	14	15	24
Canada
Productive	34	10	1
Dry	7	1	1
Total Canada	41	11	2
Total Exploratory	55	26	26
Development:
United States
Productive	921	819	774
Dry	17	36	38
Total United States	938	855	812
Canada
Productive	36	31	61
Dry	3	10	11
Total Canada	39	41	72
Total Development	977	896	884
Total wells drilled (net):	1,032	922	910

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:

	Gross	Net
Gas wells
United States	24,698	16,457
Canada	644	408
Total gas wells	25,342	16,865
Oil wells
United States	1,004	517
Canada	426	163
Total oil wells	1,430	680

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

Plant	Location	Primary Fuel Type	Net Summer Capability (Mw)
Utility Generation
North Anna	Mineral, VA	Nuclear	1,628	(a)
Surry	Surry, VA	Nuclear	1,598
Mt. Storm	Mt. Storm, WV	Coal	1,569
Chesterfield	Chester, VA	Coal	1,234
Chesapeake	Chesapeake, VA	Coal	595
Clover	Clover, VA	Coal	441	(b)
Yorktown	Yorktown, VA	Coal	326
Bremo	Bremo Bluff, VA	Coal	227
Mecklenburg	Clarksville, VA	Coal	138
North Branch	Bayard, WV	Coal	74
Altavista	Altavista, VA	Coal	63
Southampton	Southampton, VA	Coal	63
Yorktown	Yorktown, VA	Oil	818
Possum Point	Dumfries, VA	Oil	786
Gravel Neck (CT)	Surry, VA	Oil	183
Darbytown (CT)	Richmond, VA	Oil	144
Chesapeake (CT)	Chesapeake, VA	Oil	144
Possum Point (CT)	Dumfries, VA	Oil	78
Northern Neck (CT)	Lively, VA	Oil	64
Low Moor (CT)	Covington, VA	Oil	60
Kitty Hawk (CT)	Kitty Hawk, NC	Oil	44
Remington (CT)	Remington, VA	Gas	580
Possum Point (CC)	Dumfries, VA	Gas	545	(c)
Chesterfield (CC)	Chester, VA	Gas	397
Possum Point	Dumfries, VA	Gas	322
Elizabeth River (CT)	Chesapeake, VA	Gas	312
Ladysmith (CT)	Ladysmith, VA	Gas	290
Bellmeade (CC)	Richmond, VA	Gas	230
Gordonsville Energy (CC)	Gordonsville, VA	Gas	217
Gravel Neck (CT)	Surry, VA	Gas	146
Darbytown (CT)	Richmond, VA	Gas	144
Bath County	Warm Springs, VA	Hydro	1,477	(d)
Gaston	Roanoke Rapids, NC	Hydro	225
Roanoke Rapids	Roanoke Rapids, NC	Hydro	99
Pittsylvania	Hurt, VA	Other	80
Other	Various	Various	15
			15,356	(e)
Non-utility Generation
Millstone	Waterford, CT	Nuclear	1,953	(f)
Kincaid	Kincaid, IL	Coal	1,158
Brayton Point	Somerset, MA	Coal	1,078	(g)
State Line	Hammond, IN	Coal	515
Salem Harbor	Salem, MA	Coal	312	(g)
Morgantown	Morgantown, WV	Coal	25	(h)
Brayton Point	Somerset, MA	Oil	435	(g)
Salem Harbor	Salem, MA	Oil	431	(g)
Fairless (CC)	Fairless Hills, PA	Gas	1,096	(c)
Elwood (CT)	Elwood, IL	Gas	704	(i)
Armstrong (CT)	Shelocta, PA	Gas	625	(c)
Troy (CT)	Luckey, OH	Gas	600	(c)
Manchester (CC)	Providence, RI	Gas	426	(g)
Pleasants (CT)	St. Mary’s, WV	Gas	313	(c)
Other	Various	Various	38
			9,709
Purchased Capacity			3,081	(j)
		Total Capacity	28,146

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

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

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

(c) Includes generating units which Dominion operates under leasing arrangements.

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

(e) Totals may not add due to rounding.

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

(g) Acquired January 1, 2005 from USGen New England, Inc. The Brayton Point Station also has four small generation units fired by oil-diesel (combined capacity 8 Mw) included inNon-Utility Generation-Other.

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

(i) Excludes 50 percent partnership interest owned by Peoples Energy.

(j) Purchase capacity includes generation from the Batesville facility. Dominion has decided to divest its interest in the long-term power tolling contract associated with this facility. SeeLong-Term Power Tolling Contract in MD&A for additional information.

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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.

SeeRegulation 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

Name and Age	Business Experience Past Five Years
Thos. E. Capps (69)	Chairman of the Board of Directors and Chief Executive Officer of Dominion from August 2000 to date; Chairman of the Board of Directors of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Directors and Chief Executive Officer of Consolidated Natural Gas Company from January 2004 to date; President of Dominion from August 2000 to December 2003; Chief Executive Officer and President of Consolidated Natural Gas Company from January 2000 to December 2003; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from January 2000 to August 2000; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from September 1995 to January 2000.
Thomas F. Farrell, II (50)	President and Chief Operating Officer of Dominion from January 2004 to date; President and Chief Operating Officer of Consolidated Natural Gas Company from January 2004 to date; Executive Vice President of Dominion from March 1999 to December 2003; President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to December 2003; Executive Vice President of Consolidated Natural Gas Company from January 2000 to December 2003; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2002.
Thomas N. Chewning (59)	Executive Vice President and Chief Financial Officer of Dominion from May 1999 to date; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 2000 to date.
Jay L. Johnson (58)	Executive Vice President of Dominion and President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to date; Senior Vice President, Business Excellence, Dominion Energy, Inc. from September 2000 to December 2002; Chief of Naval Operations, U.S. Navy, and member of the Joint Chiefs of Staff from 1996 until July 2000.
Duane C. Radtke (56)	Executive Vice President of Dominion and Consolidated Natural Gas Company from April 2001 to date; President of Devon Energy International from August 2000 to April 2001; Executive Vice President—Production of Santa Fe Snyder Corp. from May 1999 to August 2000.
Mary C. Doswell (46)	Senior Vice President and Chief Administrative Officer of Dominion from January 2003 to date; President and Chief Executive Officer of Dominion Resources Services, Inc. from January 2004 to date; President of Dominion Resources Services, Inc. from January 2003 to December 2003; Vice President—Billing and Credit of Virginia Electric and Power Company from October 2001 to December 2002; Vice President—Metering of Virginia Electric and Power Company from January 2000 to October 2001.
Paul D. Koonce (45)	Chief Executive Officer—Energy of Virginia Electric and Power Company from January 2004 to date; Chief Executive Officer—Transmission of Virginia Electric and Power Company from January 2003 to December 2003; Senior Vice President—Portfolio Management of Virginia Electric and Power Company from January 2000 to December 2002.
Mark F. McGettrick (47)	President and Chief Executive Officer—Generation of Virginia Electric and Power Company from January 2003 to date; Senior Vice President and Chief Administrative Officer of Dominion from January 2002 to December 2002; President of Dominion Resources Services, Inc. from October 2002 to January 2003; Senior Vice President—Customer Service and Metering of Virginia Electric and Power Company from January 2000 to December 2001.
Eva S. Hardy (60)	Senior Vice President—External Affairs & Corporate Communications of Dominion from May 1999 to date; Senior Vice President-External Affairs & Corporate Communications of Virginia Electric and Power Company from September 1997 to April 2000.
G. Scott Hetzer (48)	Senior Vice President and Treasurer of Dominion from May 1999 to date; Senior Vice President and Treasurer of Virginia Electric and Power Company and Consolidated Natural Gas Company from January 2000 to date.
James L. Sanderlin (63)	Senior Vice President—Law of Dominion from September 1999 to date; Senior Vice President—Law of Consolidated Natural Gas Company from January 2000 to date.
Steven A. Rogers (43)	Vice President, Controller and Principal Accounting Officer of Dominion and Consolidated Natural Gas Company and Vice President and Principal Accounting Officer of Virginia Electric and Power Company from June 2000 to date; Controller of Virginia Electric and Power Company from January 2000 to May 2000; Controller of Dominion Energy, Inc. from September 1998 to June 2000.

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

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.

Issuer Purchases of Equity Securities
Period	(a) Total Number of Shares (or Units) Purchased (1)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Program
10/1/04 – 10/31/04	—		—	N/A	N/A
11/1/04 – 11/30/04	—		—	N/A	N/A
12/1/04 – 12/31/04	84	$	66.41	N/A	N/A
Total	84	$	66.41	N/A	N/A

(1) Amounts are registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.

Item 6. Selected Financial Data

	2004(1)			2003(2)			2002		2001(3)		2000(4)
(millions, except per share amounts)
Operating revenue	$	13,972		$	12,078		$	10,218	$	10,558	$	9,246
Income from continuing operations before cumulative effect of changes in accounting principles		1,264			949			1,362		544		415
Loss from discontinued operations, net of taxes(5)		(15	)		(642	)		—		—		—
Cumulative effect of changes in accounting principles, net of taxes		—			11			—		—		21
Net income		1,249			318			1,362		544		436
Income from continuing operations before cumulative effect of changes in accounting principles per common share—basic		3.84			2.99			4.85		2.17		1.76
Net income per common share—basic		3.80			1.00			4.85		2.17		1.85
Income from continuing operations before cumulative effect of changes in accounting principles per common share—diluted		3.82			2.98			4.82		2.15		1.76
Net income per common share—diluted		3.78			1.00			4.82		2.15		1.85
Dividends paid per share		2.60			2.58			2.58		2.58		2.58
Total assets		45,446			43,546			39,239		36,044		30,449
Long-term debt(6)		15,507			15,776			12,060		12,119		10,101
Preferred securities of subsidiary trusts(6)		—			—			1,397		1,132		385

(1) Dominion’s 2004 results include a $112 million after-tax charge reflecting Dominion’s valuation of its interest in a long-term power tolling contract and $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges.

(2) Dominion’s 2003 results include $122 million of after-tax incremental restoration expenses associated with Hurricane Isabel. Also in 2003, Dominion adopted accounting standards that resulted in the recognition of the cumulative effect of changes in accounting principles. See Note 3 to the Consolidated Financial Statements.

(3) Dominion’s 2001 results include a $97 million after-tax charge representing exposure to the Enron Corp. bankrupcty and $68 million of after-tax charges associated with a senior management restructuring initiative.

(4) Dominion’s 2000 results include $198 million of after-tax restructuring and other acquisition-related costs resulting from the merger with Consolidated Natural Gas Company.

(5) Reflects the net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004. See Note 9 to the Consolidated Financial Statements.

(6) Upon adoption of Financial Accounting Standards Board Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, on December 31, 2003 with respect to special purpose entities, Dominion began reporting as long-term debt its junior subordinated notes held by five capital trusts, rather than the trust preferred securities issued by those trusts. See Note 3 to the Consolidated Financial Statements.

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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

• Introduction

• Accounting Matters

• Results of Operations

• Segment Results of Operations

• Selected Information—Energy Trading Activities

• Sources and Uses of Cash

• Future Issues and Other Matters

• Market Rate Sensitive Instruments and Risk Management

• Risk Factors and Cautionary Statements that May Affect Future Results

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 inRisk 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 concentratesits 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:

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

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

• A liquefied natural gas (LNG) import and storage facility in Maryland;

• Certain gas production operations located in the Appalachian basin; and

• Clearinghouse, which is responsible for energy trading, marketing, hedging, arbitrage and gas aggregation activities.

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. Asa 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:

• Dominion’s corporate, service company and other operations, including unallocated debt;

• The remaining assets of Dominion Capital, Inc. (DCI), a financial services subsidiary, which are being divested in accordance with a Securities and Exchange Commission (SEC) order;

• The net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004; and

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

Accounting Matters

Critical Accounting Policies and Estimates

Dominion has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. 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 andnear-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:

• Historical return analysis to determine expected future risk premiums;

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

• Expected inflation and risk-free interest rate assumptions; and

• Investment allocation of plan assets. Dominion’s strategic target asset allocation for its pension fund is 45% U.S. equity securities, 8% non-U.S. equity securities, 22% debt securities and 25% other, such as real estate and private equity investments.

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:

					Increase in Net Periodic Cost
Actuarial Assumption	Change in Assumption		Pension Benefits		Other Postretirement Benefits
			(millions)
Discount rate	(0.25	)%	$	13	$	6
Rate of return on plan assets	(0.25	)%		10		2
Healthcare cost trend rate	1	%		N/A		22

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:

• Dominion was required to consolidate certain variable interest lessor entities through which Dominion had financed and leased several new power generation projects, as well as its corporate headquarters and aircraft. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $644 million in net property, plant and equipment and deferred charges and $688 million of related debt. In 2004, Dominion’s Consolidated Statement of Income reflects depreciation expense on the net property, plant and equipment and interest expense on the debt associated with these entities, whereas in prior years it reflected as rent expense in other operations and maintenance expense, the lease payments to these entities.

• In addition, under FIN 46R, Dominion reports as long-term debt its junior subordinated notes held by five capital trusts, rather than the trust preferred securities issued by those trusts. As a result, in 2004 Dominion reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

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:

• Accretion of the AROs, including nuclear decommissioning, is reported in other operations and maintenance expense. Previously, expenses associated with the provision for nuclear decommissioning were reported in depreciation expense and in other income (loss); and

• Realized and unrealized earnings of trusts available for funding decommissioning activities at Dominion’s utility nuclear plants are recorded in other income (loss) and AOCI, as appropriate. Previously, as permitted by regulatory authorities, these earnings, along with an offsetting charge to expense, for the accretion of the decommissioning liability, were both reported in other income (loss).

D 2004/ Page 22

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:

• For derivative contracts not held for trading purposes that involve physical delivery of commodities, unrealized gains and losses and settlements on sales contracts are presented in revenue, while unrealized gains and losses and settlements on purchase contracts are reported in expenses; and

• Non-derivative energy-related contracts, previously subject to fair value accounting under prior accounting guidance, are recognized as revenue or expense on a gross basis at the time of contract performance, settlement or termination.

Other

Dominion enters into buy/sell and related agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquidmarketing 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:

Year Ended December 31,	2004						2003						2002
	Net Income			Diluted EPS			Net Income			Diluted EPS			Net Income			Diluted EPS
(millions, except per share amounts)
Dominion Generation	$	525		$	1.59		$	512		$	1.60		$	561		$	1.98
Dominion Energy		190			0.57			346			1.09			268			0.95
Dominion Delivery		466			1.41			453			1.42			422			1.49
Dominion Exploration & Production		595			1.80			415			1.30			380			1.34
Primary operating segments		1,776			5.37			1,726			5.41			1,631			5.76
Corporate and Other		(527	)		(1.59	)		(1,408	)		(4.41	)		(269	)		(0.94	)
Consolidated	$	1,249		$	3.78		$	318		$	1.00		$	1,362		$	4.82

D 2004/ Page 23

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:

• A lower contribution from regulated electric generation operations primarily due to the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. These higher fuel costs were partially offset by a reduction in capacity expenses due to the termination of certain long-term power purchase agreements and increased revenue due to favorable weather and customer growth;

• Net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;

• A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option positions and the effect of unfavorable price changes on electric trading margins, partially offset by favorable margins in coal trading and marketing;

• A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins; and

• A higher contribution from exploration and production operations due to favorable changes in the fair value of certain oil options, higher average realized prices for gas and oil and the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan. Results were also affected by the recognition of revenue in connection with deliveries under volumetric production payment (VPP) agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

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:

• A $112 million after-tax charge reflecting Dominion’s valuation of its interest in a long-term power tolling contract, which is subject to a planned divestiture in the first quarter of 2005, as aresult of its exit from certain energy trading activities. The charge is based on Dominion’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of Dominion’s interest in the contract;

• $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter;

• $61 million of after-tax charges related to Dominion’s investment in and planned divestiture of DCI assets;

• $43 million of net after-tax charges resulting from the termination of certain long-term power purchase agreements;

• $13 million of after-tax losses associated with Dominion’s telecommunications business, which was sold during 2004; partially offset by

• A $28 million after-tax benefit associated with the disposition of CNG International’s (CNGI) investment in Australian pipeline assets that were sold during 2004.

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:

• $750 million of after-tax losses associated with Dominion’s discontinued telecommunications business;

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

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

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

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

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

D 2004/ Page 24

Analysis of Consolidated Operations

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

Year Ended December 31,	2004			2003			2002
(millions)
Operating Revenue
Regulated electric sales	$	5,180		$	4,876		$	4,856
Regulated gas sales		1,422			1,258			876
Nonregulated electric sales		1,249			1,130			1,017
Nonregulated gas sales		2,082			1,718			778
Gas transportation and storage		802			740			705
Gas and oil production		1,636			1,503			1,334
Other		1,601			853			652
Operating Expenses
Electric fuel and energy purchases, net		2,162			1,667			1,447
Purchased electric capacity		587			607			691
Purchased gas, net		2,927			2,175			1,159
Liquids, pipeline capacity and other purchases		1,007			468			159
Other operations and maintenance		2,748			2,908			2,190
Depreciation, depletion and amortization		1,305			1,216			1,258
Other taxes		519			476			429
Other income (loss)		186			(40	)		103
Interest and related charges		939			975			945
Income tax expense		700			597			681
Loss from discontinued operations, net of taxes		(15	)		(642	)		—
Cumulative effect of changes in accounting principles, net of taxes		—			11			—

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:

• A $231 million increase due to the impact of a comparatively higher fuel rate on increased sales volumes. The rate increase resulted from the settlement of a fuel rate case in December 2003. This increase in regulated electric sales revenue was more than offset by an increase inElectric fuel and energy purchases, net expense;

• A $24 million increase associated with favorable weather;

• A $49 million increase from customer growth associated with new customer connections; and

• An $18 million increase due to lost revenue in 2003 as a result of outages caused by Hurricane Isabel.

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 inPurchased gas, net expense.

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

• A $181 million increase in revenue from nonregulated retail energy marketing operations reflecting increased volumes ($165 million) and higher prices ($16 million);

• A $97 million increase in revenue from merchant generation operations, largely due to the commencement of commercial operations at the 1,096 megawatt Fairless Energy power station(Fairless) in June 2004, partially offset by decreased revenue at certain other stations resulting from lower generation volumes;

• A $140 million decrease in revenue from energy trading and marketing activities reflecting decreased margins in electric trading due to unfavorable price movements; and

• A $19 million decrease due to the sale of CNGI’s generation assets in December 2003.

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

• A $279 million increase in revenue from producer services operations, reflecting higher prices ($157 million) and increased volumes ($122 million). This increase in nonregulated gas sales revenue was largely offset by a corresponding increase inPurchased gas, net expense;

• A $131 million increase in revenue from nonregulated retail energy marketing operations, reflecting increased volumes ($55 million) and higher prices ($76 million);

• A $61 million increase in revenue from sales of gas purchased by exploration and production operations to facilitate gas transportation and satisfy other agreements. This increase in nonregulated gas sales revenue was largely offset by a corresponding increase inPurchased gas, net expense; partially offset by

• A $108 million decrease in revenue from energy trading and marketing activities due to comparatively lower price volatility on natural gas option positions.

D 2004/ Page 25

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

• A $29 million increase due to the August 2003 reactivation of the Cove Point LNG facility, which was acquired by Dominion in September 2002; and

• A $27 million increase in revenue from gas transmission operations primarily reflecting increased transportation, storage, gathering and extraction revenues.

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

• A $37 million increase in revenue from oil production, largely reflecting higher volumes; and

• A $180 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by

• A $72 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

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

• A $384 million increase in coal sales revenue resulting from higher coal prices and increased sales volumes;

• A $120 million increase in sales of emissions credits reflecting higher prices and increased sales volumes; and

• A $109 million increase in revenue from sales of purchased oil by exploration and production operations.

These increases in other revenue were largely offset by corresponding increases inLiquids, 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:

• A $408 million increase related to regulated utility operations resulting from the combined effects of an increase in the fixed fuel rate and the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase also reflects higher generation volumes in the current year;

• A $162 million increase related to nonregulated retail energy marketing operations reflecting increased volumes ($153 million) and higher prices ($9 million);

• An $88 million increase related to merchant generation operations, largely due to the commencement of commercial operations at Fairless, partially offset by decreased fuel expense at certain other stations resulting from lower generation volumes; partially offset by

• A $163 million decrease related to energy trading and marketing activities.

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

• A $274 million increase associated with producer services operations, reflecting higher prices ($159 million) and increased volumes ($115 million), as discussed above inNonregulated gas sales revenue;

• A $130 million increase associated with regulated gas sales discussed above inRegulated gas sales revenue;

• An $83 million increase associated with nonregulated retail energy marketing operations, reflecting increased volumes ($56 million) and higher prices ($27 million);

• A $66 million increase from gas transmission operations due to increased gathering and extraction activities and higher gas usage; and

• A $58 million increase related to purchases of gas by exploration and production operations to facilitate gas transportation and satisfy other agreements, as discussed above inNonregulated gas sales revenue.

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 inOther revenue.

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

• A $113 million net benefit due to favorable changes in the fair value of certain oil options related to exploration and production operations. During 2004, Dominion effectively settled certain oil options not designated as hedges by entering into offsetting option positions that had the effect of preserving approximately $120 million in mark-to-market gains attributable to favorable changes in time value; and

• The impact of the following charges recognized in 2003:

• $197 million of incremental restoration expenses associated with Hurricane Isabel;

• $108 million of charges from asset and goodwill impairments associated with DCI’s financial services operations;

• $105 million of charges associated with the termination of certain long-term power purchase agreements;

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

• A $60 million goodwill impairment associated with the purchase of the remaining interest in the telecommunications joint venture, Dominion Fiber Ventures, LLC (DFV), held by another party;

• A $28 million charge related to severance costs for workforce reductions; and

• A $22 million impairment related to CNGI’s generation assets that were sold in December 2003.

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

• A $184 million charge related to the valuation of Dominion’s interest in a long-term power tolling contract;

• $96 million of losses related to the discontinuance of hedge accounting for certain oil hedges resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter;

• $72 million of charges associated with the impairment of retained interests from mortgage securitizations and venture capital and other equity investments held by DCI;

• $71 million of net expenses associated with the termination of certain long-term power purchase agreements;

D 2004/ Page 26

• An approximate $60 million increase in costs related to gas and oil production activities;

• An $18 million increase in reliability expenses associated with utility operations primarily due to increased tree-trimming;

• A $13 million increase related to salaries, wages and benefits resulting from a $60 million increase in pension and medical benefits and a $46 million increase due to wage increases and other factors, partially offset by an $89 million decrease in incentive-based compensation expense due to failure to meet targeted earnings goals; and

• $10 million of expenses associated with the sale of natural gas and oil assets in British Columbia, Canada.

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:

• A $61 million increase resulting from net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;

• A $23 million benefit associated with the disposition of CNGI’s investment in Australian pipeline assets that were sold during 2004; and

• The impact of the following charges recognized in 2003, which did not recur in 2004:

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

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

• A $62 million impairment of CNGI’s investment in Australian pipeline assets held for sale.

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:

• Impairment of network assets and related inventories of $566 million. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile. In addition, Dominion increased the valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting in a $48 million increase in deferred income tax expense; and

• Telecommunications operating losses of $28 million.

2003 vs. 2002

Operating Revenue

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

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

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

• A $103 million decrease associated with milder weather.

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 inPurchased gas, net expense.

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

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

• A $76 million increase in revenue from nonregulated retail energy marketing operations, primarily as a result of customer growth, including the acquisition of new customers previously served by other energy companies during 2003; and

• A $43 million decrease in revenue from energy trading and marketing activities due to unfavorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3, partially offset by increased margins.

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

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

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

• A $208 million increase in revenue from energy trading and marketing activities due to higher margins, favorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3.

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:

• A $49 million increase in coal sales revenue;

D 2004/ Page 27

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

• $94 million of emissions credit sales that began in 2003;

• A $26 million increase in sales of extracted products; and

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

Operating Expenses and Other Items

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

• A $154 million increase associated with energy trading and marketing activities and nonregulated retail energy marketing operations, primarily resulting from higher volumes purchased and the reclassification of certain purchase contracts due to the implementation of EITF 02-3; and

• A $68 million increase related to regulated utility operations, including $42 million associated with rate recovery in 2003 revenue and the recognition of $14 million of previously deferred fuel costs not recovered under the 2003 settlement of the Virginia jurisdictional fuel rate case.

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

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

• A $647 million increase associated with producer services operations, reflecting higher prices ($459 million) and higher volumes ($188 million); and

• A $363 million increase associated with regulated gas operations discussed above inRegulated gas sales revenue.

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

Other operations and maintenance expense rose 33% to $2.9 billion, primarily reflecting the following specific items:

• $197 million of incremental restoration expenses associated with Hurricane Isabel;

• $108 million of asset and goodwill impairments associated with DCI’s financial services operations;

• $105 million of expenses associated with the termination of certain long-term power purchase contracts used in electric utility operations;

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

• A $60 million goodwill impairment associated with the purchase of the remaining interest in the telecommunications joint venture held by another party;

• $86 million of accretion expense for AROs;

• An $87 million increase in expense resulting from a decrease in net pension credits and an increase in other postretirement benefit costs; partially offset by

• A $15 million decrease in expenses associated with nuclear outages for refueling.

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

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

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

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

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

• A $32 million increase in net realized losses (including investment income) associated with nuclear decommissioning trust fund investments.

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

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

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

• Impairment of network assets and related inventories of $566 million. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile. In addition, Dominion increased the valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting in a $48 million increase in deferred income tax expense; and

• Telecommunications operating losses of $28 million.

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

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

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

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

• A $27 million after-tax loss (FIN 46R).

D 2004/ Page 28

Outlook—Dominion

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

Growth factors include:

• Continued growth in utility customers;

• Reduced electric capacity expenses, resulting from the termination of long-term power purchase agreements;

• Oil production growth, reflecting a full year of Devils Tower and Front Runner operations;

• A contribution from the operations of three USGen power stations acquired in January 2005;

• Higher contribution from Cove Point operations due to expansion of the facility; and

• A contribution from the Kewaunee nuclear power plant, expected to be acquired in the first half of 2005.

The growth factors will be partially offset by:

• Higher expected Virginia jurisdictional fuel expenses;

• A lower contribution from Millstone resulting from an additional refueling outage;

• Higher expected operating expenses for gas and oil production;

• An increase in incentive-based compensation expense if earnings targets are met; and

• Increased interest expense.

Based on these projections, Dominion estimates that cash flow from operations will increase in 2005, as compared to 2004. Management believes this increase will provide sufficient cash flow to maintain or grow Dominion’s current dividend to common shareholders.

Segment Results of Operations

Dominion Generation

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet as well as coal and emissions trading and marketing activities.

	2004		2003		2002
(millions, except EPS)
Net income contribution	$	525	$	512	$	561
EPS contribution	$	1.59	$	1.60	$	1.98
Electricity supplied (million mwhrs)		112		105		101

mwhrs = megawatt hours

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s operating results:

2004 vs. 2003

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Fuel expenses in excess of rate recovery	$	(115	)	$	(0.36	)
Regulated electric sales:
Weather		10			0.03
Customer growth		20			0.06
Nuclear decommissioning trust performance		38			0.12
Coal trading and marketing		31			0.10
Capacity expenses		36			0.11
Other		(7	)		(0.02	)
Share dilution		—			(0.05	)
Change in net income contribution	$	13		$	(0.01	)

Dominion Generation’s net income contribution increased $13 million, primarily reflecting:

• Higher fuel expenses incurred by the regulated utility operations due to the elimination of fuel deferral accounting which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase in fuel expenses also reflects higher generation volumes;

• Higher regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers, comparably favorable weather, lost revenue in 2003 due to outages associated with Hurricane Isabel, and the impact of the economy and other factors;

• Net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;

• A higher contribution from coal trading and marketing primarily due to higher coal prices and increased sales volumes; and

• Reduced purchased power capacity expenses due to the termination of long-term power purchase agreements in connection with the purchase of the related nonutility generating facilities.

2003 vs. 2002

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Revenue reallocation	$	(57	)	$	(0.20	)
Regulated electric sales:
Weather		(42	)		(0.15	)
Customer growth		23			0.08
Merchant generation margins		18			0.06
Capacity expenses		29			0.10
Fuel settlement		(9	)		(0.03	)
Utility outages		(13	)		(0.04	)
Other		2			0.01
Share dilution		—			(0.21	)
Change in net income contribution	$	(49	)	$	(0.38	)

Dominion Generation’s net income contribution decreased $49 million, primarily reflecting:

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

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

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

• A higher contribution from merchant generation operations due to fewer outage days at the Millstone Power Station in 2003 and a full year’s contribution from gas-fired generating units placed into service during 2002;

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

• Recognition of previously deferred fuel costs in connection with the 2003 Virginia fuel rate settlement; and

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

D 2004/ Page 29

Dominion Energy

Dominion Energy includes Dominion’s electric transmission, natural gas transmission pipeline and storage businesses, an LNG facility, certain natural gas production, energy trading and marketing operations and producer services which includes aggregation of gas supply and related wholesale activities.

	2004		2003		2002
(millions, except EPS)
Net income contribution	$	190	$	346	$	268
EPS contribution	$	0.57	$	1.09	$	0.95
Gas transportation throughput (bcf)		704		614		597

bcf = billion cubic feet

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s operating results:

2004 vs. 2003

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Energy trading and marketing	$	(116	)	$	(0.37	)
Economic hedges		(12	)		(0.04	)
Electric transmission revenue		(15	)		(0.05	)
Other		(13	)		(0.04	)
Share dilution		—			(0.02	)
Change in net income contribution	$	(156	)	$	(0.52	)

Dominion Energy’s net income contribution decreased $156 million, primarily reflecting:

• A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option positions and the effect of unfavorable price changes on electric trading margins;

• A decrease attributable to unfavorable price movements in 2004 on the economic hedges of Dominion Exploration & Production gas production described inSelected Information—Energy Trading Activities;

• Lower electric transmission revenue primarily due to decreased wheeling revenue resulting from lower contractual volumes and unfavorable market conditions; and

• Other factors including losses from asset and price risk management activities related to intersegment marketing.

2003 vs. 2002

			Increase (Decrease)
	Amount		EPS
(millions, except EPS)
Energy trading and marketing	$	12	$	0.05
Economic hedges		33		0.12
Electric transmission margins		11		0.04
Cove Point operations		9		0.03
Revenue reallocation		7		0.02
Other		6		0.02
Share dilution		—		(0.14	)
Change in net income contribution	$	78	$	0.14

Dominion Energy’s net income increased $78 million, primarily reflecting:

• An increase in the contribution of energy trading and marketing activities, reflecting an increase in margins on settled contracts, partially offset by a decrease in net mark-to-market gains on derivative contracts;

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

• An increase in electric transmission margins due to customer growth and other factors, partially offset by the impact of unfavorable weather;

• A contribution from the Cove Point LNG facility due to its reactivation in August 2003; and

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

Dominion Delivery

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

	2004		2003		2002
(millions, except EPS)
Net income contribution	$	466	$	453	$	422
EPS contribution	$	1.41	$	1.42	$	1.49
Electricity delivered (million mwhrs)		78		75		75
Gas throughput (bcf)		371		373		364

Presented below, on an after-tax basis, are the key factors impacting Dominion Delivery’s operating results:

2004 vs. 2003

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Weather	$	(5	)	$	(0.02	)
Customer growth—utility operations		9			0.03
Nonregulated retail energy marketing operations		32			0.10
Reliability expenses		(11	)		(0.03	)
Other		(12	)		(0.04	)
Share dilution		—			(0.05	)
Change in net income contribution	$	13		$	(0.01	)

Dominion Delivery’s net income contribution increased $13 million, primarily reflecting:

• A decrease in regulated gas sales due to comparably milder winter weather in regulated gas service territories; partially offset by an increase in regulated electric sales resulting from comparably favorable weather in regulated electric service territories;

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

• A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins;

D 2004/ Page 30

• Higher reliability expenses, primarily due to increased tree trimming; and

• Other factors, including a decrease in net pension credits.

2003 vs. 2002

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Revenue reallocation	$	50		$	0.18
Customer growth—utility operations		10			0.03
Weather		(5	)		(0.02	)
Income taxes		(9	)		(0.03	)
Other		(15	)		(0.05	)
Share dilution		—			(0.18	)
Change in net income contribution	$	31		$	(0.07	)

Dominion Delivery’s net income contribution increased $31 million, primarily reflecting:

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

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

• A decrease in regulated electric sales due to comparably milder weather in electric utility service territories, offset by an increase in regulated gas sales due to comparably colder weather in gas utility service territories;

• A decrease in net pension credits and an increase in other postretirement benefit costs; and

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

Dominion Exploration & Production

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

	2004		2003		2002
(millions, except EPS)
Net income contribution	$	595	$	415	$	380
EPS contribution	$	1.80	$	1.30	$	1.34
Gas production (bcf)		359		384		385
Oil production (million bbls)		10		9		10
Average realized prices with hedging results:(1)
Gas (per mcf)(2)	$	4.09	$	3.95	$	3.40
Oil (per bbl)		24.98		24.29		23.28
Average prices without hedging results:
Gas (per mcf)(2)		5.65		4.99		3.03
Oil (per bbl)		39.07		29.82		24.44
DD&A (per mcfe)	$	1.30	$	1.20	$	1.12
Average production (lifting) cost (per mcfe)(3)		0.92		0.80		0.60

bbl = barrel

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

(1) Excludes the effects of the economic hedges discussed underSelected Information—Energy Trading Activities.

(2) Excludes $223 million and $43 million of revenue recognized in 2004 and 2003, respectively, under the VPP agreements described in Note 12 to the Consolidated Financial Statements.

(3) The exclusion of volumes produced and delivered under the VPP agreements accounted for approximately 75% of the increase from 2003 to 2004 and 8% of the increase from 2002 to 2003.

Presented below, on an after-tax basis, are the key factors impacting Dominion Exploration & Production’s operating results:

2004 vs. 2003

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
VPP revenue	$	114		$	0.36
Business interruption insurance		61			0.19
Gas and oil—production		(55	)		(0.17	)
Gas and oil—prices		49			0.15
Operations and maintenance		26			0.08
DD&A—production		13			0.04
DD&A—rate		(30	)		(0.09	)
Other		2			0.01
Share dilution		—			(0.07	)
Change in net income contribution	$	180		$	0.50

Dominion Exploration & Production’s net income contribution increased $180 million, primarily reflecting:

• Recognition of revenue in connection with deliveries under the VPP agreements;

• The recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan;

• Lower gas production reflecting the sale of mineral rights under the VPP agreements;

• Higher oil production reflecting production related to the deepwater Gulf of Mexico Devils Tower project;

• Higher average realized prices for gas and oil;

• Lower operations and maintenance expenses, primarily due to favorable changes in the fair value of certain oil options, partially offset by an increase in production costs; and

• A higher rate for depreciation, depletion and amortization, primarily reflecting higher industry finding and development costs, increased acquisition costs and the effect of the reduction in reserves attributable to the VPP transactions.

2003 vs. 2002

				Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Gas and oil—prices	$	133		$	0.47
Gas and oil—production		(18	)		(0.06	)
VPP revenue		27			0.10
DD&A—rate		(22	)		(0.08	)
DD&A—production		3			0.01
Operations and maintenance		(41	)		(0.15	)
Severance taxes		(18	)		(0.06	)
Income taxes		(20	)		(0.07	)
Other		(9	)		(0.03	)
Share dilution		—			(0.17	)
Change in net income contribution	$	35		$	(0.04	)

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

• Higher average realized prices for gas and oil;

• Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production. Lower gas production, reflecting the

D 2004/ Page 31

sale of mineral rights under a VPP agreement and declines in Rocky Mountain and Michigan production, was largely offset by increased Gulf of Mexico gas production;

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

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

• Higher severance taxes, resulting from higher gas and oil revenue associated with higher commodity prices; and

• Higher income taxes, primarily reflecting the expiration of Section 29 production tax credits beginning in 2003, partially offset by a reduction in tax rates applied to deferred taxes associated with Canadian operations.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:

	2004			2003			2002
(millions, except EPS amounts)
Specific items attributable to operating segments	$	(224	)	$	(220	)	$	7
DCI operations		(82	)		(96	)		14
Telecommunications operations(1)		(13	)		(750	)		(26	)
Other corporate operations		(208	)		(342	)		(264	)
Total net expense		(527	)		(1,408	)		(269	)
Earnings per share impact	$	(1.59	)	$	(4.41	)	$	(0.94	)

(1) $15 million and $642 million are classified as discontinued operations in 2004 and 2003, respectively.

Specific Items Attributable to Operating Segments—2004

During 2004, Dominion reported net expenses of $224 million in the Corporate and Other segment attributable to its operating segments. The net expenses in 2004 primarily related to the impact of the following:

• A $184 million charge ($112 million after-tax) related to the valuation of Dominion’s interest in a long-term power tolling contract, attributable to Dominion Generation;

• $96 million of losses ($61 million after-tax) related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter, attributable to Dominion Exploration & Production; and

• $71 million of charges ($43 million after-tax) resulting from the termination of certain long-term power purchase contracts, attributable to Dominion Generation.

Specific Items Attributable to Operating Segments—2003

During 2003, Dominion reported net expenses of $220 million in the Corporate and Other segment attributable to its operating segments. The net expenses in 2003 primarily related to the impact of the following:

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

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

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

• Statement 133 Implementation Issue No. C20: a $75 million after-tax loss attributable to Dominion Generation; and

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

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

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

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

• $26 million of severance costs ($15 million after-tax) for workforce reductions during the first quarter of 2003, attributable to:

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

• Dominion Energy ($2 million after-tax);

• Dominion Delivery ($4 million after-tax); and

• Dominion Exploration & Production ($1 million after-tax).

DCI Operations

DCI recognized a net loss of $82 million in 2004; a decrease of $14 million as compared to 2003. The decrease primarily resulted from a $20 million reduction in after-tax charges associated with asset impairments.

DCI recognized a net loss of $96 million in 2003, compared to net income of $14 million in 2002. The loss resulted primarily from the recognition of the following charges recognized in 2003: $108 million ($70 million after-tax) of impairments related to retained interests from securitizations, goodwill and other investments, and the sale of financial assets; and a $26 million valuation allowance established on certain deferred tax assets.

Telecommunications Operations

Dominion’s loss from its discontinued telecommunications business decreased $737 million to $13 million in 2004, primarily as a result of its sale in May 2004 and the impact of certain charges recognized during 2003 which are discussed below.

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

• $566 million associated with the impairment of network assets and related inventories. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile;

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

D 2004/ Page 32

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

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

• $41 million of after-tax operating losses.

Other Corporate Operations

The net expenses associated with other corporate operations for 2004 decreased by $134 million as compared to 2003, predominantly due to a $28 million after-tax benefit associated with the disposition of CNGI’s investment in Australian pipeline assets that were sold during 2004, lower interest expense and the impact in 2003 of the charges discussed below.

The net expenses associated with other corporate operations for 2003 increased by $78 million as compared to 2002, primarily reflecting:

• A $22 million ($14 million after-tax) impairment related to CNGI’s generation assets that were sold in December 2003;

• A $62 million ($55 million after-tax) impairment of CNGI’s investment in Australian pipeline assets held for sale; and

• A $16 million ($10 million after-tax) loss representing the cumulative effect of adopting FIN 46R.

Selected Information—Energy Trading Activities

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

In addition, the Clearinghouse held a portfolio of financial derivative instruments to manage Dominion’s price risk associated with a portion of its anticipated sales of 2004 natural gas production that had not been considered in the hedging activities of the Dominion Exploration & Production segment (economic hedges). In 2004, Dominion Energy recognized a net loss of $22 million on the economic hedges. As anticipated, Dominion Exploration & Production sold sufficient volumes of natural gas in 2004 at market prices, which, when combined with the settlement of the economic hedges, resulted in a range of prices for those sales contemplated by the risk management strategy.

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.

A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes, including the economic hedges, during 2004 follows:

	Amount
(millions)
Net unrealized gain at December 31, 2003	$	33
Contracts realized or otherwise settled during the period		15
Net unrealized gain at inception of contracts initiated during the period		—
Changes in valuation techniques		—
Other changes in fair value		98
Net unrealized gain at December 31, 2004	$	146

The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes, including the economic hedges at December 31, 2004, is summarized in the following table based on the approach used to determine fair value and contract settlement or delivery dates:

	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less than 1 year		1-2 years		2-3 years		3-5 years		In Excess of 5 years	Total
(millions)
Actively quoted(1)	$	105	$	15	$	5		—	—	$	125
Other external sources(2)		—		14		5	$	2	—		21
Models and other valuation methods		—		—		—		—	—		—
Total	$	105	$	29	$	10	$	2	—	$	146

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

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

Sources and Uses of Cash

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

At December 31, 2004, Dominion had cash and cash equivalents of $389 million with $2.4 billion of unused capacity under its credit facilities. For long-term financing needs, amounts available for debt or equity offerings under currently effective shelf registrations totaled $2.5 billion at February 1, 2005.

D 2004/ Page 33

Operating Cash Flows

As presented on Dominion’s Consolidated Statements of Cash Flows, net cash flows from operating activities were $2.8 billion, $2.4 billion and $2.4 billion for the years ended December 31, 2004, 2003 and 2002, respectively. Dominion’s management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares.

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

• Cost-recovery shortfalls due to capped base and fuel rates in effect in Virginia for its regulated electric utility;

• The collection of business interruption insurance proceeds associated with the recovery of delayed gas and oil production due to Hurricane Ivan;

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

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

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

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

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

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

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

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy trading, marketing and hedging activities and sales of gas and oil production. Presented below is a summary of Dominion’s gross and net credit exposure as of December 31, 2004 for these activities. Dominion calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	784	$	23	$	761
Non-investment grade(2)		36		—		36
No external ratings:
Internally rated—investment grade(3)		299		—		299
Internally rated—non-investment grade(4)		150		—		150
Total	$	1,269	$	23	$	1,246

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s) . The five largest counterparty exposures, combined, for this category represented approximately 16% of the total gross credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 14% of the total gross credit exposure.

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

Investing Cash Flows

During 2004, 2003 and 2002, investing activities resulted in net cash outflows of $1.3 billion, $3.4 billion, and $4.0 billion respectively. Significant investing activities for 2004 included:

• $1.5 billion of capital expenditures for the construction and expansion of generation facilities, environmental upgrades, purchase of nuclear fuel, and construction and improvements of gas and electric transmission and distribution assets;

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

• $729 million of proceeds from sales of gas and oil mineral rights and properties;

• $490 million for the purchase of securities and $466 million for the sale of securities, primarily related to investments held in nuclear decommissioning trusts; and

• $132 million in advances and $806 million in reimbursements related to the Fairless generation project in Pennsylvania.

Financing Cash Flows and Liquidity

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

During 2004, net cash used in financing activities was $1.3 billion. During 2003 and 2002, net cash flows from financing activities were $853 million and $1.3 billion, respectively. During 2004, the Dominion Companies issued long-term debt (net of exchanged debt) and common stock totaling approximately $1.7 billion. The proceeds were used primarily to repay debt.

Credit Facilities and Short-Term Debt

The Dominion Companies use short-term debt, primarily commercial paper, to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. At December 31, 2004, the Dominion Companies had committed lines of credit totaling $3.75 billion. Although there were no loans outstanding, these lines of credit support commercial paper borrowings and letter of credit issuances. At December 31,

D 2004/ Page 34

2004, the Dominion Companies had the following commercial paper and letters of credit outstanding and capacity available under credit facilities:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Three-year revolving credit facility(1)	$	1,500
Three-year revolving credit facility(2)		750
Total joint credit facilities		2,250	$	573	$	183	$	1,494
Three-year CNG credit facility(3)		1,500		—		555		945
Totals	$	3,750	$	573	$	738	$	2,439

(1) The $1.5 billion three-year revolving credit facility was entered into in May 2004 and terminates in May 2007. This credit facility can also be used to support up to $500 million of letters of credit.

(2) The $750 million three-year revolving credit facility was entered into in May 2002 and can also be used to support up to $200 million of letters of credit. Dominion expects to renew this facility prior to its maturity in May 2005.

(3) The $1.5 billion three-year credit facility is used to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements under its gas and oil hedging program. The facility was entered into in August 2004 and terminates in August 2007.

In addition to the facilities above, in June and August of 2004, CNG entered into two $100 million letter of credit agreements that terminate in June 2007 and August 2009, respectively. Additionally, in October 2004, CNG entered into three letter of credit agreements totaling $700 million that terminate in April 2005 and are not expected to be renewed. These five agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by CNG in its risk management strategies for gas and oil production. At December 31, 2004, outstanding letters of credit under these agreements totaled $900 million.

Dominion’s financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2004, the total amount of commercial paper outstanding was $573 million and the total amount of letter of credit issuances was $738 million, leaving approximately $2.4 billion available for issuance. The Dominion Companies are required to pay minimal annual commitment fees to maintain the credit facilities.

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

All of the credit facilities include a defined maximum total debt to total capital ratio. As of December 31, 2004, the calculated ratio for the Dominion Companies, pursuant to the terms of the agreements, was as follows:

Company	Maximum Ratio	Actual Ratio(1)
Dominion Resources, Inc.	65%	55%
Virginia Power	60%	50%
CNG	60%	51%

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

These provisions apply separately to Dominion Resources, Inc., Virginia Power and CNG. If any one of the Dominion Companies or any of that specific company’s material subsidiaries fail to make payment on various debt obligations in excess of $25 million, the lenders could require that respective company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any defaults on indebtedness by CNG or any of its material subsidiaries would not affect the lenders’ commitment to Virginia Power. Similarly, any defaults on indebtedness by Virginia Power or any of its material subsidiaries would not affect the lenders’ commitment to CNG. However, any default by either CNG or Virginia Power would also affect in like manner the lenders’ commitment to Dominion Resources, Inc. under the joint credit agreements.

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

Long-Term Debt

During 2004, Dominion Resources, Inc. and its subsidiaries issued the following long-term debt:

Type	Principal		Rate	Maturity	Issuing Company
	(millions)
Senior notes	$	200	5.20%	2016	Dominion Resources, Inc.
Senior notes		100	Variable	2006	Dominion Resources, Inc.
Senior notes		400	5.00%	2014	CNG
Senior notes		177	4.92%	2009	Dominion Canada Finance Corporation
Total long-term debt issued	$	877

During 2004, Dominion Resources, Inc. and its subsidiaries repaid $1.3 billion of long-term debt securities.

In 2004, Dominion exchanged $219 million of outstanding contingent convertible senior notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash upon conversion.

In 2004, in connection with the acquisition of certain generating facilities, Virginia Power assumed $109 million of private placement bonds and $104 million of pollution control bonds. Virginia Power exchanged $106 million of its 2004 Series A 7.25% senior notes due 2017 for $106 million of the private placement bonds. The senior notes have the same financial terms as the private placement bonds, but are registered securities.

Common Stock

During 2004, Dominion issued 14 million shares of common stock and received proceeds of $839 million. Of this amount, 7 million shares and proceeds of $413 million resulted from the settlement of stock purchase contracts associated with Dominion’s 2000 issuance of equity-linked debt securities. The remainder of the shares issued and proceeds received were through Dominion Direct^® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options. In 2005, Dominion Direct^® and the Dominion employee savings plans will purchase Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued.

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In July 1998, Dominion was authorized by its Board of Directors to repurchase up to the lesser of 16.5 million shares, or $650 million of its outstanding common stock. As of December 31, 2004, Dominion had repurchased approximately 12 million shares for $537 million, with its last repurchase occurring in 2002. In February 2005, in order to recognize the significant increase in the size of the company and the market value of its common stock since the time of the previous authorization, Dominion’s Board of Directors superseded this authority, with new authority, to repurchase up to the lesser of 25 million shares or $2.0 billion of Dominion’s outstanding common stock.

Forward Equity Transaction

In September 2004, Dominion entered into a forward equity sale agreement (forward agreement) with Merrill Lynch International (MLI), as forward purchaser, relating to 10 million shares of Dominion’s common stock. The forward agreement provides for the sale of two tranches of Dominion common stock, each with stated maturity dates and settlement prices. In connection with the forward agreement, MLI borrowed an equal number of shares of Dominion’s common stock from stock lenders and, at Dominion’s request, sold the borrowed shares to J.P. Morgan Securities Inc. (JPM) under a purchase agreement among Dominion, MLI and JPM. JPM subsequently offered the borrowed shares to the public. Dominion accounted for the forward agreement as equity at its initial fair value but did not receive any proceeds from the sale of the borrowed shares.

The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then existing market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. Except in specified circumstances or events that would require physical share settlement, Dominion may elect to settle the forward agreement by means of a physical share, cash or net share settlement and may also elect to settle the agreement in whole, or in part, earlier than the stated maturity date at fixed settlement prices. Under either a physical share or net share settlement, the maximum number of shares deliverable by Dominion under the terms of the forward agreement was limited to the 10 million shares specified in the two tranches. Assuming gross share settlement of all shares under the forward agreement, Dominion would have received aggregate proceeds of approximately $644 million, based on maturity forward prices of $64.62 per share for the 2 million shares included in the first tranche and $64.34 per share for the 8 million shares included in the second tranche.

However, Dominion elected to cash settle the first tranche in December 2004 and made a payment to MLI for $5.8 million, representing the difference between Dominion’s share price and the applicable forward sale price, multiplied by the 2 million shares. Dominion recorded the settlement payment as a reduction to common stock in its Consolidated Balance Sheet. Additionally, Dominion elected to cash settle 3 million shares of the second tranche in February 2005 and made a payment to MLI for $17.4 million.

The remaining 5 million shares of the second tranche must be settled by May 17, 2005. If gross share settlement were elected for the remainder of the second tranche at its maturity date, Dominion would receive aggregate proceeds of approximately $322 million and would deliver 5 million of its common shares. In the event any or allof the proceeds are not needed, Dominion has the option to either cash settle or net share settle the remainder of the second tranche of the forward agreement in whole, or in part, and may elect settlement earlier than the stated maturity date. If Dominion elects to cash or net share settle any portion of the remainder of the second tranche, the payment is based on the difference between Dominion’s share price and the applicable forward sale price for the second tranche, multiplied by the number of shares being settled.

If, at December 31, 2004, Dominion had elected a cash settlement of the 8 million shares in the second tranche, Dominion would have owed MLI $28 million, of which, $18 million would have represented settlement of the 5 million shares remaining in the second tranche after the February 2005 settlement. If, at the time of cash settlement, Dominion’s current share price were lower than the forward sale price, Dominion would receive a payment from MLI. For every dollar increase (decrease) in the value of Dominion’s stock, the value of the settlement of the shares remaining in the second tranche from MLI’s perspective would increase (decrease) by $5 million.

Dominion expects to use proceeds received from physical share settlements under the remainder of the second tranche of the forward agreement to fund part of the cost of acquiring the Kewaunee nuclear power plant in Wisconsin for $220 million (which is expected to close in the first half of 2005) and the acquisition of three electric generating stations from USGen for $642 million (which closed on January 1, 2005).

Amounts Available under Shelf Registrations

At February 1, 2005, Dominion Resources, Inc., Virginia Power, and CNG had approximately $941 million, $670 million, and $900 million, respectively, of available capacity under currently effective shelf registrations. Securities that may be issued under these shelf registrations, depending upon the registrant, include senior notes (including medium-term notes), subordinated notes, first and refunding mortgage bonds, trust preferred securities, preferred stock and common stock.

In addition, Dominion Resources, Inc., under a separate shelf registration has 6.9 million shares of common stock available exclusively for delivery against stock purchase contracts associated with outstanding equity-linked debt securites.

In December 2004, the SEC granted Dominion’s request for financing authorization under the 1935 Act through December 31, 2007. This authority replaced the previous financing authority granted by the SEC, which expired December 31, 2004.

Credit Ratings

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

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are

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subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for the Dominion Companies are most affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable, such as major acquisitions.

Credit ratings for the Dominion Companies as of February 1, 2005 follow:

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

As of February 1, 2005, Moody’s maintains a negative outlook for its ratings of CNG and Standard & Poor’s maintains a negative outlook for its ratings of Dominion Resources, Inc., Virginia Power and CNG.

Generally, a downgrade in an individual company’s credit rating would not restrict its ability to raise short-term and long-term financing so long as its credit rating remains “investment grade,” but it would increase the cost of borrowing. Dominion works closely with both Standard & Poor’s and Moody’s with the objective of maintaining its current credit ratings. As discussed inRisk Factors and Cautionary Statements That May Affect Future Results,in order to maintain its current ratings, Dominion may find it necessary to modify its business plans and such changes may adversely affect its growth and earnings per share.

Debt Covenants

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

• The timely payment of principal and interest;

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

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

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

• Limitations on liens.

Dominion monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2004, there were no events of default under the Dominion Companies’ covenants.

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Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

Dominion is party to numerous contracts and arrangements obligating Dominion to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion is a party as of December 31, 2004. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt and interest payable. The majority of current liabilities will be paid in cash in 2005.

	Less than 1 Year		1-3 years		3-5 years		More than 5 years		Total
(millions)
Long-term debt(1)	$	1,368	$	3,948	$	1,807	$	9,810	$	16,933
Interest payments(2)		974		1,682		1,346		7,339		11,341
Leases		133		225		184		365		907
Purchase obligations(3):
Purchased electric capacity for utility operations		509		968		858		3,103		5,438
Fuel used for utility operations		691		673		245		51		1,660
Fuel used for nonregulated operations		48		76		70		—		194
Production handling		56		105		61		27		249
Pipeline transportation and storage		82		118		85		95		380
Energy commodity purchases for resale(4)		527		131		3		—		661
Other		352		254		35		5		646
Other long-term liabilities(5):
Financial derivatives- commodities(4)		1,084		858		1		—		1,943
Other contractual obligations		25		32		14		32		103
Total cash payments	$	5,849	$	9,070	$	4,709	$	20,827	$	40,455

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

(2) Does not reflect Dominion's ability to defer distributions related to its junior subordinated notes payable to affiliated trusts.

(3) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

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

(5) Excludes regulatory liabilities, AROs and employee benefit plan obligations that are not contractually fixed as to timing and amount. See Notes 14, 15 and 21 to the Consolidated Financial Statements. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year.

Dominion’s planned capital expenditures during 2005 are expected to total approximately $3.6 billion, which includes the cost of acquiring USGen and certain non-utility generating facilities. For 2006, planned capital expenditures are expected to be approximately $3.0 billion. These expenditures include construction and expansion of generation facilities, environmental upgrades, construction improvements and expansion of gas and electric transmission and distribution assets, purchases of nuclear fuel and expenditures to explore for and develop natural gas and oil properties. Dominion expects to fund its capital expenditures with cash from operations and a combination of sales of securities and short-term borrowings.

Dominion may choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings.

Use of Off-Balance Sheet Arrangements

Leasing Arrangements

Dominion has an agreement with a voting interest entity (lessor) to lease the Fairless power station in Pennsylvania, which began commercial operations in June 2004. During construction, Dominion acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs advanced to the lessor. Project costs totaled $898 million at December 31, 2004. Dominion will make annual lease payments of $53 million. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.

Benefits of this arrangement include:

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

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

Securitizations of Mortgages and Loans

As of December 31, 2004, Dominion held $335 million of retained interests from securitizations of mortgage and commercial loans completed in prior years. Dominion did not securitize or originate any loans in 2004. Investors in the securitization trusts have no recourse to Dominion’s other assets for failure of debtors to repay principal and interest on the underlying loans when due. Therefore, Dominion’s exposure to any future losses from this activity is limited to its investment in retained interests.

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Forward Equity Transaction

As described inFinancing Cash Flows and Liquidity—Forward Equity Transaction, in September 2004, Dominion entered into a forward equity sale agreement relating to 10 million shares of Dominion’s common stock. The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then current market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. If Dominion decides it does not need any or all of the proceeds, it has the option to cash settle or net share settle the forward sale agreement in whole, or in part.

Future Issues and Other Matters

Status of Electric Deregulation in Virginia

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

Retail choice has been available to all of Dominion’s Virginia regulated electric customers since January 1, 2003. Dominion has also separated its generation, distribution and transmission functions through the creation of divisions. Virginia codes of conduct ensure that Dominion’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 by three and one-half years, to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

• Lock in Dominion’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

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

The risk of fuel factor-related cost recovery shortfalls may adversely impact Dominion’s 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 electric generation. If gas and oil prices rise, it is expected that Dominion’s exploration and production operations will earn greater profits that will help 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 charges 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 by agreeing to market-based pricing upon return to the incumbent electric utility. In January 2005, Dominion filed compliance plans for both of these programs.

RTO

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

In October 2004, the FERC issued an order conditionally approving Dominion’s application to join PJM. In its order, FERC determined that: (i) Dominion’s proposed transmission rate treatment must conform to a regional transmission rate design, and (ii) Dominion must assess all available evidence and determine whether the requested deferral of expenditures related to the establishment and operation of an RTO should be recorded as a regulatory asset until the end of the Virginia retail rate cap period. 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 Dominion’s service territory upon its integration into PJM.

Dominion has made filings with both the Virginia Commission and North Carolina Utilities Commission (North Carolina

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Commission) requesting authorization to become a member of PJM. In October 2004, Dominion filed a settlement agreement with the Virginia Commission resolving most of the issues raised by interested parties in the proceeding, and hearings were held to address the remaining issues. The Virginia Commission approved Dominion’s application to join PJM in November 2004 subject to the terms and conditions of the settlement agreement. The North Carolina Commission evidentiary hearing was held in January 2005. Dominion cannot predict the outcome of this matter at this time.

North Carolina Rate Matter

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.

Dominion Transmission, Inc. (DTI) Rate Matter

At the request of the Public Service Commission of the State of New York (PSCNY), DTI has engaged in negotiations with PSCNY regarding the potential for a prospective reduction of DTI ‘s transportation and storage service rates to address concerns about the level of DTI’s earnings. As a result of these negotiations, DTI and PSCNY have reached an agreement in principle that establishes parameters for a potential rate settlement, which must be finalized by DTI and its customers. DTI is negotiating with its customers to reach a possible settlement agreement. The settlement parameters envision reduced rates to DTI’s customers and a five-year moratorium on future changes to DTI’s transportation and storage service rates. If DTI is able to reach an agreement with its customers in the first quarter of 2005, FERC approval of a filed settlement could be obtained in the second quarter of 2005.

Recovery of Stranded Costs

Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not reasonably be expected to be recovered in a competitive market. At December 31, 2004, Dominion’s exposure to potentially stranded costs included long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. Dominion believes capped electric retail rates and, where applicable, wires charges will provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Recovery of Dominion’s potentially stranded costs remains subjectto numerous risks even in the capped-rate environment. These include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs and recovery of certain other items.

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

Changes to Cost Structure—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 until December 31, 2010, unless capped rates are terminated earlier under the Virginia Restructuring Act. The generation-related cash flows provided by the Virginia Restructuring Act are intended to compensate Dominion for continuing to provide generation services and to allow Dominion to incur costs to restructure such operations during the transition period. As a result, during the transition period, Dominion’s earnings may increase to the extent that it can reduce operating costs for its utility generation-related operations. Conversely, the same risks affecting the recovery of Dominion’s stranded costs, discussed above, may also adversely impact its cost structure during the transition period. Accordingly, Dominion could realize the negative economic impact of any such adverse event. In addition to managing the cost of its generation-related operations, Dominion may also seek opportunities to sell available electric energy and capacity to customers beyond its electric utility service territory. Using cash flows from operations during the transition period, Dominion may further alter its cost structure or choose to make additional investment in its business.

The capped rates were derived from rates established as part of the 1998 Virginia rate settlement and do not provide for specific recovery of particular generation-related expenditures, except for

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certain regulatory assets. To the extent that Dominion manages its operations to reduce its overall operating costs below those levels included in the capped rates, Dominion’s earnings may increase. Since the enactment of the Virginia Restructuring Act, Dominion has been reviewing its cost structure to identify opportunities to reduce the annual operating expenses of its generation-related operations. In the period 2001 through 2004, Dominion negotiated the termination of several long-term power purchase agreements that is expected to reduce capacity payments in 2005 by $179 million.

Common Stock Dividend Increase

In July 2004, Dominion announced that its fourth-quarter dividend payable December 20, 2004, would be increased by 2 cents per share to 66.5 cents per share. In February 2005, the quarterly dividend rate increased again from 66.5 cents per share to 67 cents per share for an annual rate in 2005 of $2.68 per share. Dominion’s expected cash flow and earnings should enable it to make future annual increases when its board of directors deems it financially prudent. Common stock dividends are declared on a quarterly basis by the board of directors.

Statoil ASA (Statoil) Agreement

In June 2004, Dominion executed 20-year contracts with Statoil for the increased capacity planned for its Cove Point LNG facility and related gas transmission services. Under the terms of the agreements, Statoil will purchase firm LNG tanker discharge services and related transportation service from Cove Point, as well as downstream firm transportation and storage services from DTI. Plans call for increasing the Cove Point storage tank capacity to 14.6 bcf and the plant’s deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. To provide the transmission services, Dominion also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the Mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed in service in 2008.

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, Dominion recovered such costs arising from regulated electric operations through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period ending December 31, 2010, in excess of the level currently included in the Virginia jurisdictional electric retail rates, Dominion’s results of operations will decrease. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations and recovery, if any, through the generation component of rates will be dependent upon the market price of electricity. Dominion also may seek recovery through regulatedrates for environmental expenditures related to regulated gas transmission and distribution operations.

Environmental Protection and Monitoring Expenditures

Dominion incurred approximately $132 million, $113 million and $123 million of expenses (including depreciation) during 2004, 2003 and 2002, respectively, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $203 million in 2005 and $215 million in 2006. In addition, capital expenditures related to environmental controls were $94 million, $210 million and $280 million for 2004, 2003 and 2002, respectively. These expenditures are expected to be approximately $123 million for 2005 and $207 million for 2006. The 2005 and 2006 amounts include planned expenditures for the newly acquired USGen electric generating facilities.

Clean Air Act Compliance

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

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

• NO_X emission limitations applicable during the ozone season months of May through September and on an annual average basis.

Implementation of projects to comply with SO₂ and NO_X limitations are ongoing and will be influenced by changes in the regulatory environment, availability of allowances, various state and federal control programs and emission control technology. In response to these requirements, Dominion estimates it will make capital expenditures at its affected generating facilities (including the newly acquired electric generating facilities from USGen) of approximately $700 million during the period 2005 through 2009 for SO₂ and NO_x emission control equipment.

Other EPA Matters

In relation to a Notice of Violation received by Virginia Power in 2000 from the EPA, Dominion entered into a Consent Decree settlement in 2003 and committed to improve air quality. Dominion has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia. Dominion continues to commit to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree.

Other

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

In October 2003, the EPA and the Massachusetts Department of Environmental Protection jointly issued a new National Pollutant Discharge Elimination System permit for the USGen, Brayton Point Power Station. The new permit contained conditions that in effect

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require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. In November 2003, an appeal was filed with the EPA Environmental Appeals Board and the Division of Administrative Law Appeals in Massachusetts. Until the appeals process is completed, the outcome cannot be predicted.

Future Environmental Regulations

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 Dominion’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, significant additional expenditures may be required.

The U.S. Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% over the next 10 years. Several legislative proposals that include provisions seeking to impose mandatory reductions of greenhouse gas emissions are under consideration in the United States Congress. Several Northeast states have already or are considering the imposition of mandatory carbon dioxide (CO₂) reductions through the development of a regional cap-and-trade program. The cost of compliance with the Protocol or other mandatory greenhouse gas reduction obligations could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue, Dominion cannot predict the financial impact of future climate change actions on its operations at this time.

Other Matters

USGen Power Stations

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. These assets will be included in the Dominion Generation operating segment. Dominion did not acquire any of the facilities’ debt in the transaction and plans to finance the acquisition with a combination of debt and equity.

Kewaunee Nuclear Power Plant

During the fourth quarter of 2003, Dominion announced an agreement with Wisconsin Public Service Corporation, a subsidiary ofWPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WP&L), a subsidiary of Alliant Energy Corporation, to purchase the Kewaunee nuclear power plant , located in northeastern Wisconsin. Under terms of the agreement, the aggregate purchase price is $220 million in cash, including $35 million for nuclear fuel. Dominion will sell 100% of the facility’s output to WPS (59%) and WP&L (41%) under a power purchase agreement that expires in 2013. In November 2004, the Public Service Commission of Wisconsin voted to deny the sale. The transaction had received all other applicable regulatory approvals. During January 2005, the commission granted Dominion’s request for a rehearing of the case. If approved by the commission, the transaction is expected to close in the first half of 2005. If approved, Kewaunee would be included in the Dominion Generation operating segment.

Restructuring of Contract with Non-Utility Generator

In February 2005, Dominion paid $42 million in cash and assumed $62 million of 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. The transaction is part of an ongoing program that seeks to achieve competitive cost structures at Dominion’s utility generation business and is expected to reduce annual capacity payments by $18 million. The purchase price for the acquisition was allocated to the assets and liabilities acquired based on their estimated fair values as of the date of acquisition. In connection with the termination of the agreement, Dominion expects to record an after-tax charge of approximately $46 million.

Long-Term Power Tolling Contract

In the fourth quarter of 2004, Dominion recorded a $112 million after-tax charge related to its interest in a long-term power tolling contract with a 551 megawatt combined cycle facility located in Batesville, Mississippi. Dominion decided to divest its interest in the long-term power tolling contract in connection with its reconsideration of the scope of certain activities of the Clearinghouse, including those conducted on behalf of Dominion’s business segments, and its ongoing strategy to focus on business activities within the MAIN to Maine region. The charge is based on Dominion’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of Dominion’s interest in the contract in the first quarter of 2005.

Future Acquisitions

In 2005, Dominion expects to focus on managing its existing assets rather than acquiring new assets through mergers or acquisitions. Exceptions would include acquiring a Midwest, Northeast or Mid-Atlantic nuclear station; replacing gas and oil reserves through acquisitions if more cost effective than drilling; or continuing to buy out uneconomic long-term power purchase agreements.

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Market Rate Sensitive Instruments and Risk Management

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

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

Commodity Price Risk—Trading Activities

As part of its strategy to market energy and to manage related risks, Dominion manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. Dominion uses established policies and procedures to manage the risks associated with these price fluctuations and uses derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $23 million and $56 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2004 and 2003, respectively.

Commodity Price Risk—Non-Trading Activities

Dominion manages the price risk associated with purchases and sales of natural gas, oil and electricity by using derivative commodity instruments including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of Dominion’s non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange. A hypothetical 10% unfavorable change in market prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $576 million and $424 million as of December 31, 2004 and December 31, 2003, respectively.

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

Interest Rate Risk

Dominion manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. Dominion also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2004, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $10 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2003, would have resulted in a decrease in annual earnings of approximately $6 million.

In addition, Dominion, through subsidiaries, retains ownership of mortgage investments, including subordinated bonds and interest-only residual assets retained from securitizations of mortgage loans originated and purchased in prior years. Note 26 to the Consolidated Financial Statements discusses the impact of changes in value of these investments.

Foreign Currency Exchange Risk

Dominion’s Canadian natural gas and oil exploration and production activities are relatively self-contained within Canada. As a result, Dominion’s exposure to foreign currency exchange risk for these activities is limited primarily to the effects of translation adjustments that arise from including that operation in its Consolidated Financial Statements. Dominion’s management monitors this exposure and believes it is not material. In addition, Dominion manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, Dominion’s exposure to foreign currency risk is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $13 million and $19 million in the fair value of currency forward contracts held by Dominion at December 31, 2004 and 2003, respectively.

Investment Price Risk

Dominion is subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. Dominion recognized a net realized gain (net of investment income) on nuclear decommissioning trust investments of $51 million in 2004 and a net realized loss (net of investment income) of $10 million in 2003. Dominion recorded, in AOCI, net unrealized gains on decommissioning trust investments of $84 million and $263 million in 2004 and 2003, respectively.

Dominion also sponsors employee pension and other postretirement benefit plans that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in Dominion’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans. Dominion’s pension plans experienced net realized and unrealized gains of $453 million and $627 million in 2004 and 2003, respectively.

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Risk Management Policies

Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on credit policies and the December 31, 2004 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

Risk Factors and Cautionary Statements That May Affect Future Results

Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; inherent risk in the operation of nuclear facilities; fluctuations in energy-related commodities prices and the effect these could have on Dominion’s earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are subject to changing regulatory structures; changes to regulated gas and electric rates recovered by Dominion; receipt of approvals for and the timing of the closing dates for pending acquisitions; realization of expected business interruption insurance proceeds; the transfer of control over electric transmission facilities to a regional transmission organization; board approval of future dividends; political and economic conditions (including inflation and deflation); and completing the divestiture of investments held by DCI. Other more specific risk factors are as follows:

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

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

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

Dominion is exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia for its regulated electric utility. Under the Virginia Restructuring Act, as amended in April 2004, Dominion’s base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain unchanged until December 31, 2010 unless modified or terminated consistent with the Virginia Restructuring Act. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates periods, Dominion remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs. In addition, under the 2004 amendments to the Virginia fuel factor statute, Dominion’s current Virginia fuel factor provisions are locked-in until the earlier of July 1, 2007 or the termination of capped rates by order of the Virginia State Corporation Commission.

The amendments provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting. As a result of the locked-in fuel factor and the uncertainty of what the one-time adjustment will be, Dominion is exposed to fuel price risk. This risk includes exposure to increased costs of fuel, including the energy portion of certain purchased power costs.

Under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations is open to competition and resulting uncertainty. Under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations in Virginia is open to competition and is no longer subject to cost-based regulation. To date, the competitive market has been slow to develop. Consequently, it is difficult to predict the pace at which the competitive environment will evolve and the

D 2004/ Page 44

extent to which Dominion will face increased competition and be able to operate profitably within this competitive environment.

Dominion’s merchant power business is operating in a challenging market which could adversely affect its results of operations and future growth. The success of Dominion’s approximately 9,700-megawatt merchant power business depends upon favorable market conditions as well as its ability to find buyers willing to enter into power purchase agreements at prices sufficient to cover operating costs. Dominion attempts to manage these risks by entering into both short-term and long-term fixed price sales and purchase contracts. However, depressed spot and forward wholesale power prices, high fuel and commodity costs and excess capacity in the industry could result in lower than expected revenues in Dominion’s merchant power business.

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

The use of derivative instruments could result in financial losses and liquidity constraints. Dominion uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, Dominion could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Dominion uses financial derivatives to hedge future sales of its gas and oil production. These hedge arrangements generally include margin requirements that require Dominion to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit limits. When commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity to cover these margin requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results.

For additional information concerning derivatives and commodity-based trading contracts, seeMarket Rate Sensitive Instruments and Risk Management and Notes 2 and 8 to the Consolidated Financial Statements.

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

Dominion’s exploration and production business is dependent on factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of its assets. Factors that may affect Dominion’s financial results include weather that damages or causes the shutdown of its gas and oil producing facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and Dominion’s ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.

Short-term market declines in the prices of natural gas and oil could adversely affect Dominion’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) in a given country at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

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

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Changing rating agency requirements could negatively affect Dominion’s growth and business strategy. As of February 1, 2005, Dominion’s senior unsecured debt is rated BBB+, negative outlook, by Standard & Poor’s and Baa1, stable outlook, by Moody’s. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, Dominion may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings per share. A reduction in Dominion’s credit ratings or the credit ratings of its Virginia Power and CNG subsidiaries by either Standard & Poor’s or Moody’s could increase Dominion’s borrowing costs and adversely affect operating results and could require it to post additional margin in connection with some of its trading and marketing activities.

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

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on the operations of Dominion. Implementation of Dominion’s growth strategy is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect Dominion’s business and future financial condition.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

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Item 8. Financial Statements and Supplementary Data

Index

	Page No.
Management’s Annual Report on Internal Control over Financial Reporting	48
Reports of Independent Registered Public Accounting Firm	49
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002	51
Consolidated Balance Sheets at December 31, 2004 and 2003	52
Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income at December 31, 2004, 2003 and 2002 and for the years then ended	54
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002	55
Notes to Consolidated Financial Statements	56

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Management’s Annual Report on Internal Control over Financial Reporting

Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for its financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Management maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that Dominion’s and its subsidiaries’ assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

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

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2004 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for management’s report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2004, Dominion makes the following assertion:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

On December 31, 2003, Dominion adopted Financial Accounting Standards Board Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, for its interests in special purpose entities, referred to as SPEs. As a result, Dominion has included in its consolidated financial statements certain SPEs. The Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these SPEs. As these SPEs are owned by unrelated parties, Dominion does not have the authority to dictate or modify, and therefore could not assess the internal controls in place at these entities. Management’s conclusion regarding the effectiveness of Dominion’s internal control does not extend to the internal controls of these SPEs.

Management evaluated Dominion’s internal control over financial reporting as of December 31, 2004. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2004.

The independent registered public accounting firm that audited the financial statements has issued an attestation report on Dominion’s assessment of the internal control over financial reporting.

February 28, 2005

D 2004/ Page 48

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, common shareholders’ equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2005, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

D 2004/ Page 49

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited management’s assessment, included in paragraphs 5-9 of the accompanying Management’s Annual Report on Internal Control over Financial Reporting, that Dominion Resources, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from their assessment the internal control over financial reporting at certain special purpose entities consolidated under Financial Accounting Standards Board Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities. The Company’s Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these special purpose entities. As these special purpose entities are owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore could not assess the internal controls in place at these entities. Accordingly, our audit did not include the internal control over financial reporting at those special purpose entities. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our reports dated February 28, 2005, expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

D 2004/ Page 50

Consolidated Statements of Income

Year Ended December 31,	2004			2003			2002
(millions, except per share amounts)
Operating Revenue	$	13,972		$	12,078		$	10,218
Operating Expenses
Electric fuel and energy purchases, net		2,162			1,667			1,447
Purchased electric capacity		587			607			691
Purchased gas, net		2,927			2,175			1,159
Liquids, pipeline capacity and other purchases		1,007			468			159
Other operations and maintenance		2,748			2,908			2,190
Depreciation, depletion and amortization		1,305			1,216			1,258
Other taxes		519			476			429
Total operating expenses		11,255			9,517			7,333
Income from operations		2,717			2,561			2,885
Other income (loss)		186			(40	)		103
Interest and related charges:
Interest expense		811			849			826
Interest expense—junior subordinated notes payable to affiliated trusts		112			—			—
Distributions—mandatorily redeemable trust preferred securities		—			111			103
Subsidiary preferred dividends		16			15			16
Total interest and related charges		939			975			945
Income before income taxes		1,964			1,546			2,043
Income tax expense		700			597			681
Income from continuing operations before cumulative effect of changes in accounting principles		1,264			949			1,362
Loss from discontinued operations (net of income tax benefit of $4 and expense of $15, in 2004 and 2003, respectively)		(15	)		(642	)		—
Cumulative effect of changes in accounting principles (net of income taxes of $7)		—			11			—
Net Income	$	1,249		$	318		$	1,362
Earnings Per Common Share—Basic:
Income from continuing operations before cumulative effect of changes in accounting principles	$	3.84		$	2.99		$	4.85
Loss from discontinued operations		(0.04	)		(2.02	)		—
Cumulative effect of changes in accounting principles		—			.03			—
Net income	$	3.80		$	1.00		$	4.85
Earnings Per Common Share—Diluted:
Income from continuing operations before cumulative effect of changes in accounting principles	$	3.82		$	2.98		$	4.82
Loss from discontinued operations		(0.04	)		(2.01	)		—
Cumulative effect of changes in accounting principles		—			.03			—
Net income	$	3.78		$	1.00		$	4.82
Dividends paid per common share	$	2.60		$	2.58		$	2.58

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

D 2004/ Page 51

Consolidated Balance Sheets

At December 31,	2004			2003
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	389		$	126
Customer accounts receivable (net of allowance of $43 and $51)		2,585			2,308
Other accounts receivable		320			828
Inventories:
Materials and supplies		328			296
Fossil fuel		180			154
Gas stored		385			420
Derivative assets		1,713			1,436
Deferred income taxes		594			240
Prepayments		157			202
Other		471			531
Total current assets		7,122			6,541
Investments
Available for sale securities		335			413
Nuclear decommissioning trust funds		2,023			1,872
Other		810			802
Total investments		3,168			3,087
Property, Plant and Equipment
Property, plant and equipment		38,663			37,107
Accumulated depreciation, depletion and amortization		(11,947	)		(11,257	)
Total property, plant and equipment, net		26,716			25,850
Deferred Charges and Other Assets
Goodwill, net		4,298			4,300
Regulatory assets		788			832
Prepaid pension cost		1,947			1,939
Derivative assets		705			402
Other		702			595
Total deferred charges and other assets		8,440			8,068
Total assets	$	45,446		$	43,546

D 2004/ Page 52

At December 31,	2004			2003
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,368		$	1,252
Short-term debt		573			1,452
Accounts payable, trade		1,984			1,929
Accrued interest, payroll and taxes		578			619
Derivative liabilities		2,858			2,082
Other		695			750
Total current liabilities		8,056			8,084
Long-Term Debt
Long-term debt		14,078			14,336
Junior subordinated notes payable to affiliated trusts		1,429			1,440
Total long-term debt		15,507			15,776
Deferred Credits and Other Liabilities
Deferred income taxes		5,424			4,614
Deferred investment tax credits		75			92
Asset retirement obligations		1,705			1,651
Derivative liabilities		1,583			1,185
Regulatory liabilities		610			587
Other		803			762
Total deferred credits and other liabilities		10,200			8,891
Total liabilities		33,763			32,751
Commitments and Contingencies (see Note 22)
Subsidiary Preferred Stock Not Subject To Mandatory Redemption		257			257
Common Shareholders’ Equity
Common stock—no par(1)		10,888			10,052
Other paid-in capital		92			61
Retained earnings		1,442			1,054
Accumulated other comprehensive loss		(996	)		(629	)
Total common shareholders’ equity		11,426			10,538
Total liabilities and shareholders’ equity	$	45,446		$	43,546

(1) 500 million shares authorized; 340 million shares and 325 million shares outstanding at December 31, 2004 and December 31, 2003, respectively.

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

D 2004/ Page 53

Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income

	Common Stock					Other Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Amount
(millions)
Balance at December 31, 2001	265		$	7,129		$	28		$	922		$	289		$	8,368
Comprehensive income:
Net income										1,362						1,362
Net deferred losses on derivatives—hedging activities, net of $345 tax benefit													(663	)		(663	)
Unrealized losses on investment securities, net of $41 tax benefit													(68	)		(68	)
Foreign currency translation adjustments													6			6
Minimum pension liability adjustment, net of $1 tax benefit													(2	)		(2	)
Amounts reclassified to net income:
Net derivative gains—hedging activities, net of $4 tax expense													(8	)		(8	)
Total comprehensive income										1,362			(735	)		627
Issuance of stock—public offering	38			1,712												1,712
Issuance of stock—employee and direct stock purchase plans	3			199												199
Stock awards and stock options exercised (net of change in unearned compensation)	3			113												113
Stock repurchase and retirement	(1	)		(66	)											(66	)
Accrued contract payments—equity-linked securities				(36	)											(36	)
Tax benefit from stock awards and stock options exercised							21									21
Dividends and other adjustments							(2	)		(723	)					(725	)
Balance at December 31, 2002	308			9,051			47			1,561			(446	)		10,213
Comprehensive income:
Net income										318						318
Net deferred derivative losses—hedging activities, net of $479 tax benefit													(791	)		(791	)
Unrealized gains on investment securities, net of $78 tax expense													112			112
Foreign currency translation adjustments													68			68
Amounts reclassified to net income:
Net realized losses on investment securities, net of $29 tax benefit													49			49
Net losses on derivatives—hedging activities, net of $225 tax benefit													379			379
Total comprehensive income										318			(183	)		135
Issuance of stock—public offering	11			683												683
Issuance of stock—employee and direct stock purchase plans	3			206												206
Stock awards and stock options exercised (net of change in unearned compensation)	3			112												112
Tax benefit from stock awards and stock options exercised							14									14
Dividends										(825	)					(825	)
Balance at December 31, 2003	325			10,052			61			1,054			(629	)		10,538
Comprehensive income:
Net income										1,249						1,249
Net deferred derivative losses—hedging activities, net of $632 tax benefit													(1,118	)		(1,118	)
Unrealized gains on investment securities, net of $18 tax expense													37			37
Foreign currency translation adjustments													30			30
Amounts reclassified to net income:
Net realized losses on investment securities, net of $12 tax benefit													23			23
Net losses on derivatives—hedging activities, net of $407 tax benefit													705			705
Foreign currency translation adjustments(1)													(44	)		(44	)
Total comprehensive income										1,249			(367	)		882
Issuance of stock—equity-linked securities	7			413												413
Issuance of stock—employee and direct stock purchase plans	3			206												206
Stock awards and stock options exercised (net of change in unearned compensation)	5			223												223
Cash settlement—forward equity transaction				(6	)											(6	)
Tax benefit from stock awards and stock options exercised							31									31
Dividends										(861	)					(861	)
Balance at December 31, 2004	340		$	10,888		$	92		$	1,442		$	(996	)	$	11,426

(1) Reclassified to earnings due to the sale of CNG International investments.

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

D 2004/ Page 54

Consolidated Statements of Cash Flows

Year Ended December 31,	2004			2003			2002
(millions)
Operating Activities
Net income	$	1,249		$	318		$	1,362
Adjustments to reconcile net income to net cash from operating activities:
Impairment of telecommunications assets		—			566			—
DCI impairment losses		72			85			13
Impairment (recovery) of CNG’s international assets		(18	)		84			—
Net unrealized gains on energy trading contracts		(113	)		(54	)		(5	)
Depreciation, depletion and amortization		1,433			1,334			1,379
Deferred income taxes and investment tax credits, net		554			452			714
Other adjustments for non-cash items		9			22			34
Changes in:
Accounts receivable		(288	)		(507	)		(442	)
Inventories		(24	)		(234	)		(55	)
Deferred fuel and purchased gas costs, net		89			(244	)		(143	)
Prepaid pension cost		(8	)		(229	)		(198	)
Accounts payable, trade		55			372			155
Accrued interest, payroll and taxes		(9	)		42			58
Deferred revenue		(223	)		(43	)		—
Margin deposit assets and liabilities		(6	)		(18	)		(186	)
Other operating assets and liabilities		67			409			(238	)
Net cash provided by operating activities		2,839			2,355			2,448
Investing Activities
Plant construction and other property additions		(1,451	)		(2,138	)		(1,339	)
Additions to gas and oil properties, including acquisitions		(1,299	)		(1,300	)		(1,489	)
Proceeds from sales of gas and oil properties		729			305			15
Acquisition of businesses		—			—			(410	)
Proceeds from sales of loans and securities		466			912			572
Purchases of securities		(490	)		(777	)		(462	)
Escrow release (deposit) for debt refunding		—			500			(500	)
Purchase of Dominion Fiber Ventures senior notes		—			(633	)		—
Advances to lessor for project under construction		(132	)		(385	)		(240	)
Reimbursement from lessor for project under construction		806			—			—
Other		115			143			(107	)
Net cash used in investing activities		(1,256	)		(3,373	)		(3,960	)
Financing Activities
Issuance (repayment) of short-term debt, net		(879	)		259			(666	)
Issuance of long-term debt and preferred stock		877			3,393			2,434
Repayment of long-term debt and preferred stock		(1,283	)		(2,922	)		(1,904	)
Issuance of preferred securities by subsidiary trusts		—			—			400
Repayment of preferred securities of subsidiary trusts		—			—			(135	)
Issuance of common stock		839			990			2,020
Repurchase of common stock		—			—			(66	)
Common dividend payments		(861	)		(825	)		(723	)
Other		(13	)		(42	)		(43	)
Net cash provided by (used in) financing activities		(1,320	)		853			1,317
Increase (decrease) in cash and cash equivalents		263			(165	)		(195	)
Cash and cash equivalents at beginning of period		126			291			486
Cash and cash equivalents at end of period	$	389		$	126		$	291
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	926		$	941		$	912
Income taxes		(8	)		(32	)		(8	)
Noncash transactions from investing and financing activities:
Assumption of debt related to acquisitions of non-utility generating facilities		213			—			—
Proceeds held in escrow from sale of gas and oil properties		156			—			—
Exchange of debt securities		325			500			567

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

D 2004/ Page 55

Notes to Consolidated Financial Statements

1. Nature of Operations

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

Virginia Power is a regulated public utility that generates, transmits and distributes electricity within an area of approximately 30,000-square-miles in Virginia and northeastern North Carolina. Virginia Power serves approximately 2.3 million retail customer accounts, including governmental agencies and wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. Virginia Power has trading relationships beyond the geographic limits of its retail service territory and buys and sells natural gas, electricity and other energy-related commodities.

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. Its regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and its nonregulated retail energy marketing businesses serve approximately 1.2 million residential and commercial customer accounts in the Northeast, Mid-Atlantic and Midwest. CNG operates an interstate gas transmission pipeline system in the Midwest, Mid-Atlantic states and the Northeast and a liquefied natural gas (LNG) import and storage facility in Maryland. Its producer services operations involve the aggregation of natural gas supply and related wholesale activities. CNG’s exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

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

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

Dominion manages its daily operations through four primary operating segments: Dominion Generation, Dominion Energy, Dominion Delivery and Dominion Exploration & Production. In addition, Dominion reports a Corporate and Other segment that includes the operations of Dominion’s corporate, service company and other operations (including unallocated debt), DCI and the net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004. Assets remain wholly owned by its legal subsidiaries.

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

2. Significant Accounting Policies

General

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

The Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Dominion and all majority-owned subsidiaries, and those variable interest entities (VIEs) where Dominion has been determined to be the primary beneficiary.

Certain amounts in the 2003 and 2002 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2004 presentation.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion’s customer accounts receivable at December 31, 2004 and 2003 included $384 million and $342 million, respectively, of accrued unbilled revenue based on estimated amounts of electric energy or natural gas delivered but not yet billed to its utility customers. Dominion estimates unbilled utility revenue based on historical usage, applicable customer rates, weather factors and, for electric customers, total daily electric generation supplied after adjusting for estimated losses of energy during transmission.

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

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

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

• Nonregulated electric sales consist primarily of sales of electricity from utility and merchant generation facilities at market-based rates, sales of electricity to residential and commercial customers at contracted fixed prices and market-based rates and electric trading revenue;

D 2004/ Page 56

Notes to Consolidated Financial Statements, Continued

• Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, sales of gas purchased from third parties and gas trading revenue;

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

• Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by Dominion including the recognition of revenue previously deferred in connection with the volumetric production payment (VPP) transactions described in Note 12. Gas and oil production revenue is reported net of royalties; and

• Other revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations; sales of coal and extracted products; gas and oil processing; gas transmission pipeline capacity release; sales of emissions credits; business interruption insurance revenue associated with delayed gas and oil production caused by Hurricane Ivan; and sales activity related to agreements used to facilitate the marketing of oil production.

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

Crude Oil Buy/Sell Arrangements

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 Emerging Issues Task Force (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. Amounts currently shown on a grossbasis in Dominion’s Consolidated Statements of Income that could be impacted by further EITF deliberations in this area are summarized below.

Year Ended December 31,	2004		2003		2002
(millions)
Sale activity included in operating revenue	$	290	$	181	$	164
Purchase activity included in operating expenses(1)		271		163		147

(1) Included in Liquids, pipeline capacity and other purchases

Electric Fuel, Purchased Energy and Purchased Gas—Deferred Costs

Where permitted by regulatory authorities, the differences between actual electric fuel, purchased energy and purchased gas expenses and the levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs or recovery of fuel rate revenue in excess of current period expenses is recognized as a regulatory asset or liability.

As for electric fuel and purchased energy expenses, effective January 1, 2004, Dominion’s fuel factor provisions for its Virginia retail customers are locked in until the earlier of July 1, 2007 or the termination of capped rates, with a one-time adjustment of the fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction. As a result, approximately 12% of the cost of fuel used in electric generation and energy purchases used to serve utility customers is subject to deferral accounting. Prior to the amendments to the Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) and the Virginia fuel factor statute in 2004, approximately 93% of the cost of fuel used in electric generation and energy purchases used to serve utility customers had been subject to deferral accounting. Deferred costs associated with the Virginia jurisdictional portion of expenditures incurred through 2003 continue to be reported as regulatory assets, pending recovery through future rates.

Income Taxes

Dominion and its subsidiaries file a consolidated federal income tax return. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109,Accounting for Income Taxes.Accordingly, a regulatory asset has been recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. Dominion establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Deferred investment tax credits are amortized over the service lives of the properties giving rise to the credits.

Stock-based Compensation

Dominion sponsors a plan that provides stock-based awards to directors, executives and other key employees. Under the plan, Dominion grants stock options and restricted stock awards that vest over periods ranging from one to five years. Options have contractual terms that

D 2004/ Page 57

Notes to Consolidated Financial Statements, Continued

range from six and a half to ten years. Thirty million shares of common stock are registered under the plan, with approximately eight million shares available for new grants as of December 31, 2004.

Dominion also had three plans under which its directors were granted their stock retainers, deferred their cash fees and accumulated stock equivalents. In December 2004, these three directors’ plans were amended to freeze participation and prohibit deferral of compensation or granting of new benefits after December 31, 2004 to comply with new deferred compensation requirements of Section 885 of the American Jobs Creation Act of 2004 (the Act) and Section 409A of the Internal Revenue Code of 1986, as amended (the Code). A new directors’ plan was approved by the Board to permit the deferral of compensation earned by Dominion’s non-employee directors after December 31, 2004 in accordance with the Act and Section 409A of the Code and provides comparable benefits to those previously included under the three frozen directors’ plans. The new directors’ plan is subject to shareholder approval.

Dominion measures compensation expense for stock-based awards issued to its employees using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations. Under this method, compensation expense for restricted stock awards equals the fair value of Dominion’s common stock on the date of grant. Stock option awards generally do not result in compensation expense since their exercise price is typically equal to the market price of Dominion’s common stock on the date of grant. Compensation expense, if any, for both types of awards is recognized on a straight-line basis over the stated vesting period of the award.

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

Year Ended December 31,	2004			2003			2002
(millions)
Net income—as reported	$	1,249		$	318		$	1,362
Add: actual stock-based compensation expense, net of tax(1)		10			10			5
Deduct: pro forma stock-based compensation expense, net of tax		(20	)		(36	)		(52	)
Net income—pro forma	$	1,239		$	292		$	1,315
Basic EPS—as reported	$	3.80		$	1.00		$	4.85
Basic EPS—pro forma		3.77			0.92			4.68
Diluted EPS—as reported		3.78			1.00			4.82
Diluted EPS—pro forma		3.75			0.92			4.65

(1) Actual stock-based compensation expense reflects primarily the issuance of restricted stock.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2004 and 2003, accounts payable includes $158 million and $123 million, respectively of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, Dominion considers cash and cash equivalents to include cash onhand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in local gas distribution operations is valued using the last-in-first-out (LIFO) method. Under the LIFO method, those inventories were valued at $59 million at both December 31, 2004 and 2003. Based on the average price of gas purchased during 2004, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $302 million. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.

Derivative Instruments

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

All derivatives, except those for which an exception applies, are reported on the Consolidated Balance Sheets at fair value. One of the exceptions—normal purchases and normal sales—may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenue resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. Derivative contracts that are subject to fair value accounting, including unrealized gain positions and purchased options, are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. For derivatives that are not designated as hedging instruments, any changes in fair value are recorded in earnings.

Valuation Methods

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

For options and contracts with option-like characteristics where pricing information is not available from external sources, Dominion generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Other option models are used by Dominion under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option

D 2004/ Page 58

Notes to Consolidated Financial Statements, Continued

Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, Dominion estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

Derivative Instruments Designated as Hedging Instruments

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

Cash Flow Hedges—A significant portion of Dominion’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and oil. Dominion also uses foreign currency forward contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For cash flow hedge transactions in which Dominion is hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective in offsetting changes in the hedging relationship, until earnings are affected by the hedged item. For cash flow hedge transactions that involve a forecasted transaction, Dominion would discontinue hedge accounting if the occurrence of the forecasted transaction was determined to be no longer probable. Dominion would reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction would not occur.

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

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

Derivative Instruments Held for Trading and Other Purposes

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

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

Statement of Income Presentation:

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

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

• Physically-Settled Derivatives—Not Held for Trading Purposes or Designated as Hedging Instruments: Effective October 1, 2003, all statement of income related amounts for physically settled derivative sales contracts are presented in revenue, while all statement of income related amounts for physically settled derivative purchase contracts are reported in expenses. For periods prior to October 1, 2003, unrealized changes in fair value for physically settled derivative contracts are presented in other operations and maintenance expense on a net basis.

Effective January 1, 2003, Dominion recognizes revenue or expense from all non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or termination. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value reported in revenue on a net basis.

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Notes to Consolidated Financial Statements, Continued

Investment Securities

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

Dominion analyzes all securities classified as available-for-sale to determine whether a decline in fair value should be considered other-than-temporary. Retained interests from securitizations of financial assets are evaluated in accordance with EITF Issue No. 99-20,Recognition of Interest Income and Impairments of Purchased and Retained Beneficial Interests in Securitized Financial Assets. For other securities, Dominion uses several criteria to evaluate other-than-temporary declines, including length of time over which the market value has been lower than its cost, the percentage of the decline as compared to its average cost and the expected fair value of the security. If the market value of the security has been less than cost for greater than nine months and the decline in value is greater than 50% of its average cost, the security is written down to its expected recovery value. If only one of the above criteria is met, a further analysis is performed to evaluate the expected recovery value based on third party price targets. If the third party price quotes are below the security’s average cost and one of the other criteria has been met, the decline is considered other-than-temporary and the security is written down to its expected recovery value.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs, other direct costs and capitalized interest. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2004, 2003 and 2002, Dominion capitalized interest costs of $70 million, $96 million and $95 million, respectively.

For electric distribution and transmission property and natural gas property subject to cost-of-service utility rate regulation, the depreciable cost of such property, less salvage value, is charged to accumulated depreciation at retirement. Cost of removal collections from utility customers and expenditures not representing asset retirement obligations (AROs) are recorded as regulatory liabilities or regulatory assets.

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

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

	2004	2003	2002
(percent)
Generation	2.10	1.95	2.34
Transmission	2.21	2.22	2.26
Distribution	3.19	3.18	3.27
Storage	3.05	2.81	2.47
Gas gathering and processing	2.58	2.39	2.31
General and other	5.49	5.67	5.74

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

In 2002, Dominion extended the estimated useful lives of most of its fossil fuel power stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. The change reduced annual depreciation expense for those assets by approximately $68 million.

Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end pricing adjusted for cash flow hedges in place. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-country basis. Approximately 16% of Dominion’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2004. Dominion adopted Staff Accounting Bulletin No. 106 (SAB 106) as of December 31, 2004 and, accordingly, excludes future cash flows associated with settling AROs that have been accrued on the balance sheet pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations, from its calculations under the full cost ceiling test.

Depreciation of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depreciable base of costs subject to amortization also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base,

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Notes to Consolidated Financial Statements, Continued

determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base. 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. SeeAsset Retirement Obligations for a discussion of gas and oil abandonment and dismantlement costs.

Goodwill and Intangible Assets

Dominion evaluates goodwill for impairment annually, as of April 1st, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives.

Impairment of Long-Lived and Intangible Assets

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

Regulatory Assets and Liabilities

For utility operations subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will allow for the recovery of current costs through future rates charged to customers, Dominion defers these costs and recognizes regulatory assets in its financial statements that otherwise would be expensed by nonregulated companies. Likewise, Dominion recognizes regulatory liabilities in its financial statements when it is probable that regulators will allow for customer credits through future rates and when revenue is collected from customers for expenditures that are not yet incurred.

Asset Retirement Obligations

Beginning in 2003, Dominion recognizes its AROs at fair value as incurred, capitalizing these amounts as costs of the related tangible long-lived assets. Due to the absence of relevant market information, fair value is estimated using discounted cash flow analyses. Dominion reports the accretion of the liabilities due to the passage of time as an operating expense. In addition, beginning in 2003, Dominion classifies all investments held by its decommissioning trusts as available-for-sale, and recognizes realized gains and losses in other income (loss) and records unrealized gains and losses in AOCI.

Nuclear Decommissioning—2002

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

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

Gas and Oil Dismantlement and Abandonment Costs—2002

Prior to 2003, Dominion’s accounting and reporting practices for future dismantlement and restoration activities for its gas and oil wells and platforms recognized such costs as a component of depletion expense and included them in accumulated depreciation, depletion and amortization.

Amortization of Debt Issuance Costs

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

3. Newly Adopted Accounting Standards

2004

FSP FAS 142-2

Dominion adopted Financial Accounting Standards Board (FASB) Staff Position 142-2,Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Entities,(FSP 142-2) in September 2004. FSP 142-2 was issued to clarify that an exception outlined in SFAS No. 142 includes the balance sheet classification of drilling and mineral rights of oil and gas producing entities. In accordance with the guidance in FSP 142-2, Dominion continues to present its oil and gas drilling rights as tangible assets classified in property, plant and equipment.

FIN 46R

Dominion adopted FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, (FIN 46R) for its interests in VIEs that are not considered special purpose entities on March 31, 2004. As discussed below, Dominion adopted FIN 46R for its interests in special purpose entities on December 31, 2003. FIN 46R addresses the identification and consolidation of VIEs, which are entities that are not controllable through voting interests or in which the VIEs’ equity investors do not bear the residual economic risks and rewards in proportion to voting rights. There was no impact on Domin - -

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Notes to Consolidated Financial Statements, Continued

ion’s results of operations or financial position related to this adoption.

Dominion is a party to long-term contracts for purchases of electric generation capacity and energy from qualifying facilities and independent power producers. Certain variable pricing terms in some of these contracts cause them to be considered potential variable interests that require evaluation under the provisions of FIN 46R. If a power generator that holds one of these specific types of contracts is determined to be a VIE and Dominion is determined to be the primary beneficiary, Dominion would be required to consolidate the entity in its financial statements. Consolidation of one of these potential VIEs would primarily result in the addition of property, plant and equipment, long-term debt and minority interest to Dominion’s Consolidated Balance Sheets. The impact on Dominion’s Consolidated Statements of Income would be that purchased energy and capacity expenses attributable to the long-term contract with the VIE would be replaced by the VIE’s operations, maintenance and interest expenses. The VIE’s results of operations would be reported as income attributable to a minority interest, and would not affect Dominion’s net income. The debt of these potential VIEs, even if included in Dominion’s Consolidated Balance Sheets, would be nonrecourse to Dominion.

At March 31, 2004, Dominion had determined that its power purchase agreements with ten of these entities would require further analysis under FIN 46R. Each of these facilities began commercial operations and service to Dominion under the long-term contracts prior to December 31, 2003. Since these entities were established and are legally owned by parties not affiliated with Dominion, Dominion submitted requests for information needed to evaluate the entity and its contractual relationship with the entity under FIN 46R. In addition, Dominion informed the entities that, if the results of its evaluation were to indicate that Dominion should consolidate the entity, it would also require periodic financial information in order to perform the accounting required to consolidate the entity in its financial statements. The objectives of the FIN 46R evaluation are to determine: (1) whether Dominion’s interest, represented by the power purchase contract, is a significant variable interest; (2) whether the supplier entity is a VIE; and (3) if the supplier entity is a VIE, whether Dominion is the primary beneficiary.

In response to these requests, five of the potential VIE supplier entities provided some, but limited, information. After completing its analysis of this information, Dominion concluded that one of the supplier entities is a VIE, its power purchase contract represented a significant variable interest in the VIE, but Dominion is not its primary beneficiary. In addition, using the limited information received, Dominion concluded that it does not hold significant variable interests in two of the potential VIE supplier entities.

Since the enactment of the Virginia Restructuring Act, Dominion has sought to renegotiate or terminate long-term power purchase contracts in its efforts to reduce the cost structure of its generation-related operations. In November 2004, Dominion paid $92 million to terminate its power purchase agreement and to acquire the related generating facility from one of the potential VIE suppliers that had not provided information in response to Dominion’s FIN 46R request. Dominion had purchased $20 million, $20 million and $21 million of electric generation capacity and $4 million, $7 million and $3 million of electric energy under this power purchase agreement in 2004, 2003 and 2002, respectively. In addition, in February 2005, Dominion paid $42 million in cash and assumed $62 million of debt to terminate its power purchase agreement and to acquire the related generating facility from the supplier entity that Dominion had determined to be a VIE and, in which, its power purchase agreement represented a significant variable interest. Dominion purchased $23 million, $23 million and $24 million of electric generation capacity and $8 million, $10 million and $5 million of electric energy under this power purchase agreement in 2004, 2003 and 2002, respectively.

For those six potential VIE supplier entities that have not provided sufficient information, Dominion will continue its efforts to obtain information and will complete an evaluation of its relationship with each of these potential VIEs, if sufficient information is ultimately obtained. Dominion has remaining purchase commitments with these six potential VIE supplier entities of $2.6 billion at December 31, 2004. These commitments are incorporated in Dominion’s disclosure of unconditional purchase obligations included in Note 22. Dominion paid $249 million, $250 million and $300 million for electric generation capacity and $185 million, $168 million and $120 million for electric energy to these entities in 2004, 2003 and 2002, respectively. Dominion’s exposure to losses from its involvement with these entities cannot be determined since losses, if any, would be represented by either: 1) the difference between (a) the amount payable by Dominion for energy and capacity under the long-term contract and (b) amounts recoverable through sales to retail electric customers in its service territory or wholesale market transactions; or 2) if the potential VIE supplier fails to perform, any amount paid by Dominion to obtain replacement energy and capacity in excess of the amounts otherwise payable under the long-term contract with the potential VIE supplier entity.

The EITF has added a project to its agenda to consider what variability should be considered when determining whether an interest is a variable interest. It is uncertain how this EITF project or other future efforts to further interpret FIN 46R could impact Dominion’s conclusions based on its use of information received.

EITF 04-8

On December 31, 2004, Dominion adopted EITF Issue No. 04-8,The Effect of Contingently Convertible Instruments on Diluted Earnings per Share, which requires the shares issuable under contingently convertible instruments to be included in the diluted EPS calculation regardless of whether the market price trigger (or other contingent feature) has been met. Prior to adoption, Dominion exchanged $219 million of outstanding contingent convertible senior notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash. The new notes outstanding on December 31, 2004 were included in the diluted EPS calculation retroactive to the date of issuance using the method described in EITF 04-8. Under this method, the number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average

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Notes to Consolidated Financial Statements, Continued

market price for the period. This did not result in an increase to the average shares outstanding used in the calculation of Dominion’s diluted EPS since the conversion price included in the notes was greater than the average market price.

SAB 106

In September 2004, the SEC issued SAB 106 , which provides guidance to oil and gas companies following the full cost accounting method regarding the application of SFAS No. 143. SAB 106 requires companies calculating the full cost ceiling test to exclude future cash outflows associated with settling AROs that have been accrued on the balance sheet as required by SFAS No. 143. However, estimated dismantlement and abandonment costs related to future development activities, which are not required to be accrued under SFAS No. 143, should continue to be included in the full cost ceiling test. Dominion adopted the provisions of SAB 106 during the fourth quarter of 2004. There was no financial statement impact associated with the adoption of SAB 106.

2003

SFAS No. 143

Effective January 1, 2003, Dominion adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The effect of adopting SFAS No. 143 for 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $201 million. The increase is comprised of a $180 million after-tax gain, representing the cumulative effect of a change in accounting principle and an increase in income before the cumulative effect of a change in accounting principle of $21 million.

EITF 02-3

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

EITF 03-11

Dominion adopted EITF Issue No. 03-11,Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, on October 1, 2003. EITF 03-11 addresses classification of income statement related amounts for derivative contracts. Income statement amounts related to periods prior to October 1, 2003 are presented as originally reported. See Note 2.

Statement 133 Implementation Issue No. C20

In connection with a request to reconsider an interpretation of SFAS No. 133,Accounting for Derivative Instruments and HedgingActivities, FASB issued Statement 133 Implementation Issue No. C20,Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. Issue C20 establishes criteria for determining whether a contract’s pricing terms that contain broad market indices (e.g., the consumer price index) could qualify as a normal purchase or sale and, therefore, not be subject to fair value accounting. Dominion has several contracts that qualify as normal purchase and sales contracts under the Issue C20 guidance. However, the adoption of Issue C20 required the contracts to be initially recorded at fair value as of October 1, 2003, resulting in the recognition of an after-tax charge of $75 million, representing the cumulative effect of the change in accounting principle. As normal purchase and sales contracts, no further changes in fair value will be recognized.

FIN 46R

On December 31, 2003, Dominion adopted FIN 46R for its interests in special purpose entities, resulting in the consolidation of several special purpose lessor entities through which Dominion had constructed, financed and leased several new power generation projects, as well as its corporate headquarters and aircraft. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $644 million in net property, plant and equipment and deferred charges and $688 million of related debt. This resulted in additional depreciation expense of approximately $20 million in 2004. The cumulative effect in 2003 of adopting FIN 46R for Dominion’s interests in special purpose entities was an after-tax charge of $27 million, representing depreciation expense and amortization associated with the consolidated assets.

From 1997 through 2002, Dominion established five capital trusts that sold trust preferred securities to third party investors. Dominion received the proceeds from the sale of the trust preferred securities in exchange for various junior subordinated notes issued by Dominion to be held by the trusts. Upon adoption of FIN 46R, Dominion began reporting as long-term debt its junior subordinated notes held by the trusts rather than the trust preferred securities. As a result in 2004, Dominion reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

Pro Forma Information Reflecting Adoption of New Standards

Disclosure requirements associated with the adoption of FIN 46R and SFAS No. 143 require a presentation of pro forma net income and EPS for 2002 as if Dominion had applied the provisions of those standards as of January 1, 2002. Other standards adopted

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Notes to Consolidated Financial Statements, Continued

during 2004 and 2003 do not require pro forma information and are excluded from the amounts presented below.

	Amount		Basic EPS		Diluted EPS
(in millions, except per share amounts)
2002
Reported net income	$	1,362	$	4.85	$	4.82
Adjusted net income		1,363		4.85		4.82

4. Recently Issued Accounting Standards

EITF 03-1

In accordance with FSP EITF 03-1-1, Dominion delayed its adoption of the recognition and measurement provisions of EITF Issue No. 03-1,The Meaning of Other-Than-Temporary Impairment and ItsApplication to Certain Investments, which provides guidance for evaluating and recognizing other-than-temporary impairments for certain investments in debt and equity securities. This delay will be in effect until the FASB reaches a final conclusion on issues raised in its proposed FSP 03-1-a, which relates primarily to implementation issues concerning certain types of debt securities.

Pending the adoption of any new guidance that may be finalized in the future, Dominion has continued to evaluate its available-for-sale securities for other-than-temporary impairment based upon the accounting policy described in Note 2. In addition to issues being addressed by the FASB in FSP 03-1-a, Dominion and other entities in the electric industry have sought additional guidance from the FASB concerning the proper application of EITF 03-1 to debt and equity securities held in nuclear decommissioning trusts. Given the delayed effective date and the request for additional guidance described above, Dominion cannot predict what the initial or ongoing impact of applying EITF 03-1 to its nuclear decommissioning trust investments may have on its results of operations and financial condition at this time.

SFAS No. 123R

In December 2004, the FASB issued SFAS No. 123 (revised 2004),Share-Based Payment(SFAS No. 123R), which requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. The cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123R covers a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans. The requirements of SFAS No. 123R are effective for unvested awards outstanding as of July 1, 2005 as well as for awards granted, modified, repurchased or cancelled on or after that date. Compensation expense expected to be recognized for unvested stock options outstanding at adoption is not expected to be material and Dominion’s accounting for restricted stock awards is not expected to change significantly under the new standard. Dominion is currently evaluating the financial statement impact of applying SFAS No. 123R to future grants of stock-based awards.

SFAS No. 151

In November 2004, the FASB issued SFAS No. 151,Inventory Costs—an amendment of ARB No. 43, Chapter 4, which clarifies that abnormal amounts of idle facility expense, handling costs, freight, and wasted materials (spoilage) should be recognized as current period charges, and requires that in manufacturing operations, allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facility. Dominion will adopt the provisions of this standard prospectively beginning January 1, 2006 and does not expect the adoption to have a material impact on its results of operations and financial condition.

SFAS No. 153

In December 2004, the FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29, which requires that all commercially substantive exchange transactions, for which the fair value of the assets exchanged are reliably determinable, be recorded at fair value, whether or not they are exchanges of similar productive assets. This amends the exception from fair value measurements in APB No. 29,Accounting for Nonmonetary Transactions, for nonmonetary exchanges of similar productive assets and replaces it with an exception for only those exchanges that do not have commercial substance. Dominion will adopt the provisions of this standard prospectively beginning July 1, 2005 and does not expect the adoption to have a material impact on its results of operations and financial condition.

5. Acquisitions

USGen Power Plants

In January 2005, Dominion completed the acquisition of three electric power generation facilities from USGen New England, Inc. (USGen) for $642 million in cash. 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. These assets will be included in the Dominion Generation operating segment. Dominion did not acquire any of the facilities’ debt in the transaction and plans to finance the acquisition with a combination of debt and equity.

Cove Point LNG Limited Partnership

In September 2002, Dominion acquired 100% ownership of Cove Point LNG Limited Partnership (Cove Point), a cost-based rate-regulated entity, from a subsidiary of The Williams Companies for $225 million in cash. Dominion recorded $75 million of goodwill representing the excess of the purchase price over the regulatory basis of Cove Point’s assets acquired and liabilities assumed. Cove Point’s assets include an LNG natural gas import and storage facility located near Baltimore, Maryland and an approximately 85-mile natural gas pipeline. Cove Point became fully operational in August 2003. Cove Point is included in the Dominion Energy

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Notes to Consolidated Financial Statements, Continued

operating segment and the goodwill arising from the acquisition was allocated to that segment for goodwill impairment-testing purposes.

Mirant State Line Ventures, Inc.

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

6. Operating Revenue

Dominion’s operating revenue consists of the following:

Year Ended December 31,	2004		2003		2002
(millions)
Regulated electric sales	$	5,180	$	4,876	$	4,856
Regulated gas sales		1,422		1,258		876
Nonregulated electric sales		1,249		1,130		1,017
Nonregulated gas sales		2,082		1,718		778
Gas transportation and storage		802		740		705
Gas and oil production		1,636		1,503		1,334
Other		1,601		853		652
Total operating revenue	$	13,972	$	12,078	$	10,218

7. Income Taxes

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

Year Ended December 31,	2004			2003			2002
(millions)
Income before provision for taxes:
U.S.	$	1,938		$	1,506		$	2,018
Non-U.S.		26			40			25
Total		1,964			1,546			2,043
Income tax expense:
Current
Federal		62			121			(46	)
State		82			22			13
Non-U.S.		(3	)		1
Total current		141			144			(33	)
Deferred
Federal		580			433			654
State		(16	)		32			65
Non-U.S.		12			6			13
Total deferred		576			471			732
Amortization of deferred investment tax credits—net		(17	)		(18	)		(18	)
Total income tax expense	$	700		$	597		$	681

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

Year Ended December 31,	2004		2003		2002
U.S. statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Valuation allowance	(0.3	)	4.0		—
State taxes, net of federal benefit	2.2		2.2		2.5
Utility plant differences	0.1		(0.4	)	(0.1	)
Preferred dividends	0.3		0.4		0.3
Amortization of investment tax credits	(0.7	)	(0.9	)	(0.7	)
Nonconventional fuel credit	—		—		(1.8	)
Other benefits and taxes / foreign operations	—		(0.5	)	0.2
Employee pension and other benefits	(0.5	)	(0.7	)	(0.6	)
Employee stock ownership plan deduction	(0.5	)	(0.7	)	(0.8	)
Other, net	—		0.2		(0.7	)
Effective tax rate	35.6	%	38.6	%	33.3	%

Dominion’s 2004 and 2003 effective tax rates were negatively impacted by the expiration of nonconventional fuel tax credits. Dominion’s 2003 effective tax rate was also negatively impacted by an increase in the valuation allowance related to federal loss carryforwards at CNG International (CNGI), Dominion Telecom, Inc. and DCI that are not expected to be utilized.

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

At December 31,	2004			2003
(millions)
Deferred income tax assets:
Other comprehensive income	$	594		$	397
Deferred investment tax credits		31			31
Loss and credit carryforwards		798			424
Valuation allowance		(328	)		(338	)
Total deferred income tax assets		1,095			514
Deferred income tax liabilities:
Depreciation method and plant basis differences		2,735			2,310
Income taxes recoverable through future rates		60			16
Partnership basis differences		567			485
Postretirement and pension benefits		537			571
Intangible drilling costs		965			833
Geological, geophysical and other exploration differences		249			220
Deferred state income taxes		494			432
Other		318			21
Total deferred income tax liabilities		5,925			4,888
Total net deferred income tax liabilities	$	4,830		$	4,374

At December 31, 2004, Dominion had the following loss and credit carryforwards:

• Federal loss carryforwards of $1.4 billion that expire if unutilized during the period 2005 through 2024. A valuation allowance on $806 million in carryforwards has been established due to the uncertainty of realizing these future deductions;

• State net operating loss carryforwards of $2.4 billion that expire if unutilized during the period 2005 through 2024. A valuation allowance on $988 million has been established for these carryforwards; and

D 2004/ Page 65

Notes to Consolidated Financial Statements, Continued

• Federal and state minimum tax credits of $131 million that do not expire and other federal and state income tax credits of $66 million that will expire if unutilized during the period 2006 through 2024.

Other

Dominion has not provided for U.S. deferred income taxes or foreign withholding taxes on its remaining undistributed earnings of $135 million from its non-U.S. subsidiaries since those earnings are intended to be reinvested indefinitely.

As a matter of course, Dominion is regularly audited by federal and state tax authorities. Dominion establishes liabilities for probable tax-related contingencies and reviews them in light of changing facts and circumstances. Although the results of these audits are uncertain, Dominion believes that the ultimate outcome will not have a material adverse effect on Dominion’s financial position. Dominion had no significant tax-related contingent liabilities at December 31, 2004.

American Jobs Creation Act of 2004

The Act was signed into law October 22, 2004, and has several provisions for energy companies including a deduction related to taxable income derived from qualified production activities. Under the Act, qualified production activities include Dominion’s electric generation and oil and gas extraction activities. The Act limits the deduction to the lesser of taxable income derived from qualified production activities or the consolidated federal taxable income of Dominion and its subsidiaries. At this time, Dominion does not believe the qualified production activities deduction will have a material impact on Dominion’s results of operations or financial position in 2005.

The Act also allows United States companies to repatriate foreign earnings at a substantially reduced tax rate until December 2005. At the current time, Dominion does not have plans to repatriate funds to the United States but is continuing its evaluation and will finalize its plans during 2005. Dominion estimates the range of foreign earnings that may be repatriated to be $135 million to $225 million, which would result in income tax expense in the range of $20 million to $35 million.

8. Hedge Accounting Activities

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

	2004			2003			2002
(millions)
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$	(2	)	$	(3	)	$	2
Cash flow hedges		10			7			(31	)
Net ineffectiveness	$	8		$	4		$	(29	)
Portion of gains (losses) on hedging instruments excluded from measurement of effectiveness and included in net income:
Fair value hedges(1)	$	3		$	1		$	(1	)
Cash flow hedges(2)		101			7			(1	)
Total	$	104		$	8		$	(2	)

(1) Amounts relate to changes in the difference between spot prices and forward prices for 2004 and to changes in options’ time value for 2003 and 2002.

(2) Amounts relate to changes in options’ time value.

The following table presents selected information related to cash flow hedges included in AOCI in the Consolidated Balance Sheet at December 31, 2004:

	Accumulated Other Comprehensive Income (Loss) After Tax			Portion Expected to be Reclassified to Earnings during the Next 12 Months After Tax			Maximum Term
(millions)
Commodities:
Gas	$	(673	)	$	(354	)	38 months
Oil		(308	)		(135	)	36 months
Electricity		(209	)		(133	)	36 months
Interest Rate		(31	)		(3	)	258 months
Foreign Currency		40			11		35 months
Total	$	(1,181	)	$	(614	)

The actual amounts that will be reclassified to earnings in 2005 will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates. The effect of amounts being reclassified from accumulated other comprehensive loss to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

As a result of damage to certain offshore production facilities in the Gulf of Mexico caused by Hurricane Ivan, and the related loss of forecasted oil production for the period from mid-September 2004 to May 2005, Dominion discontinued certain cash flow hedges effective September 14, 2004. In connection with the discontinuance of these cash flow hedges, Dominion reclassified $71 million of pre-tax losses from AOCI to earnings in 2004. These amounts were reported in other operations and maintenance expense in the Consolidated Statements of Income.

D 2004/ Page 66

Notes to Consolidated Financial Statements, Continued

9. Discontinued Operations—Telecommunications Operations

Dominion Fiber Ventures, LLC (DFV) was a joint venture originally formed by Dominion and a third-party investor trust (Investor Trust) to fund the development of its principal subsidiary, Dominion Telecom, Inc. (Dominion Telecom). Dominion Telecom was a facilities-based interchange and emerging local carrier, providing broadband solutions to wholesale customers throughout the eastern United States. In connection with its formation, DFV issued $665 million of 7.05% senior secured notes due March 2005 which were secured in part by Dominion convertible preferred stock held in trust. Dominion was the beneficial owner of the trust and thus did not present the convertible preferred stock in its Consolidated Balance Sheets. During 2004, as a result of the retirement of DFV’s senior notes, the trust was dissolved and the convertible preferred stock was retired.

At inception, Dominion’s strategy for Dominion Telecom was to focus primarily on delivering lit capacity, dark fiber and collocation services to under-served markets. With the markets for these services not growing at rates originally contemplated and the continuing downward pressure on prices, resulting from excess capacity in the telecommunications industry, Dominion reconsidered its investment strategy during 2003. Reflecting a revision in long-term expectations for potential growth in telecommunications service revenue, Dominion approved a strategy to sell its interest in the telecommunications business and began reporting Dominion Telecom as a discontinued operation in the fourth quarter of 2003.

2004—Sale of Dominion Telecom

In May 2004, Dominion completed the sale of its discontinued telecommunication operations to Elantic Telecom, Inc., realizing a loss of $11 million ($7 million after-tax, $0.02 per share) related to the sale. The results of telecommunications operations, including revenue of $8 million and a loss before income taxes of $19 million, are presented as discontinued operations, on a net basis, on the Consolidated Statement of Income for 2004.

During July 2004, Elantic Telecom Inc. filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Eastern District of Virginia, Richmond Division. Dominion is currently assessing its potential exposure, if any, as a result of this filing. At December 31, 2004, Dominion has $9 million of remaining guarantees related to Dominion Telecom.

2003—Asset Impairments

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

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

2003-Additional Investments in DFV

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

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

In the fourth quarter of 2003, Dominion purchased the Investor Trust’s interest in DFV for $62 million, including $2 million for accrued dividends. This transaction was accounted for as a purchase of a minority interest and $60 million was recognized as goodwill and impaired. The purchase enabled Dominion to proceed with its strategy to sell Dominion Telecom and, accordingly, classify the business as discontinued operations as of December 31, 2003. As a result, telecommunications assets (network assets and inventories) and liabilities, both totaling $13 million were classified as held-for-sale, and were included in other current assets and liabilities on the Consolidated Balance Sheet as of December 31, 2003. The results of telecommunications operations, including revenue of $18 million and a loss before income taxes of $627 million, were presented as discontinued operations, on a net basis, on the Consolidated Statement of Income for 2003.

2003—Other

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

D 2004/ Page 67

Notes to Consolidated Financial Statements, Continued

the underlying limited liability company agreement rather than voting interests.

2002 Transactions

During 2002, Dominion’s Consolidated Financial Statements reflected the following transactions between Dominion and DFV and Dominion Telecom:

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

• Equity losses of $32 million;

• Interest expense on the affiliated loans of $13 million; and

• Management and other support services billed by Dominion to Dominion Telecom of $35 million.

10. Earnings Per Share

The following table presents the calculation of Dominion’s basic and diluted EPS:

Year Ended December 31,	2004			2003			2002
(millions, except per share amounts)
Income from continuing operations before cumulative effect of changes in accounting principles	$	1,264		$	949		$	1,362
Loss from discontinued operations		(15	)		(642	)		—
Cumulative effect of changes in accounting principles		—			11			—
Net income	$	1,249		$	318		$	1,362
Basic EPS
Average shares of common stock outstanding—basic		329.1			317.5			281.0
Income from continuing operations before cumulative effect of changes in accounting principle	$	3.84		$	2.99		$	4.85
Loss from discontinued operations		(0.04	)		(2.02	)		—
Cumulative effect of changes in accounting principles		—			.03			—
Net income	$	3.80		$	1.00		$	4.85
Diluted EPS
Average shares of common stock outstanding		329.1			317.5			281.0
Net effect of potentially dilutive securities(1)		1.4			1.3			1.6
Average shares of common stock outstanding—diluted		330.5			318.8			282.6
Income from continuing operations before cumulative effect of changes in accounting principles	$	3.82		$	2.98		$	4.82
Loss from discontinued operations		(0.04	)		(2.01	)		—
Cumulative effect of changes in accounting principles		—			.03			—
Net income	$	3.78		$	1.00		$	4.82

(1) Potentially dilutive securities consist of options, restricted stock, equity-linked securities, contingently convertible senior notes and shares issuable under a forward equity sale agreement.

Potentially dilutive securities with the right to purchase approximately 5 million, 10 million and 11 million common shares for the years ended 2004, 2003 and 2002, respectively, were not included in the respective period’s calculation of diluted EPS because the exercise and purchase prices included in those instruments were greater than the average market price of the common shares.

11. Available-For-Sale and Other Investment Securities

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

Available-for-sale securities as of December 31, 2004 and 2003 are summarized below:

	Fair Value		Total Unrealized Gains Included in AOCI		Total Unrealized Losses Included in AOCI
(millions)
2004
Equity securities	$	1,229	$	240	$	12
Debt securities		1,044		20		1
Total		2,273		260		13
2003
Equity securities		1,092		157		9
Debt securities		1,102		22		12
Total	$	2,194	$	179	$	21

The following table presents the fair value and gross unrealized losses of Dominion’s available-for-sale securities, aggregated by investment category and the length of time the securities have been in a continuous loss position, at December 31, 2004:

	Equity Securities				Debt Securities
	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
(millions)
Less than 12 months	$	92	$	10	$	166	$	1
12 months or more		9		2		5		—
Total	$	101	$	12	$	171	$	1

D 2004/ Page 68

Notes to Consolidated Financial Statements, Continued

Debt securities backed by mortgages and loans do not have stated contractual maturities as borrowers have the right to call or repay obligations with or without call or prepayment penalties. At December 31, 2004, these debt securities totaled $335 million. The fair value of all other debt securities at December 31, 2004 by contractual maturity are as follows:

	Amount
(millions)
Due in one year or less	$	18
Due after one year through five years		230
Due after five years through ten years		261
Due after ten years		200
Total	$	709

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

	2004		2003(1)		2002
(millions)
Available-for-sale securities:
Proceeds from sales	$	463	$	832	$	506
Realized gains		57		62		58
Realized losses		90		102		58
Trading securities:
Net unrealized gain (loss)(2)		4		12		(10	)

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

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

Decommissioning Trust Investments—Utility Plants 2002

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

12. Property, Plant and Equipment

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

At December 31,	2004		2003
(millions)
Utility
Generation	$	10,135	$	9,780
Transmission		3,464		3,308
Distribution		8,024		7,713
Storage		1,023		999
Nuclear fuel		795		757
Gas gathering and processing		418		416
General		774		795
Plant under construction		674		698
Total utility		25,307		24,466
Nonutility
Exploration and production properties being amortized:
Proved		8,246		7,561
Unproved		653		567
Unproved exploration and production properties not being amortized		970		1,154
Merchant generation properties—nuclear		997		929
Nuclear fuel		271		175
Merchant generation properties—other		1,268		1,214
Other—including plant under construction		951		1,041
Total nonutility		13,356		12,641
Total property, plant and equipment	$	38,663	$	37,107

Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2004 and the years in which such excluded costs were incurred, are as follows:

	Total		2004		2003		2002		Years Prior
(millions)
Property acquisition costs	$	711	$	43	$	60	$	53	$	555
Exploration costs		122		44		30		25		23
Capitalized interest		137		49		54		25		9
Total	$	970	$	136	$	144	$	103	$	587

There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2004. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

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

Year Ended December 31,	2004		2003		2002
(Per Mcf Equivalent)
United States cost center	$	1.28	$	1.20	$	1.13
Canadian cost center		1.18		1.00		0.85

D 2004/ Page 69

Notes to Consolidated Financial Statements, Continued

Volumetric Production Payment Transactions

In 2004, Dominion received $413 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period May 2004 through April 2008. The sale reduced Dominion’s proved natural gas reserves by approximately 83 billion cubic feet (bcf). While Dominion is obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and rights to future development drilling. If production from the properties is inadequate to deliver approximately 83 bcf of natural gas scheduled for delivery to the purchaser, Dominion has no obligation to make up the shortfall. Cash proceeds received from this VPP transaction were recorded as deferred revenue. Dominion will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser. Dominion also entered into a VPP transaction in 2003 receiving proceeds of $266 million for approximately 66 bcf for the period August 2003 through August 2007.

Sale of British Columbia Assets

In December 2004, Dominion sold the majority of its natural gas and oil assets in British Columbia, Canada, for $476 million, which was credited to Dominion’s full cost pool. Dominion received cash proceeds of $320 million in December 2004 and $156 million in January 2005. The properties sold produced about 30 bcf equivalent net of natural gas annually. Dominion recorded expenses of $10 million in other operations and maintenance expense related to the sale.

Jointly-Owned Utility Plants

Dominion’s proportionate share of jointly-owned utility plants at December 31, 2004 follows:

	Bath County Pumped Storage Station		North Anna Power Station		Clover Power Station
(millions, except percentages)
Ownership interest		60.0%		88.4%		50.0%
Plant in service	$	1,014	$	2,067	$	548
Accumulated depreciation		378		897		112
Nuclear fuel		—		380		—
Accumulated amortization of nuclear fuel		—		285		—
Construction work in progress		27		47		3

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

13. Goodwill and Intangible Assets

Goodwill

There was no impairment of or material change to the carrying amount and segment allocation of goodwill in 2004.

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

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

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

Other Intangible Assets

All of Dominion’s intangible assets, other than goodwill, are subject to amortization. Amortization expense for intangible assets was $62 million, $54 million and $53 million for 2004, 2003 and 2002, respectively. There were no material acquisitions of intangible assets in 2004 or 2003. Intangible assets are included in other assets on the Consolidated Balance Sheets. The components of intangible assets at December 31, 2004 and 2003 were as follows:

	2004				2003
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Software and software licenses	$	579	$	269	$	543	$	237
Other		118		30		73		23
Total	$	697	$	299	$	616	$	260

Annual amortization expense for intangible assets is estimated to be $63 million for 2005, $57 million for 2006, $48 million for 2007, $33 million for 2008 and $26 million for 2009.

D 2004/ Page 70

Notes to Consolidated Financial Statements, Continued

14. Regulatory Assets and Liabilities

Dominion’s regulatory assets and liabilities include the following:

At December 31,	2004		2003
(millions)
Regulatory assets:
Unrecovered gas costs	$	52	$	55
Regulatory assets—current(1)		52		55
Other postretirement benefit costs(2)		96		102
Income taxes recoverable through future rates(3)		250		227
Deferred cost of fuel used in electric generation		248		335
Regional transmission organization start-up and integration costs(4)		41		30
Cost of decommissioning DOE uranium enrichment facilities(5)		18		27
Customer bad debts(6)		73		65
Other		62		46
Regulatory assets—non-current		788		832
Total regulatory assets	$	840	$	887
Regulatory liabilities:
Amounts payable to customers	$	2	$	3
Estimated rate contingencies and refunds(7)		13		13
Regulatory liabilities—current(8)		15		16
Provision for future cost of removal(9)		595		572
Other		15		15
Regulatory liabilities—non-current		610		587
Total regulatory liabilities	$	625	$	603

(1) Reported in other current assets.

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

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

(4) The Federal Energy Regulatory Commission (FERC) has authorized the deferral of start-up costs incurred by transmission owning companies joining a Regional Transmission Organization (RTO). Dominion has deferred $13 million in start-up costs associated with the Alliance Regional Transmission Organization (ARTO) and $24 million associated with PJM Interconnection, LLC (PJM) and associated carrying costs of $4 million. Dominion expects recovery from Virginia jurisdictional retail customers to commence at the end of the Virginia retail rate cap period, subject to regulatory approval.

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

(6) The Public Utilities Commission of Ohio (Ohio Commission) has authorized the collection of previously deferred costs of $51 million associated with certain uncollectible customer accounts from 2001 over five years through the tracker rider effective in 2004. The Ohio Commission has also authorized the deferral and recovery of excess bad debt costs incurred in 2003 and thereafter for certain uncollectible customer accounts not contemplated in current base rate recoveries. The total deferral of 2004 and 2003 excess uncollectible amounts was $17 million and $13 million, respectively.

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

(8) Reported in other current liabilities.

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

At December 31, 2004, approximately $416 million of Dominion’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of unrecovered gas costs, customer bad debts and a portion of deferred fuel costs. Unrecovered gas costs and the ongoing portion of bad debts are recovered within two years. The previously deferred bad debts will be recovered over a 4-year period. Deferred fuel costs were historically recovered within two years; however, in connection with the settlement of the 2003 Virginia fuel rate proceeding, Dominion agreed to recover $307 million of previously incurred costs through June 30, 2007 without a return on unrecovered balances.

15. Asset Retirement Obligations

Dominion’s AROs are primarily associated with the decommissioning of its nuclear generation facilities, retiring certain natural gas pipelines and dismantling and removing gas and oil wells and platforms. In addition, Dominion has AROs related to its natural gas gathering, storage, transmission and distribution systems, including approximately 2,300 gas storage wells in Dominion’s underground natural gas storage network. These obligations result from certain safety requirements to be performed at the time any pipeline or storage well is abandoned. However, Dominion expects to operate its natural gas gathering, storage, transmission and distribution systems in perpetuity. Thus, AROs for those assets will not be reflected in Dominion’s Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur when expected retirement or abandonment dates for individual pipelines or storage wells are determined by Dominion’s operational planning. The changes to Dominion’s AROs during 2004 were as follows:

	Amount
(millions)
Asset retirement obligations at December 31, 2003(1)	$	1,653
Obligations incurred during the period		23
Obligations settled during the period		(60	)
Accretion expense		91
Revisions in estimated cash flows		(2	)
Other		2
Asset retirement obligations at December 31, 2004(1)	$	1,707

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

D 2004/ Page 71

Notes to Consolidated Financial Statements, Continued

Dominion has established trusts dedicated to funding the future decommissioning of its nuclear plants. At December 31, 2004 and 2003 the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $2.0 billion and $1.9 billion, respectively.

16. Short-Term Debt and Credit Agreements

Joint Credit Facilities

In May 2004 and 2002, Dominion, Virginia Power and CNG entered into two joint credit facilities that allow aggregate borrowings of up to $2.25 billion. The facilities include a $1.5 billion three-year revolving credit facility that terminates in May 2007 and a $750 million three-year revolving credit facility that terminates in May 2005. Dominion expects to renew the $750 million credit facility prior to its maturity in May 2005. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and CNG and other general corporate purposes. The $1.5 billion and $750 million credit facilities can also be used to support the issuance of up to $500 million and $200 million of letters of credit, respectively.

At December 31, 2004, total outstanding commercial paper supported by the joint credit facilities was $573 million, with a weighted average interest rate of 2.39%. At December 31, 2003, total outstanding commercial paper supported by previous creditagreements was $1.44 billion, with a weighted average interest rate of 1.20%.

At December 31, 2004 and 2003, total outstanding letters of credit supported by the joint credit facilities were $183 million and $85 million, respectively.

CNG Credit Facilities

In August 2004, CNG entered into a $1.5 billion three-year revolving credit facility that terminates in August 2007. This credit facility is being used to support CNG’s issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by CNG in its risk management strategies for its gas and oil production. At December 31, 2004, outstanding letters of credit under this facility totaled $555 million. At December 31, 2003, outstanding letters of credit under the previous facility totaled $820 million.

In addition to the facilities above, in June and August of 2004, CNG entered into two $100 million letter of credit agreements that terminate in June 2007 and August 2009, respectively. Additionally, in October 2004, CNG entered into three letter of credit agreements totaling $700 million that terminate in April 2005 and are not expected to be renewed. These five agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by CNG in its risk management strategies for gas and oil production. At December 31, 2004, outstanding letters of credit under these agreements totaled $900 million.

D 2004/ Page 72

Notes to Consolidated Financial Statements, Continued

17. Long-Term Debt

At December 31,	2004 Weighted Average Coupon(1)	2004			2003
(millions, except percentages)
Dominion Resources, Inc.:
Unsecured Senior and Medium-Term Notes:
2.25% to 7.82%, due 2004 to 2008	4.85%	$	2,002		$	1,740
5.0% to 8.125%, due 2009 to 2033(2)	6.25%		3,880			3,680
Unsecured Equity-Linked Senior Notes, 5.75% to 8.05%, due 2006 to 2008(3)	5.75%		330			743
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)			220			220
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041	8.22%		825			825
Unsecured Nonrecourse Debt, Variable Rate, due 2004			—			18
Consolidated Natural Gas Company:
Unsecured Debentures and Senior Notes:
5.375% to 7.375%, due 2004 to 2008	6.16%		1,000			1,400
5.0% to 6.875%, due 2010 to 2027(2)	6.17%		2,350			1,950
Unsecured Senior Subordinated Debt, 9.25%, due 2004			—			88
Secured Bank Debt, Variable Rate, due 2006(9)	2.55%		234			234
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.8%, due 2041			206			206
Virginia Electric and Power Company:
Secured First and Refunding Mortgage Bonds:(5)
7.625% to 8.0%, due 2004 to 2007	7.63%		215			465
7.0% to 8.625%, due 2024 to 2025	8.09%		512			512
Secured Bank Debt, Variable Rate, due 2007(9)	1.75%		370			370
Unsecured Senior and Medium-Term Notes:
5.375% to 7.2%, due 2004 to 2008	5.57%		1,370			1,445
4.50% to 7.25%, due 2010 to 2025	5.08%		936			830
Unsecured Callable and Puttable Enhanced SecuritiesSM, 4.10%, due 2038(6)			225			225
Tax-Exempt Financings:(7)
Variable Rate, due 2008	1.33%		60			60
Variable Rates, due 2015 to 2027	1.34%		137			137
4.95% to 9.62%, due 2005 to 2008	5.24%		108			107
2.225% to 7.65%, due 2009 to 2031	5.32%		397			295
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 7.375%, due 2042			412			412
Dominion Energy, Inc.:
Unsecured Medium-Term Notes, 5.72% to 6.1%, due 2005 to 2006(8)	5.94%		262			243
Unsecured Medium-Term Notes, 4.92%, due 2009(8)			191			—
Secured Senior Note, 7.33%, due 2020			231			238
Secured Bank Debt, Variable Rates, due 2006(9)	2.55%		347			347
Revolving Lines of Credit, Variable Rates, due 2004			—			150
Dominion Capital, Inc.:
Notes, 12.5%, due 2008			6			6
Dominion Resources Services, Inc., Secured Bank Debt, Variable Rate, due 2006(9)	2.34%		107			107
Dominion Fiber Ventures, Secured Senior Notes, 7.05%, due 2005(10)			—			21
			16,933			17,074
Fair value hedge valuation(11)			11			43
Amounts due within one year	6.02%		(1,368	)		(1,252	)
Unamortized discount and premium, net			(69	)		(89	)
Total long-term debt		$	15,507		$	15,776

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2004.

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

(3) In November 2004, Dominion issued 6.7 million shares of its common stock to settle stock purchase contracts related to $413 million of 8.05% equity-linked senior notes. In connection with settlement, the senior notes were remarketed and now carry an annual interest rate of 3.66%. As a result of settlement of the stock purchase contracts, the 3.66% senior notes are reported as a component of Unsecured Senior and Medium-Term Notes.

D 2004/ Page 73

Notes to Consolidated Financial Statements, Continued

(4) Convertible into a combination of cash and shares of Dominion’s common stock at any time after March 31, 2004 when the average closing price of Dominion common stock reaches $88.32 per share for a specified period. At the option of holders on December 15, 2006, December 15, 2008, December 15, 2013, or December 15, 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest.

(5) Substantially all of Virginia Power’s property ($12.0 billion at December 31, 2004) is subject to the lien of the mortgage, securing its mortgage bonds.

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

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

(8) Aggregate principal amount of CAD$545 million of securities denominated in Canadian dollars and presented in US dollars, based on exchange rates as of year-end.

(9) Represents debt associated with certain special purpose lessor entities that are consolidated in accordance with FIN 46R. The debt is nonrecourse to Dominion and is secured by the entities’ property, plant and equipment, which totaled $963 million and $997 million at December 31, 2004 and 2003, respectively.

(10) Debt was redeemed in December 2004.

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

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2004 were as follows:

	2005			2006			2007			2008			2009			Thereafter			Total
	(millions, except percentages)
Secured First and Refunding Mortgage Bonds		—			—		$	215			—			—		$	512		$	727
Secured Senior Notes	$	8		$	9			10		$	10		$	11			183			231
Unsecured Senior Notes (including Medium-Term Notes)		1,355			1,774			858			1,009			500			7,046			12,542
Unsecured Callable and Puttable Enhanced SecuritiesSM		—			—			—			—			—			225			225
Tax-Exempt Financings		5			5			19			157			114			401			701
Secured Bank Debt		—			688			370			—			—			—			1,058
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			1,443			1,443
Other		—			—			—			6			—			—			6
Total	$	1,368		$	2,476		$	1,472		$	1,182		$	625		$	9,810		$	16,933
Weighted average coupon		6.02	%		4.16	%		5.02	%		5.11	%		5.21	%		6.27	%

Dominion’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2004, there were no events of default under these covenants.

Convertible Securities

As described in Note 3, Dominion entered into an exchange transaction with respect to $219 million of its outstanding contingent convertible senior notes in contemplation of the transition method provided by EITF 04-8. Dominion exchanged the outstanding notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash. The notes are valued at a conversion rate of 13.5865 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $73.60. Amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases.

The new notes outstanding on December 31, 2004 were included in the diluted EPS calculation retroactive to the date of issuance using the method described in EITF 04-8. Under this method, the number of shares included in the denominator of the diluted EPS calculation are calculated as the net shares issuable for the reporting period based upon the average market price for the period. This did not result in an increase to the average sharesoutstanding used in the calculation of Dominion’s diluted EPS since the conversion price of $73.60 included in the notes was greater than the average market price of the shares.

The senior notes are convertible by holders into a combination of cash and shares of Dominion’s common stock under any of the following circumstances:

(1) the price of Dominion common stock reaches $88.32 per share for a specified period;

(2) the senior notes are called for redemption by Dominion on or after December 20, 2006;

(3) the occurrence of specified corporate transactions; or

(4) the credit rating assigned to the senior notes by Moody’s is below Baa3 and by Standard & Poor’s is below BBB- or the ratings are discontinued for any reason.

Since none of the conditions have been met, the senior notes are not yet subject to conversion. In 2007, Dominion will also begin to pay contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase their senior notes for cash at 100% of the principal plus accrued interest in December 2006, 2008, 2013 or 2018, or if Dominion undergoes certain fundamental changes.

D 2004/ Page 74

Notes to Consolidated Financial Statements, Continued

Equity—Linked Securities

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

Dominion makes quarterly interest payments on the senior notes and quarterly payments on the stock purchase contracts at the rates described below. Dominion has recorded the present value of the stock purchase contract payments as a liability, offset by a charge to common stock in shareholders’ equity. Interest payments on the senior notes are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as interest expense. In calculating diluted EPS, Dominion applies the treasury stock method to the equity-linked debt securities. These securities did not have a significant effect on diluted EPS for 2003.

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

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

Date of Issuance	Units Issued	Total Net Proceeds		Total Long- term Debt		Senior Notes Annual Interest Rate		Stock Purchase Contract Annual Rate		Total Equity Charge		Stock Purchase Settlement Date	Maturity of Senior Notes
	(millions, except percentages)
2000	8.3	$	400.1	$	412.5	3.66%	(1)	—%	(2)	$	20.7	11/04	11/06
2002	6.6	$	320.1	$	330.0	5.75%		3.00%		$	36.3	5/06	5/08

(1) Prior to their remarketing in November 2004, the senior notes carried an annual interest rate of 8.05%.

(2) The stock purchase contracts carried an annual interest rate of 1.45% prior to their settlement in November 2004.

Junior Subordinated Notes Payable to Affiliated Trusts

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

Under previous accounting guidance, Dominion consolidated the trusts in the preparation of its Consolidated Financial Statements. In accordance with FIN 46R, Dominion ceased to consolidate the trusts as of December 31, 2003 and instead reports as long-term debt on its Consolidated Balance Sheet the junior subordinated notes issued by Dominion and held by the trusts.

The following table provides summary information about the trust preferred securities and junior subordinated notes outstanding as of December 31, 2004:

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

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

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

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

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

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

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

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

D 2004/ Page 75

Notes to Consolidated Financial Statements, Continued

redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, it may not make any payments or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

18. Subsidiary Preferred Stock

Dominion is authorized to issue up to 20 million shares of preferred stock. During 2001, Dominion issued 665,000 shares of Series A mandatorily convertible preferred stock, liquidation preference $1,000 per share, to Piedmont Share Trust (Piedmont Trust) in connection with the formation of DFV and the issuance of senior notes by DFV. Dominion was the beneficial owner of the Piedmont Trust, which was consolidated in the preparation of Dominion’s Consolidated Financial Statements, thus eliminating the outstanding shares of preferred stock. During 2004, as a result of the retirement of DFV’s senior notes, the Piedmont Trust was dissolved and the outstanding shares of preferred stock were retired.

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

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

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

Presented below are the series of Virginia Power preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2004:

Dividend	Issued and Outstanding Shares		Entitled Per Share Upon Liquidation
	(thousands	)
$ 5.00	107		112.50
4.04	13		102.27
4.20	15		102.50
4.12	32		103.73
4.80	73		101.00
7.05	500		103.18	(1)
6.98	600		103.15	(2)
Flex MMP 12/02, Series A	1,250		100.00
Total	2,590

(1) Through 7/31/05; $102.82 commencing 8/1/05; amounts decline in steps thereafter to $100.00.

(2) Through 8/31/05; $102.80 commencing 9/1/05; amounts decline in steps thereafter to $100.00.

19. Shareholders’ Equity

Issuance of Common Stock

During 2004, Dominion issued 14 million shares of common stock and received proceeds of $839 million. Of this amount, 7 million shares and proceeds of $413 million resulted from the settlement of stock purchase contracts associated with Dominion’s 2000 issuance of equity-linked debt securities. Net proceeds were used for general corporate purposes, principally repayment of debt. The remainder of the shares issued and proceeds received in 2004 occurred through Dominion Direct^® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options. In 2005, Dominion Direct^® and the Dominion employee savings plans will purchase Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued.

Repurchases of Common Stock

In July 1998, Dominion was authorized by its Board of Directors to repurchase up to the lesser of 16.5 million shares, or $650 million of its outstanding common stock. As of December 31, 2004, Dominion had repurchased approximately 12 million shares for $537 million, with its last repurchase occurring in 2002. In February 2005, in order to recognize the significant increase in the size of the company and the market value of its common stock since the time of the previous authorization, Dominion’s Board of Directors superseded this authority, with new authority, to repurchase up to the lesser of 25 million shares or $2.0 billion of Dominion’s outstanding common stock.

D 2004/ Page 76

Notes to Consolidated Financial Statements, Continued

Forward Equity Transaction

In September 2004, Dominion entered into a forward equity sale agreement (forward agreement) with Merrill Lynch International (MLI), as forward purchaser, relating to 10 million shares of Dominion’s common stock. The forward agreement provides for the sale of two tranches of Dominion common stock, each with stated maturity dates and settlement prices. In connection with the forward agreement, MLI borrowed an equal number of shares of Dominion’s common stock from stock lenders and, at Dominion’s request, sold the borrowed shares to J.P. Morgan Securities Inc. (JPM) under a purchase agreement among Dominion, MLI and JPM. JPM subsequently offered the borrowed shares to the public. Dominion accounted for the forward agreement as equity at its initial fair value but did not receive any proceeds from the sale of the borrowed shares.

The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then existing market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. Except in specified circumstances or events that would require physical share settlement, Dominion may elect to settle the forward agreement by means of a physical share, cash or net share settlement and may also elect to settle the agreement in whole, or in part, earlier than the stated maturity date at fixed settlement prices. Under either a physical share or net share settlement, the maximum number of shares deliverable by Dominion under the terms of the forward agreement was limited to the 10 million shares specified in the two tranches. Assuming gross share settlement of all shares under the forward agreement, Dominion would have received aggregate proceeds of approximately $644 million, based on maturity forward prices of $64.62 per share for the 2 million shares included in the first tranche and $64.34 per share for the 8 million shares included in the second tranche.

However, Dominion elected to cash settle the first tranche in December 2004 and made a payment to MLI for $5.8 million, representing the difference between Dominion’s share price and the applicable forward sale price, multiplied by the 2 million shares. Dominion recorded the settlement payment as a reduction to common stock in its Consolidated Balance Sheet. Additionally, Dominion elected to cash settle 3 million shares of the second tranche in February 2005 and made a payment to MLI for $17.4 million.

The remaining 5 million shares of the second tranche must be settled by May 17, 2005. If gross share settlement were elected for the remainder of the second tranche at its maturity date, Dominion would receive aggregate proceeds of approximately $322 million and would deliver 5 million of its common shares. In the event any or all of theproceeds are not needed, Dominion has the option to either cash settle or net share settle the remainder of the second tranche of the forward agreement in whole, or in part, and may elect settlement earlier than the stated maturity date. If Dominion elects to cash or net share settle any portion of the remainder of the second tranche, the payment is based on the difference between Dominion’s share price and the applicable forward sale price for the second tranche, multiplied by the number of shares being settled.

If, at December 31, 2004, Dominion had elected a cash settlement of the 8 million shares in the second tranche, Dominion would have owed MLI $28 million, of which, $18 million would have represented settlement of the 5 million shares remaining in the second tranche after the February 2005 settlement. If, at the time of cash settlement, Dominion’s current share price were lower than the forward sale price, Dominion would receive a payment from MLI. For every dollar increase (decrease) in the value of Dominion’s stock, the value of the settlement of the shares remaining in the second tranche from MLI’s perspective would increase (decrease) by $5 million.

Dominion expects to use proceeds received from physical share settlements under the remainder of the second tranche of the forward agreement to fund part of the cost of acquiring the Kewaunee nuclear power plant in Wisconsin for $220 million (which is expected to close in the first half of 2005) and the acquisition of three electric generating stations from USGen for $642 million (which closed on January 1, 2005).

Shares Reserved for Issuance

At December 31, 2004, Dominion had a total of 47 million shares reserved and available for issuance for the following: Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans, stock purchase contracts associated with equity-linked debt securities and a forward equity sale agreement.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2004			2003
(millions)
Net unrealized losses on derivatives—hedging activities	$	(1,181	)	$	(768	)
Net unrealized gains on investment securities		149			89
Minimum pension liability adjustment		(14	)		(14	)
Foreign currency translation adjustments		50			64
Total accumulated other comprehensive loss	$	(996	)	$	(629	)

D 2004/ Page 77

Notes to Consolidated Financial Statements, Continued

Stock-Based Awards

The following table provides a summary of changes in amounts of Dominion stock options outstanding as of and for the years ended December 31, 2004, 2003 and 2002. Generally, the exercise price of Dominion employee stock options equals the market price of Dominion common stock on the date of grant.

	Stock Options		Weighted- average Exercise Price		Weighted- average Fair Value
	(thousands)
Outstanding at December 31, 2001	20,992		$	52.90
Exercisable at December 31, 2001	7,955		$	42.68
Granted—2002	3,122		$	62.28	$	10.91
Exercised, cancelled and forfeited	(3,057	)	$	44.54
Outstanding at December 31, 2002	21,057		$	55.49
Exercisable at December 31, 2002	8,586		$	47.95
Exercised, cancelled and forfeited	(2,513	)	$	44.39
Outstanding at December 31, 2003	18,544		$	56.97
Exercisable at December 31, 2003	11,604		$	54.44
Exercised, cancelled and forfeited	(4,736	)	$	47.67
Outstanding at December 31, 2004	13,808		$	60.17
Exercisable at December 31, 2004	10,768		$	60.01

There were no options granted in 2003 or 2004. The fair value of the options granted in 2002 were estimated on the dates of grant using the Black-Scholes option pricing model with the following weighted-average assumptions:

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

The following table provides certain information about stock options outstanding as of December 31, 2004:

		Options Outstanding			Options Exercisable
Exercise Price	Shares Outstanding	Weighted- average Remaining Contractual Life	Weighted- average Exercise Price		Shares Exercisable	Weighted- average Exercise Price
	(thousands)	(years)			(thousands)
$ 0-$19.99	2	4.0	$	19.10	2	$	19.10
$20-$30.99	24	4.1	$	24.88	24	$	24.88
$31-$40.99	30	5.0	$	39.25	30	$	39.25
$41-$50.99	1,318	5.7	$	45.99	1,192	$	45.50
$51-$60.99	8,021	4.2	$	59.91	5,924	$	59.90
$61-$69	4,413	6.4	$	65.23	3,596	$	65.41
Total	13,808	5.0	$	60.17	10,768	$	60.01

During 2004, 2003 and 2002, respectively, Dominion granted approximately 582,000 shares, 402,000 shares, and 14,000 shares of restricted stock with weighted-average fair values of $63.29, $56.08 and $60.62.

20. Dividend Restrictions

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. Dominion received dividends from its subsidiaries of $1.2 billion, $1.1 billion and $945 million in 2004, 2003 and 2002, respectively.

At December 31, 2004, Dominion’s consolidated subsidiaries had approximately $9.3 billion in capital accounts other than retained earnings, representing capital stock, other paid in capital and AOCI. Dominion Resources, Inc. had approximately $10.0 billion in capital accounts other than retained earnings at December 31, 2004. Generally, such amounts are not available for the payment of dividends by affected subsidiaries, or by Dominion itself, without specific authorization by the SEC.

In response to a Dominion request, the SEC granted relief in 2000, authorizing payment of dividends by CNG from other capital accounts to Dominion in amounts up to $1.6 billion, representing CNG’s retained earnings prior to Dominion’s acquisition of CNG. The SEC granted further relief in 2004, authorizing Dominion’s nonutility subsidiaries to pay dividends out of capital or unearned surplus in situations where such subsidiary has received excess cash from an asset sale, engaged in a restructuring, or is returning capital to an associate company. Dominion’s ability to pay dividends on its common stock at declared rates was not impacted by the restrictions discussed above during 2004, 2003 and 2002.

The Virginia State Corporation Commission (Virginia Commission) may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate, if found not to be in the public interest. At December 31, 2004, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2004.

See Note 17 for a description of potential restrictions on dividend payments by Dominion and certain subsidiaries in connection with the deferral of distribution payments on trust preferred securities.

21. Employee Benefit Plans

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

D 2004/ Page 78

Notes to Consolidated Financial Statements, Continued

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

Dominion provides retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date and years of service. In 2004, Dominion adopted a plan to amend its non-union retiree health care and life insurance plans. In connection with the amendment, eligible employees under age fifty-five share more of the costs of benefits with Dominion, and certain retiree medical benefits were enhanced. Dominion re-measured its accumulated postretirement benefit obligation during the third quarter of 2004 and as a result reduced the liability by $59 million. The impact of re-measurement on the 2004 postretirement net periodic benefits cost was not material. Dominion will amortize the unrecognized actuarial gains associated with the plan amendment over the average remaining service period of plan participants in accordance with SFAS No. 106,Employers’ Accounting for Postretirement Benefits Other Than Pensions.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was signed into law.The Medicare Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Based on an analysis performed by a third party actuary, Dominion has determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D and therefore expects to receive the federal subsidy offered under the Medicare Act. Dominion expects to receive subsidies of approximately $4 million annually during the period 2006 through 2009 and expects to receive approximately $26 million during the period 2010 through 2014. Dominion considered the passage of the Medicare Act a significant event requiring remeasurement of its APBO on December 8, 2003. Dominion will amortize the unrecognized actuarial gains associated with the benefits of the subsidy over the average remaining service period of plan participants in accordance with SFAS No. 106. Dominion uses December 31 as its measurement date for virtually all of its employee benefit plans. Dominion uses a market-related value of pension plan assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses.

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

	Pension Benefits						Other Postretirement Benefits
Year ended December 31,	2004			2003			2004			2003
(millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	3,110		$	2,799		$	1,351		$	1,119
Service cost		97			86			63			55
Interest cost		190			182			83			79
Benefits paid		(143	)		(159	)		(68	)		(60	)
Actuarial loss during the year		143			200			11			228
Actuarial gain related to Medicare Part D		—			—			—			(70	)
Plan amendments		13			2			(59	)		—
Benefit obligation at end of year		3,410			3,110			1,381			1,351
Change in plan assets:
Fair value of plan assets at beginning of year		3,734			3,074			587			443
Actual return on plan assets		453			627			60			89
Contributions		5			192			85			87
Benefits paid from plan assets		(143	)		(159	)		(35	)		(32	)
Fair value of plan assets at end of year		4,049			3,734			697			587
Funded status		639			624			(684	)		(764	)
Unrecognized net actuarial loss		1,225			1,244			366			392
Unrecognized prior service cost		28			18			(7	)		4
Unrecognized net transition (asset) obligation		—			—			27			82
Prepaid (accrued) benefit cost	$	1,892		$	1,886		$	(298	)	$	(286	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Prepaid pension cost	$	1,947		$	1,939			—			—
Accrued benefit liability		(94	)		(86	)	$	(298	)	$	(286	)
Intangible asset		15			9			—			—
Accumulated other comprehensive loss		24			24			—			—
Net amount recognized	$	1,892		$	1,886		$	(298	)	$	(286	)

D 2004/ Page 79

Notes to Consolidated Financial Statements, Continued

The accumulated benefit obligation for all defined benefit pension plans was $3.0 billion and $2.7 billion at December 31, 2004 and 2003, respectively. Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the third quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, the amount of contributions for the current year, if any, is determined at that time.

Included above are nonqualified and supplemental pension plans that do not have “plan assets” as defined by generally accepted accounting principles. The total projected benefit obligation for these plans was $112 million and $99 million at December 31, 2004 and 2003, respectively. The total accumulated benefit obligation for these plans was $97 million and $90 million at December 31, 2004 and 2003, respectively. Because the accumulated benefit obligation relating to these plans is in excess of the fair value of plan assets, Dominion recognized an additional minimum liability of $39 million and $34 million at December 31, 2004 and 2003, respectively.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Other Postretirement Benefits
(millions)
2005	$	152	$	70
2006		175		75
2007		155		80
2008		160		84
2009		165		89
2010-2014		1,108		528

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocation for Dominion’s pension fund is 45% U.S. equity securities; 8% non-U.S. equity securities; 22% debt securities; and 25% other, such as real estate and private equity investments. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. Dominion’s pension plans and other postretirement plans asset allocations at December 31, 2004 and 2003 are as follows:

	Pension Plans						Other Postretirement Plans
Year Ended December 31,	2004			2003			2004			2003
	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total	Fair Value		% of Total
(millions)
Equity securities:
U.S.	$	1,761	44	$	1,658	44	$	308	44	$	251	43
International		522	13		407	11		74	11		62	11
Debt securities		947	23		859	23		250	36		205	35
Real estate		298	7		264	7		17	2		14	2
Other		521	13		546	15		48	7		55	9
Total	$	4,049	100	$	3,734	100	$	697	100	$	587	100

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

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2004			2003			2002			2004			2003			2002
(millions)
Service cost	$	97		$	86		$	77		$	63		$	55		$	44
Interest cost		190			182			177			83			79			68
Expected return on plan assets		(336	)		(332	)		(349	)		(44	)		(33	)		(34	)
Amortization of prior service cost	2			2			1			—						1
Amortization of transition obligation		—			(2	)		(4	)		7			9			11
Amortization of net loss		56			20			2			21			20			5
Net periodic benefit cost (credit)	$	9		$	(44	)	$	(96	)	$	130		$	130		$	95

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

	Pension Benefits						Other Postretirement Benefits
	2004		2003		2002		2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%	6.25	%	6.75	%	7.25	%
Expected return on plan assets	8.75	%	8.75	%	9.50	%	7.79	%	7.78	%	7.82	%
Rate of increase for compensation	4.70	%	4.70	%	4.60	%	4.70	%	4.70	%	4.60	%
Medical cost trend rate(1)							9.00	%	9.00	%	9.00	%

(1) Decreasing to 5.00% in 2008 and years thereafter.

D 2004/ Page 80

Notes to Consolidated Financial Statements, Continued

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

	Pension Benefits				Other Postretirement Benefits
	2004		2003		2004		2003
Discount rate	6.00	%	6.25	%	6.00	%	6.25	%
Rate of increase for compensation	4.70	%	4.70	%	4.70	%	4.70	%

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:

• Historical return analysis to determine expected future risk premiums;

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

• Expected inflation and risk-free interest rate assumptions; and

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

Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions.

Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under Dominion’s plans.

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

			Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Effect on total service and interest cost components for 2004	$	22	$	(21	)
Effect on postretirement benefit obligation at December 31, 2004	$	173	$	(141	)

In addition, Dominion sponsors defined contribution thrift-type savings plans. During 2004, 2003 and 2002, Dominion recognized $29 million, $27 million and $26 million, respectively, as contributions to these plans.

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

22. Commitments and Contingencies

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

Long-Term Purchase Agreements

Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. Presented below is a summary of Dominion’s agreements as of December 31, 2004:

	2005		2006		2007		2008		2009		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	509	$	496	$	472	$	440	$	418	$	3,103	$	5,438
Production handling for gas and oil production operations(2)		56		54		51		38		23		27		249

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices, and payments for energy are based on the applicable pricing times the units of electrical energy delivered. At December 31, 2004, the present value of the total commitment for capacity payments is $3.4 billion. Capacity payments totaled $570 million, $611 million and $661 million, and energy payments totaled $293 million, $289 million and $219 million for 2004, 2003, and 2002, respectively.

(2) Payments under this contract, totaled $22 million and $10 million in 2004 and 2003, respectively. No payments were made under this contract in 2002.

In 2004, Dominion paid $153 million in cash and assumed $213 million of debt in connection with the termination of three long-term power purchase agreements and the acquisition of the related generating facilities used by non-utility generators to provide electricity to Dominion. In connection with the termination of the agreements, Dominion recorded after-tax charges totaling $43 million. These charges include the reversal of a $167 million pre-tax contract liability associated with one of the terminated agreements. The contract liability represented the remaining balance of the fair value recorded in October 2003 upon adoption of SFAS No. 133 Implementation Issue No. C20,Interpretation of the Meaning of “Not Clearly and Closely Related” in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature, (Issue C20). The power purchase agreement, which contained pricing terms linked to a broad market index, had to be recorded at fair value upon adoption of Issue C20; however, since it qualified as a normal purchase and sale contract, no further changes in its fair value were recognized. In 2003,

D 2004/ Page 81

Notes to Consolidated Financial Statements, Continued

Dominion paid $154 million for the purchase of a generating facility and the termination of two long-term power purchase agreements with non-utility generators. Dominion recorded after-tax charges totaling $65 million for the termination of the long-term power purchase agreements. Dominion allocates the purchase price to the assets and liabilities acquired and the terminated agreements based on their estimated fair values as of the date of acquisition.

In the fourth quarter of 2004, Dominion recorded a $112 million after-tax charge related to its interest in a long-term power tolling contract with a 551 megawatt combined cycle facility located in Batesville, Mississippi. Dominion decided to divest its interest in the long-term power tolling contract in connection with its reconsideration of the scope of certain activities of the Dominion Energy Clearinghouse, including those conducted on behalf of Dominion’s business segments, and its ongoing strategy to focus on business activities within the MAIN to Maine region. The charge is based on Dominion’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of Dominion’s interest in the contract in the first quarter of 2005.

Lease Commitments

Dominion leases various facilities, vehicles and equipment under both operating and capital leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2004 are as follows (in millions):

2005	2006		2007		2008		2009		Thereafter		Total
$133	$	117	$	108	$	97	$	87	$	365	$	907

Rental expense totaled $123 million, $105 million and $98 million for 2004, 2003 and 2002, respectively, the majority of which is reflected in other operations and maintenance expense.

Dominion has an agreement with a voting interest entity (lessor) to lease the Fairless power station in Pennsylvania (Fairless), which began commercial operations in June 2004. During construction, Dominion acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs advanced to the lessor. Project costs totaled $898 million at December 31, 2004. Dominion will make annual lease payments of $53 million, which are reflected in the lease commitments table above. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.

Environmental Matters

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

Historically, Dominion recovered such costs arising from regulated electric operations through utility rates. However, to the extent environmental costs are incurred in connection with operations regulated by the Virginia State Corporation Commission during the period ending December 31, 2010, in excess of the level currently included in Virginia jurisdictional rates, Dominion’s results of operations will decrease. After that date, Dominion may seek recovery through rates of only those environmental costs related to transmission and distribution operations.

Superfund Sites—From time to time, Dominion may be identified as a potentially responsible party to a Superfund site. The Environmental Protection Agency (EPA) (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. Dominion does not believe that any currently identified sites will result in significant liabilities.

In 1987, the EPA identified Dominion and a number of other entities as Potentially Responsible Parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Remediation design is ongoing for the Pennsylvania site, and total remediation costs are expected to be in the range of $13 million to $25 million. Based on allocation formulas and the volume of waste shipped to the site, Dominion has accrued a reserve of $2 million to meet its obligations at these two sites. Based on a financial assessment of the PRPs involved at these sites, Dominion has determined that it is probable that the PRPs will fully pay their share of the costs. Dominion generally seeks to recover its costs associated with environmental remediation from third party insurers. At December 31, 2004, any pending or possible claims were not recognized as an asset or offset against such obligations.

Other EPA Matters—In relation to a Notice of Violation received by Virginia Power in 2000 from the EPA, Dominion entered into a Consent Decree settlement in 2003 and committed to improve air quality. Dominion has already incurred certain capital expenditures for environmental improvements at its coal- fired stations in Virginia and West Virginia. Dominion continues to commit to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree.

D 2004/ Page 82

Notes to Consolidated Financial Statements, Continued

Other—Before being acquired by Dominion in 2001, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and 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 facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume. Although the results of litigation are inherently unpredictable, Dominion does not expect the ultimate outcome of the case to have a material adverse impact on its results of operations, cash flows or financial position.

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

Nuclear Operations

Nuclear Decommissioning—Minimum Financial Assurance—The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of its nuclear facilities. Dominion’s 2004 NRC minimum financial assurance amount, aggregated for the nuclear units, was $2.6 billion and has been satisfied by a combination of guarantees and the funds being collected and deposited in the trusts.

Nuclear Insurance—The Price-Anderson Act provides the public up to $10.8 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Dominion has purchased $300 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. The NRC exempted Millstone’s Unit 1 on March 30, 2004 from the Secondary Financial Retrospective Assessment, reducing Dominion’s licensed reactors to six. In the event of a nuclear incident at any licensed nuclear reactor in the United States, Dominion could be assessed up to $100.6 million for each of its six licensed reactors not to exceed $10 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The Price-Anderson Act was first enacted in 1957 and has been renewed three times—in 1967, 1975 and 1998. The Price-Anderson Act expired on August 31, 2002, but operating nuclear reactors continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation.

Dominion’s current level of property insurance coverage ($2.55 billion for North Anna, $2.55 billion for Surry, and $2.75 billion for Millstone) exceeds the NRC’s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss.The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Dominion’s nuclear property insurance is provided by the Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $83 million. Based on the severity of the incident, the board of directors of Dominion’s nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion has the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Dominion purchases insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, Dominion is subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $30 million.

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

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

Litigation

Virginia Power and Dominion Telecom were defendants in a class action lawsuit whereby the plaintiffs claimed that Virginia Power and Dominion Telecom strung fiber-optic cable across their land, along an electric transmission corridor without paying compensation. The plaintiffs sought damages for trespass and “unjust enrichment,” as well as punitive damages from the defendants. In April 2004, the parties entered into a settlement agreement that was subsequently approved by the court in July 2004. Under the terms of the settlement, a fund of $20 million has been established by Virginia Power to pay claims of current and former landowners as well as fees of lawyers for the class. Costs of notice to the class and administration of claims will be borne separately by Virginia Power. The settlement agreement resulted in an after-tax charge of $7 million in the first quarter of 2004.

D 2004/ Page 83

Notes to Consolidated Financial Statements, Continued

Enron Bankruptcy

During 2002, Dominion terminated all outstanding and open positions with Enron. Dominion submitted a claim in the Enron bankruptcy case for the value of such contracts, measured at the effective dates of contract termination. During the first quarter of 2004, the bankruptcy court approved a settlement of Dominion’s claim in the proceeding, resulting in a $2 million after-tax benefit.

Guarantees, Surety Bonds and Letters of Credit

Guarantees

As of December 31, 2004, Dominion and its subsidiaries had issued $7.8 billion of guarantees, including:

• $3.6 billion to support commodity transactions of subsidiaries;

• $1.7 billion for subsidiary debt reflected on the Consolidated Balance Sheets;

• $898 million related to a subsidiary leasing obligation for a new power generation project;

• $656 million associated with a subsidiary’s commitment to purchase three electric power generating facilities from USGen. The guarantee expired when Dominion completed the acquisition on January 1, 2005;

• $509 million related to subsidiaries’ nuclear decommissioning obligations;

• $408 million for guarantees supporting other agreements of subsidiaries; and

• $31 million for guarantees supporting third parties and equity method investees.

The commodity transaction guarantees are put in place to allow Dominion’s subsidiaries the flexibility to conduct business with counterparties without having to post substantial cash collateral. In order for Dominion to experience a liability for the $3.6 billion capacity of the guarantees, Dominion would have to fully utilize credit with every counterparty it has issued a guarantee, which management believes would be highly unlikely to occur. As of December 31, 2004, Dominion had entered into transactions with counterparties, whereby the net exposure under the guarantees related to these transactions was $678 million, which is included in the $795 million net amount due to these counterparties reported on Dominion’s Consolidated Balance Sheet at December 31, 2004.

There are no significant liabilities reflected on Dominion’s Consolidated Balance Sheets for its subsidiaries’ power generation project leasing obligation, nuclear obligations or other miscellaneous obligations.

While the majority of these guarantees do not have a termination date, Dominion may choose at any time to limit the applicability of such guarantees to future transactions.

As of December 31, 2004, substantially all of the officers’ borrowings under executive stock loan programs, which were guaranteed by Dominion, have been repaid. Because of restrictions on corporate loans or guarantees for executives under the Sarbanes-Oxley Act of 2002, Dominion has ceased its program of third party loans to executives for the purpose of acquiring company stock.

Surety Bonds and Letters of Credit

Dominion had also purchased $77 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.7 billion. Dominion enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties.

Indemnifications

As part of commercial contract negotiations in the normal course of business, Dominion may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate Dominion have not yet occurred or, if any such event has occurred, Dominion has not been notified of its occurrence. However, at December 31, 2004, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

Stranded Costs

In 1999, Virginia enacted the Virginia Restructuring Act that established a detailed plan to restructure Virginia’s electric utility industry. Under the Virginia Restructuring Act, the generation portion of Dominion’s Virginia jurisdictional operations is no longer subject to cost-based regulation. The legislation’s deregulation of generation was an event that required the discontinuance of SFAS No. 71 for the Virginia jurisdictional portion of Dominion’s generation operations in 1999. 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 by three and one-half years, to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

• Lock in Dominion’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;

• Provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and

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

Wires charges, also known as competitive transition charges, are permitted to be collected by utilities until July 1, 2007, under the Virginia Restructuring Act. Dominion has agreed to forego the collection of wires charges in 2005, and as such Virginia customers will not pay a fee if they switch from Dominion to a different service provider.

Dominion believes capped electric retail rates and, where applicable, wires charges provided under the Virginia Restructuring Act provide an opportunity to recover a portion of its potentially stranded

D 2004/ Page 84

Notes to Consolidated Financial Statements, Continued

costs, depending on market prices of electricity and other factors. Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market.

Even in the capped rate environment, Dominion remains exposed to numerous risks, including, among others, exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. At December 31, 2004, Dominion’s exposure to potentially stranded costs included: long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomic in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements.

23. Fair Value of Financial Instruments

Substantially all of Dominion’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Fair values have been determined using available market information and valuation methodologies considered appropriate by management. The financial instruments’ carrying amounts and fair values as of December 31, 2004 and 2003 were as follows:

	2004				2003
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Long-term debt	$	15,446	$	16,499	$	15,588	$	16,514
Junior subordinated notes payable to affiliated trusts		1,429		1,595		1,440		1,608

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

24. Credit Risk

Credit risk is the risk of financial loss to Dominion if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion maintains credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds held by Dominion that resulted from various trading counterparties exceeding agreed-upon credit limits established by Dominion. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from Dominion exceeding agreed-upon credit limits established by the counterparties. As of December 31,2004 and 2003, Dominion had margin deposit assets (reported in other current assets) of $179 million and $157 million, respectively, and margin deposit liabilities (reported in other current liabilities) of $28 million and $12 million, respectively.

Dominion maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on Dominion’s credit policies and its December 31, 2004 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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

Dominion’s exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy trading, marketing and commodity hedging activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy trading, marketing and hedging activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. At December 31, 2004, gross credit exposure related to these transactions totaled $1.27 billion, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, Dominion’s credit exposure is reduced to $1.25 billion. Of this amount, investment grade counterparties represent 85% and no single counterparty exceeded 6%.

25. Equity Method Investments and Affiliated Transactions

At December 31, 2004 and 2003, Dominion’s equity method investments totaled $387 million and $437 million, respectively, and equity earnings on these investments totaled $34 million in 2004, $25 million in 2003 and $11 million in 2002. Dominion received dividends from these investments of $37 million, $28 million and $36 million in 2004, 2003 and 2002, respectively. Dominion’s equity method investments are reported on the Consolidated Balance Sheets in other investments, except for the international investments discussed below, which are classified as part of assets held for sale in other current assets. Equity earnings on these investments are reported on the Consolidated Statements of Income in other income (loss). See Note 26 for discussion of DCI’s equity method investments.

D 2004/ Page 85

Notes to Consolidated Financial Statements, Continued

International Investments

CNGI was engaged in energy-related activities outside of the United States, primarily through equity investments in Australia and Argentina. After completing the CNG acquisition, Dominion’s management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on its core business.

During 2003, Dominion recognized impairment losses totaling $84 million ($69 million after-tax) related primarily to investments in a pipeline business located in Australia and a small generation facility in Kauai, Hawaii that was sold in December 2003 for cash proceeds of $42 million. These impairment losses represented adjustments to the assets’ carrying amounts to reflect Dominion’s then current evaluation of fair market value less estimated costs to sell, which were derived from a combination of actual 2003 transactions, management estimates, and other fair market value indicators.

In 2004, Dominion received cash proceeds of $52 million and recognized a gain in other income of $9 million from the sale of a portion of the Australian pipeline business in which CNGI held an investment. Dominion also recognized an $18 million benefit from an adjustment to the carrying amount of this investment to reflect its then current estimate of fair value, less estimated costs to sell.

At December 31, 2004, Dominion’s remaining CNGI investment is accounted for at fair value. Management expects this $4 million investment to be sold by the end of 2006.

26. Dominion Capital, Inc.

As of December 31, 2004, Dominion has substantially exited the core DCI financial services, commercial lending and residential mortgage lending businesses.

Dominion is required by the SEC under the 1935 Act to divest of all remaining DCI investment holdings by January 2006. Dominion’s Consolidated Balance Sheet reflects the following DCI assets as of December 31, 2004:

(millions)
Current assets	$	26
Available for sale securities		335
Other long-term investments		102
Property, plant and equipment, net		15
Deferred charges and other assets		121
Total	$	599

Securitizations of Financial Assets

At December 31, 2004 and 2003, DCI held $335 million and $413 million, respectively, of retained interests from the securitization of financial assets, which are classified as available-for-sale securities. The retained interests resulted from prior year securitizations of commercial loans receivable in collateralized loan obligation (CLO), collateralized debt obligation (CDO) and collateralized mortgage obligation (CMO) transactions.

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

Simultaneous with the above transaction, the new CDO structure acquired all of the loans held by two special purpose trusts that were established in 2001 and 2000 to facilitate DCI’s securitization of certain loan receivables. DCI’s original transfers of the loans to the CLO trusts qualified as sales under SFAS No. 125,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. Only after receiving consents from non-affiliated third parties, the CLO trusts’ governing agreements were amended to permit the sale of their financial assets into the new CDO structure in 2003. In consideration for the sale of loans to the new CDO structure, the trusts received $243 million of subordinated secured 3% notes in the new CDO structure and $119 million in cash, which was used by the CLO trusts to redeem all of their outstanding senior debt securities. As of December 31, 2003, Dominion still held residual interests in the CLO trusts, the value of which depended solely on the subordinated 3% notes issued by the new CDO. In connection with a review of the remaining assets in the CLO trusts, DCI recorded impairments totaling $23 million in 2003. Dominion received its distribution of the new CDO notes in the first quarter of 2004 upon liquidation of the trusts.

There were no mortgage securitizations in 2003 or 2004. Activity for the subordinated notes related to the new CDO structure, retained interests from securitizations of CMO’s and the CLO and CDO retained interests is summarized as follows:

	CMO			Retained Interests—CLO/CDO
(millions)
Balance at January 1, 2003	$	189		$	281
Amortization		(2	)		—
Cash received		(10	)		(1	)
Retained securitization					7
Fair value adjustment		(36	)		(15	)
Balance at December 31, 2003		141			272
Liquidation of retained interest in CLO trusts					(231	)
Distributions of new CDO notes to Dominion					235
Interest income					9
Amortization		(1	)		—
Cash received		(27	)		(4	)
Fair value adjustment		(46	)		(13	)
Balance at December 31, 2004	$	67		$	268

Key Economic Assumptions and Sensitivity Analyses

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

D 2004/ Page 86

Notes to Consolidated Financial Statements, Continued

Impairment Losses

The table below presents a summary of asset impairment losses associated with DCI operations.

Year Ended December 31	2004		2003		2002
(millions)
Retained interests from CMO securitizations(1)	$	46	$	36	$	11
Retained interests from CLO/CDO securitizations(1)		13		15		—
2003 CDO transactions		—		23		—
Venture capital and other equity investments(2)		26		16		—
Deferred tax assets(3)		—		26		—
Goodwill impairment(4)		—		18		13
Total	$	85	$	134	$	24

(1) As a result of economic conditions and historically low interest rates and the resulting impact on credit losses and prepayment speeds, Dominion recorded impairments of its retained interests from CMO, CDO and CLO securitizations in 2004, 2003 and 2002. Dominion updated its credit loss and prepayment assumptions to reflect its recent experience.

(2) Other impairments were recorded primarily due to asset dispositions.

(3) See Note 7 for discussion of deferred income taxes.

(4) See Note 13 for discussion of goodwill impairments.

27. Operating Segments

Dominion is organized primarily on the basis of products and services sold in the United States. Dominion manages its operations through the following segments:

Dominion Generationincludes the generation operations of Dominion’s electric utility and merchant fleet as well as coal and emissions trading and marketing activities.

Dominion Energy includes Dominion’s electric transmission, natural gas transmission pipeline and storage businesses, an LNG facility, certain natural gas production, as well as Clearinghouse (energy trading and marketing and aggregation of gas supply).

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

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

Corporate and Other includes the operations of Dominion’s corporate, service company and other operations (including unallocated debt), DCI and the net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004. In addition, the contribution to net income by Dominion’s primary operating segments is determined based upon a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments. These specific items are reported in the Corporate and Other segment and in 2004 include:

• Losses related to the discontinuance of hedge accounting for certain oil hedges and subsequent changes in the fair value of those hedges during the third quarter; and

• Charges reflecting Dominion’s valuation of its interest in a long-term power tolling contract and the termination of certain long-term power purchase agreements.

Specific items in 2003 include:

• Cumulative effect of changes in accounting principles;

• Incremental restoration expenses associated with Hurricane Isabel;

• Charges for the termination of certain long-term power purchase agreements and restructuring of certain electric sales contracts; and

• Severance costs for workforce reductions.

In 2002, there were no specific items attributable to Dominion’s primary operating segments reported in the Corporate and Other segment.

During the fourth quarter of 2004, Dominion performed an evaluation of its Dominion Energy Clearinghouse trading and marketing operations (Clearinghouse), 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 Clearinghouse coal and emissions trading and marketing activities in the Dominion Generation segment.

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

D 2004/ Page 87

Notes to Consolidated Financial Statements, Continued

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

	Dominion Generation		Dominion Energy		Dominion Delivery		Dominion E&P			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2004
Total revenue from external customers	$	5,144	$	2,047	$	3,757	$	2,272		$	69		$	683		$	13,972
Intersegment revenue		574		384		77		157			509			(1,701	)		—
Total operating revenue		5,718		2,431		3,834		2,429			578			(1,018	)		13,972
Interest income		52		14		8		2			269			(244	)		101
Interest and related charges		254		62		151		94			622			(244	)		939
Depreciation, depletion and amortization		282		116		316		558			35			(2	)		1,305
Equity in earnings of equity method investees		11		12		1		(1	)		11			—			34
Income tax expense (benefit)		321		119		256		314			(310	)		—			700
Loss from discontinued operations, net of tax		—		—		—		—			(15	)		—			(15	)
Net income (loss)		525		190		466		595			(527	)		—			1,249
Investment in equity method investees		162		94		5		40			86			—			387
Capital expenditures		623		354		441		1,311			21			—			2,750
Total assets (billions at December 31)		14.5		7.2		9.2		11.3			14.3			(11.1	)		45.4
2003
Total revenue from external customers	$	4,482	$	1,863	$	3,287	$	1,841		$	149		$	456		$	12,078
Intersegment revenue		293		493		61		150			591			(1,588	)		—
Total operating revenue		4,775		2,356		3,348		1,991			740			(1,132	)		12,078
Interest income		52		8		14		1			271			(237	)		109
Interest and related charges		239		64		171		82			656			(237	)		975
Depreciation, depletion and amortization		229		104		302		532			49			—			1,216
Equity in earnings of equity method investees		13		12		—		6			(6	)		—			25
Loss from discontinued operations, net of tax		—		—		—		—			(642	)		—			(642	)
Income tax expense (benefit)		312		223		236		220			(394	)		—			597
Net income (loss)		512		346		453		415			(1,408	)		—			318
Investment in equity method investees		166		85		5		51			130			—			437
Capital expenditures		1,303		319		485		1,311			20			—			3,438
Total assets (billions at December 31)		15.0		7.3		9.0		9.2			14.3			(11.3	)		43.5
2002
Total revenue from external customers	$	4,410	$	1,008	$	2,707	$	1,629		$	250		$	214		$	10,218
Intersegment revenue		51		386		23		90			568			(1,118	)		—
Total operating revenue		4,461		1,394		2,730		1,719			818			(904	)		10,218
Interest income		28		2		10		—			308			(248	)		100
Interest and related charges		234		56		171		88			644			(248	)		945
Depreciation, depletion and amortization		296		98		302		502			60			—			1,258
Equity in earnings of equity method investees		19		10		—		5			(23	)		—			11
Income tax expense (benefit)		330		172		201		165			(187	)		—			681
Net income (loss)	$	561	$	268	$	422	$	380		$	(269	)		—		$	1,362

As of December 31, 2004 and 2003, approximately 2% and 3%, respectively of Dominion’s total long-lived assets were associated with international operations. For the years ended December 31, 2004, 2003 and 2002, approximately 2%, 2% and 1%, respectively, of operating revenues were associated with international operations.

D 2004/ Page 88

Notes to Consolidated Financial Statements, Continued

28. Gas and Oil Producing Activities (unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation, depletion and amortization, at December 31, 2004 and 2003 follow:

	2004		2003
(millions)
Capitalized costs of:
Proved properties	$	8,246	$	7,561
Unproved properties		1,623		1,721
		9,869		9,282
Accumulated depreciation of:
Proved properties		1,921		1,476
Unproved properties		109		126
		2,030		1,602
Net capitalized costs	$	7,839	$	7,680

Total Costs Incurred

The following costs were incurred in gas and oil producing activities during the years ended December 31, 2004, 2003 and 2002:

	2004						2003						2002
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Property acquisition costs:
Proved properties	$	20	$	20		—	$	181	$	181		—	$	243	$	243		—
Unproved properties		116		102	$	14		133		125	$	8		177		170	$	7
		136		122		14		314		306		8		420		413		7
Exploration costs		213		199		14		291		266		25		267		260		7
Development costs(1)		915		841		74		667		604		63		760		679		81
Total	$	1,264	$	1,162	$	102	$	1,272	$	1,176	$	96	$	1,447	$	1,352	$	95

(1) Development costs incurred for proved undeveloped reserves were $172 million, $182 million and $223 million for 2004, 2003 and 2002, respectively.

Results of Operations

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

	2004						2003						2002
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Revenue (net of royalties) from:
Sales to nonaffiliated companies	$	1,526	$	1,297	$	229	$	1,736	$	1,552	$	184	$	1,396	$	1,257	$	139
Transfers to other operations		195		195		—		185		185		—		97		97		—
Total		1,721		1,492		229		1,921		1,737		184		1,493		1,354		139
Less:
Production (lifting) costs		394		309		85		357		294		63		272		220		52
Depreciation, depletion and amortization		560		497		63		526		470		56		502		452		50
Income tax expense		295		266		29		356		350		6		222		209		13
Results of operations	$	472	$	420	$	52	$	682	$	623	$	59	$	497	$	473	$	24

D 2004/ Page 89

Notes to Consolidated Financial Statements, Continued

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 2004, 2003 and 2002, and changes in the reserves during those years, are shown in the two schedules that follow:

	2004						2003						2002
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(billion cubic feet)
Proved developed and undeveloped reserves—Gas
At January 1	5,369		4,801		568		5,098		4,458		640		4,090		3,517		573
Changes in reserves:
Extensions, discoveries and other additions	400		342		58		821		767		54		874		769		105
Revisions of previous estimates(1)	(28	)	163		(191	)	(147	)	(71	)	(76	)	158		145		13
Production	(371	)	(327	)	(44	)	(396	)	(346	)	(50	)	(399	)	(346	)	(53	)
Purchases of gas in place	10		10		—		133		133		—		381		379		2
Sales of gas in place	(377	)	(85	)	(292	)	(140	)	(140	)	—		(6	)	(6	)	—
At December 31	5,003		4,904		99		5,369		4,801		568		5,098		4,458		640
Proved developed reserves—Gas
At January 1	4,006		3,553		453		4,035		3,549		486		3,466		3,026		440
At December 31	3,776		3,680		96		4,006		3,553		453		4,035		3,549		486
Proved developed and undeveloped reserves—Oil
(thousands of barrels)
At January 1	169,934		135,914		34,020		169,230		138,798		30,432		140,567		115,988		24,579
Changes in reserves:
Extensions, discoveries and other additions	9,386		7,546		1,840		13,223		7,818		5,405		24,326		24,273		53
Revisions of previous estimates(2)	(17,911	)	(5,584	)	(12,327	)	697		1,433		(736	)	11,165		4,293		6,872
Production	(10,001	)	(8,800	)	(1,201	)	(8,723	)	(7,642	)	(1,081	)	(9,725	)	(8,653	)	(1,072	)
Purchases of oil in place	666		666		—		380		380		—		2,928		2,928		—
Sales of oil in place	(3,476	)	(818	)	(2,658	)	(4,873	)	(4,873	)	—		(31	)	(31	)	—
At December 31	148,598		128,924		19,674		169,934		135,914		34,020		169,230		138,798		30,432
Proved developed reserves—Oil
At January 1	59,754		42,347		17,407		65,823		47,759		18,064		63,777		46,473		17,304
At December 31	98,841		87,382		11,459		59,754		42,347		17,407		65,823		47,759		18,064

(1) Approximately 187 Bcf of the Canadian reserve revisions pertained to properties sold in 2004 and resulted from performance-based reserve reclassifications from proved undeveloped to unproved.

(2) Approximately 8.3 million barrels of the Canadian reserve revisions pertained to properties sold in 2004 and resulted from performance-based reserve re-determinations on two British Columbia enhanced oil recovery projects.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

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

	2004						2003						2002
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
(millions)
Future cash inflows(1)	$	36,819	$	35,735	$	1,084	$	36,486	$	32,922	$	3,564	$	28,337	$	25,344	$	2,993
Less:
Future development costs(2)		1,527		1,488		39		1,505		1,391		114		1,092		1,005		87
Future production costs		5,609		5,302		307		5,582		4,765		817		3,603		2,979		624
Future income tax expense		10,152		9,909		243		9,457		8,715		742		7,582		6,904		678
Future cash flows		19,531		19,036		495		19,942		18,051		1,891		16,060		14,456		1,604
Less annual discount (10% a year)		10,505		10,275		230		10,709		9,745		964		8,255		7,436		819
Standardized measure of discounted future net cash flows	$	9,026	$	8,761	$	265	$	9,233	$	8,306	$	927	$	7,805	$	7,020	$	785

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

(2) Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $451 million, $223 million and $236 million for 2005, 2006 and 2007, respectively.

D 2004/ Page 90

Notes to Consolidated Financial Statements, Continued

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

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

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

	2004			2003			2002
(millions)
Standardized measure of discounted future net cash flows at January 1	$	9,233		$	7,805		$	3,213
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(2,004	)		(1,997	)		(1,086	)
Prices and production and development costs related to future production		1,656			480			3,975
Extensions, discoveries and other additions, less production and development costs		1,118			1,920			2,039
Previously estimated development costs incurred during the year		172			182			223
Revisions of previous quantity estimates		(734	)		(918	)		(152	)
Accretion of discount		1,359			1,149			426
Income taxes		(291	)		(679	)		(2,639	)
Other purchases and sales of proved reserves in place		(878	)		84			799
Other (principally timing of production)		(605	)		1,207			1,007
Standardized measure of discounted future net cash flows at December 31	$	9,026		$	9,233		$	7,805

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Notes to Consolidated Financial Statements, Continued

29. Quarterly Financial and Common Stock Data (unaudited)

A summary of the quarterly results of operations for the years ended December 31, 2004 and 2003 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2004
Operating revenue	$	3,879	$	3,040	$	3,292		$	3,761		$	13,972
Income from operations		890		580		744			503			2,717
Income from continuing operations before cumulative effect of changes in accounting principles		445		258		337			224			1,264
Net income		437		251		337			224			1,249
Basic EPS:
Income from continuing operations before cumulative effect of changes in accounting principles		1.37		0.79		1.02			0.67			3.84
Net income		1.35		0.76		1.02			0.67			3.80
Diluted EPS:
Income from continuing operations before cumulative effect of changes in accounting principles		1.36		0.79		1.02			0.67			3.82
Net income		1.34		0.76		1.02			0.67			3.78
Dividends paid per share		0.645		0.645		0.645			0.665			2.60
Common stock prices (high-low)		65.85-		64.75-		65.87-			68.85-			68.85-
	$	61.20	$	60.78	$	62.07		$	62.97		$	60.78
2003
Operating revenue	$	3,579	$	2,630	$	2,853		$	3,016		$	12,078
Income from operations		1,014		577		698			272			2,561
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		409		246		326			(32	)		949
Net income (loss)		508		240		(256	)		(174	)		318
Basic EPS:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		1.33		0.78		1.01			(0.10	)		2.99
Net income (loss)		1.64		0.76		(0.79	)		(0.54	)		1.00
Diluted EPS:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles		1.32		0.78		1.01			(0.10	)		2.98
Net income (loss)		1.64		0.76		(0.79	)		(0.54	)		1.00
Dividends paid per share		0.645		0.645		0.645			0.645			2.58
Common stock prices (high-low)		58.62-		65.95-		64.28-			64.45-			65.95-
	$	51.74	$	54.75	$	58.05		$	59.27		$	51.74

Dominion’s 2004 results include the impact of the following significant items:

• Third quarter results include $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges; and

• Fourth quarter results include a $112 million after-tax charge reflecting Dominion’s valuation of its interest in a long-term power tolling contract that is subject to a planned divestiture in the first quarter of 2005 and a $61 million after-tax benefit due to the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan.

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Dominion’s 2003 results include the impact of the following significant items:

• First quarter results include a $113 million after-tax gain representing the cumulative effect of adopting SFAS No. 143 and EITF 02-3 described in Note 3 and $63 million of losses related to Dominions discontinued telecommunications operations described in Note 9.

• Third quarter results include $80 million of after-tax incremental restoration expenses associated with Hurricane Isabel and $582 million of losses related to Dominion’s discontinued telecommunications operations described in Note 9; and

• Fourth quarter results include $42 million of after-tax incremental restoration expenses associated with Hurricane Isabel, $100 million of losses related to Dominion’s discontinued telecommunications operations described in Note 9 and a $102 million after-tax loss representing the cumulative effect of adopting Issue C20 and FIN 46R described in Note 3.

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

None.

Item 9A. Controls and Procedures

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

See Item 8. Financial Statements and Supplementary Data forManagement’s Annual Report On Internal Control Over Financial Reporting and the Independent Registered Public Accounting Firm’s report with respect to management’s assessment of the effectiveness of internal control over financial reporting.

Item 9B. Other Information

On February 25, 2005, Thomas F. Farrell, II, was elected to Dominion’s Board of Directors, effective March 1, 2005. Mr. Farrell is also President and Chief Operating Officer of Dominion and during 2004 received an annual salary and other compensation for such service as reported underExecutive Compensation in Dominion’s 2005 Proxy Statement, File No. 1-8489. At this time, Mr. Farrell has not been appointed to serve on any Board committees.

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Part III

Item 10. Directors and Executive Officers of the Registrant

The following information is incorporated by reference from the 2005 Proxy Statement, File No. 1-8489, which will be filed on or around March 18, 2005 (the 2005 Proxy Statement):

• Information regarding the directors required by this item is found under the headingElection of Directors.

• Information regarding Dominion’s Audit Committee required by this item is found under the headingThe Board.

• Information regarding Dominion’s Code of Ethics required by this item is found under the headingGovernance.

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

Item 11. Executive Compensation

The information regarding executive compensation contained under the headingsCommittee Report on Executive Compensationand Executive Compensation and the information regarding director compensation contained under the headingThe Board in the 2005 Proxy Statement is incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headingShare Ownership in the 2005 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the headingExecutive Compensation—Equity Compensation Plansin the 2005 Proxy Statement is incorporated by reference.

Item 13. Certain Relationships and Related Transactions

The information concerning certain transactions with executive officers under the headingExecutive Compensation—Executive Stock Purchase Programs and other transactions contained under the headingCertain Relationships in the 2005 Proxy Statement is incorporated by reference.

Item 14. Principal Accountant Fees and Services

The information concerning principal accounting fees and services contained under the headingAuditors in the 2005 Proxy Statement is incorporated by reference.

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Part IV

Item 15. Exhibits and Financial Statement Schedules

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

1. Financial Statements

    See Index on page 47.

2. Financial Statement Schedules

	Page
Report of Independent Registered Public Accounting Firm	100
Schedule I—Condensed Financial Information of Registrant	101

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

3. Exhibits

3.1	Articles of Incorporation as in effect August 9, 1999, as amended effective March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference).
3.2	Bylaws as in effect on October 20, 2000 (Exhibit 3, Form 10-Q for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference).
4.1	See Exhibit 3.1 above.
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by fifty-eight Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255, incorporated by reference); Sixty-Seventh Supplemental Indenture (Exhibit 4(i), Form 8-K, dated April 2, 1991, File No. 1-2255, incorporated by reference); Seventieth Supplemental Indenture, (Exhibit 4(iii), Form 8-K, dated February 25, 1992, File No. 1-2255, incorporated by reference); Seventy-First Supplemental Indenture (Exhibit 4(i)) and Seventy-Second Supplemental Indenture, (Exhibit 4(ii), Form 8-K, dated July 7, 1992, File No. 1-2255, incorporated by reference); Seventy-Third Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 6, 1992, File No. 1-2255, incorporated by reference); Seventy-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Fifth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 6, 1993, File No. 1-2255, incorporated by reference); Seventy-Sixth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated April 21, 1993, File No. 1-2255, incorporated by reference); Seventy-Seventh Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated June 8, 1993, File No. 1-2255, incorporated by reference); Seventy-Eighth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Seventy-Ninth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated August 10, 1993, File No. 1-2255, incorporated by reference); Eightieth Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated October 12, 1993, File No. 1-2255, incorporated by reference); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Eighty-Second Supplemental Indenture, (Exhibit 4(i), Form 8-K, dated January 18, 1994, File No. 1-2255, incorporated by reference); Eighty-Third Supplemental Indenture (Exhibit 4(i), Form 8-K, dated October 19, 1994, File No. 1-2255, incorporated by reference); Eighty-Fourth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated March 23, 1995, File No. 1-2255, incorporated by reference); and Eighty-Fifth Supplemental Indenture (Exhibit 4(i), Form 8-K, dated February 20, 1997, File No. 1-2255, incorporated by reference).
4.3	Indenture, dated as of June 1, 1986, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank) (Exhibit 4(v), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference).
4.4	Indenture, dated April 1, 1988, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as supplemented and modified by a First Supplemental Indenture, dated August 1, 1989, (Exhibit 4(vi), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255, incorporated by reference); Second Supplemental Indenture, dated May 1, 1999 (Exhibit 4.2, Form S-3, File No. 333-7615, as filed on April 13, 1999, incorporated by reference).
4.5	Subordinated Note Indenture, dated as of August 1, 1995 between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank), as Trustee (Exhibit 4(a), Form S-3 Registration Statement File No. 333-20561 as filed on January 28, 1997, incorporated by reference), Form of Second Supplemental Indenture (Exhibit 4.6, Form 8-K filed August 20, 2002, No. 1-2255, incorporated by reference).
4.6	Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999,

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	File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated January 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference).
4.7	Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement, File No. 333-50653, as filed on April 21, 1998, incorporated by reference); Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K, dated January 9, 2001, incorporated by reference).
4.8	Indenture, dated as of May 1, 1971, between Consolidated Natural Gas Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012, incorporated by reference); Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651, incorporated by reference); Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Eighteenth Supplemental Indenture dated as of December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Twentieth Supplemental Indenture dated as of March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-3196, incorporated by reference).
4.9	Indenture, dated as of April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to United States Trust Company of New York) (Exhibit (4) to Certificate of Notification at Commission File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4 A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004, incorporated by reference).
4.10	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and JP Morgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4 (iii), Form S-3, Registration Statement, File No. 333-93187, incorporated by reference); First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K, dated June 21, 2000, File No. 1-8489, incorporated by reference); Second Supplemental Indenture, dated July 1, 2000 (Exhibit 4.2, Form 8-K, dated July 11, 2000, File No. 1-8489, incorporated by reference); Third Supplemental Indenture, dated July 1, 2000 (Exhibit 4.3, Form 8-K dated July 11, 2000, incorporated by reference); Fourth Supplemental Indenture and Fifth Supplemental Indenture dated September 1, 2000 (Exhibit 4.2, Form 8-K, dated September 8, 2000, incorporated by reference); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K, dated September 8, 2000, incorporated by reference); Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K, dated October 11, 2000, incorporated by reference); Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K, dated January 23, 2001, incorporated by reference); Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K, dated May 25, 2001, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1-8489, incorporated by reference.); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489, incorporated by reference); Thirteenth Supplemental Indenture dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489, incorporated by reference); Fourteenth Supplemental Indenture, dated August 20, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489, incorporated by reference); Forms of Fifteenth and Sixteenth Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed December 12, 2002, File No. 1-8489, incorporated by reference); Forms of Seventeenth and Eighteenth Supplemental Indentures (Exhibits 4.2. and 4.3 to Form 8-K filed February 11, 2003, File No. 1-8489, incorporated by reference);

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	Forms of Twentieth and Twenty-first Supplemental Indentures (Exhibits 4.2 and 4.3 to Form 8-K filed March 4, 2003, File No. 1-8489, incorporated by reference); Form of Twenty-second Supplemental Indenture (Exhibit 4.2 to Form 8-K filed July 22, 2003, File No. 1-8489 incorporated by reference); Form of Twenty-Third Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 9, 2003, File No. 1-8489, incorporated by reference); Form of Twenty-Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference); Form of Twenty-Sixth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 14, 2004, File No. 1-8489, incorporated by reference).
4.11	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.1, Form S-3 File No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K, File dated April 12, 2001, File No. 1-3196 incorporated by reference); Second Supplemental Indenture, dated October 25, 2001 (Exhibit 4.1, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Third Supplemental Indenture, dated October 25, 2001 (Exhibit 4.3, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K, dated May 22, 2002, Form 1-3196, incorporated by reference); Form of Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196, incorporated by reference).
4.12	Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.2, Form S-3 Registration No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K, dated October 16, 2001, File No. 1-3196, incorporated by reference).
4.13	Indenture, dated as of June 15, 1994, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration and Production, Inc. and The Bank of New York (as successor trustee to Bank of Montreal Trust Company) (Exhibit 4.13, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001(Exhibit 4.7, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).
4.14	Indenture, dated as of December 11, 1997, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration & Production, Inc., and La Salle Bank National Association (formerly LaSalle National Bank) (Exhibit 4.14, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001 (Exhibit 4.9, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).
4.15	Dominion Resources, Inc. agrees to furnish to the Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of Dominion Resources, Inc.’s total consolidated assets.
10.1	Amended and Restated Interconnection and Operating Agreement, dated as of July 29, 1997 between Virginia Electric and Power Company and Old Dominion Electric Cooperative (Exhibit 10(v), Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8489, incorporated by reference).
10.2	DRI Services Agreement, dated January 28, 2000, by and between Dominion Resources, Inc., Dominion Resources Services, Inc. and Consolidated Natural Gas Service Company, Inc. (Exhibit 10(viii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8489, incorporated by reference).
10.2	Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).
10.3	PJM South Implementation Agreement between Virginia Electric and Power Company and PJM Interconnection, L.L.C., dated September 30, 2002, as amended December 6, 2002 (Exhibit 10.4, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.4	$1,500,000,000 Three Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated May 27, 2004 (Exhibit 10.3, Form 10-Q for the quarter ended March 31, 2004, File No. 1-8489, incorporated by reference).
10.5	$1,500,000,000 Three-Year Credit Agreement among Consolidated Natural Gas Company and Barclays Bank, as Administrative Agent for the Lenders, dated August 10, 2004 (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2004, File No. 1-8489, incorporated by reference).
10.6	$750,000,000 Three-Year Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company and JPMorgan Chase Bank, as Administrative Agent for the Lenders, dated as of May 30, 2002 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2003, File No. 1-8489, incorporated by reference).

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10.7	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Dominion (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489, incorporated by reference).
10.8*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.9*	Dominion Resources, Inc.’s Cash Incentive Plan as adopted December 20, 1991 (Exhibit 10(xxii), Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8489, incorporated by reference).
10.10*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference).
10.11*	Dominion Resources, Inc. Executive Stock Purchase and Loan Plan II, dated February 15, 2000 (Exhibit 10.10, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.12*	Form of Employment Continuity Agreement for certain officers of Dominion, amended and restated July 15, 2003 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003, File No. 1-8489, incorporated by reference).
10.13*	Dominion Resources, Inc. Retirement Benefit Funding Plan, effective June 29, 1990 as amended and restated September 1, 1996 (Exhibit 10(iii), Form 10-Q for the quarter ended June 30, 1997, File No. 1-8489, incorporated by reference).
10.14*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.15*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.16*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.17*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.18*	Dominion Resources, Inc. New Deferred Compensation Plan, effective January 1, 2005 (Exhibit 10.10, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.19*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.20*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.21*	Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002, incorporated by reference); amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.22*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005 (Exhibit 10.4, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.23*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001, File No. 1-8489, incorporated by reference).
10.24*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated December 17, 2004 (Exhibit 10.11, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.25*	Dominion Resources, Inc. Stock Purchase Tool Kit Restricted Stock Exchange Form of Restricted Stock Award Agreement (Exhibit 10.12, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.26*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489, incorporated by reference).
10.27*	Arrangement with Thos. E. Capps regarding additional credited years of service for retirement and retirement life insurance purposes (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.28*	Employment Agreement dated September 30, 2002 between Dominion and Thos. E. Capps (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2002, File No. 1-8489, incorporated by reference) including supplemental letter, dated February 27, 2003 (Exhibit 10.22, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.29*	Form of Reimbursement Agreement between certain executive officers and Dominion (Exhibit 10(xxvii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-2255, incorporated by reference).

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10.30*	Letter agreement between Dominion and Thomas F. Farrell, II (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.31*	Letter agreement between Dominion and Thomas N. Chewning (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.32*	Offer of employment dated March 16, 2001 between Dominion and Duane C. Radtke (Exhibit 10.26, Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8489, incorporated by reference).
10.33*	Supplemental Retirement Agreement, dated October 15, 2004 between Dominion and Duane C. Radtke (Exhibit 10, Form 8-K filed October 19, 2004, File No. 1-8489, incorporated by reference).
10.34*	Base salaries for named executive officers (filed herewith).
10.35*	Non-employee directors’ annual compensation (filed herewith).
12	Ratio of earnings to fixed charges (filed herewith).
21	Subsidiaries of the Registrant (filed herewith).
23.1	Consent of Deloitte & Touche LLP (filed herewith).
23.2	Consent of Ralph E. Davis Associates, Inc. (filed herewith).
23.3	Consent of Ryder Scott Company, L.P. (filed herewith).
31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

* Indicates management contract or compensatory plan or arrangement.

D 2004/ Page 99

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the consolidated financial statements of Dominion Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated February 28, 2005 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph as to changes in accounting principles in 2003 for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees); such reports are included elsewhere in this Annual Report on Form 10-K. Our audits also included the financial statement schedule of the Company listed in Item 15. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

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Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Statements of Income

Year Ended December 31,	2004			2003			2002
(millions)
Operating Expenses
Affiliated	$	10		$	22		$	22
Other		(5	)		10			11
Total operating expense		5			32			33
Loss from operations		(5	)		(32	)		(33	)
Other income (expense):
Affiliated interest income		155			137			85
Other		4			(28	)		7
Total other income		159			109			92
Interest and related charges:
Affiliated interest expense		69			73			68
Other		376			408			353
Total interest and related charges		445			481			421
Loss before income taxes		(291	)		(404	)		(362	)
Income tax benefit		160			163			121
Equity in earnings of affiliates		1,395			1,201			1,603
Income from continuing operations		1,264			960			1,362
Loss from discontinued operations (net of income tax benefit of $4 and expense of $15 in 2004 and 2003, respectively)		(15	)		(642	)		—
Net Income	$	1,249		$	318		$	1,362

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

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Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Balance Sheets

At December 31,	2004			2003
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	10		$	9
Receivables and advances due from affiliates		2,858			2,831
Other accounts receivable		7			—
Prepayments		—			61
Total current assets		2,875			2,901
Investments
Investment in affiliates		14,474			14,543
Loans to affiliates		1,645			1,699
Other		39			32
Total investments		16,158			16,274
Property, Plant and Equipment, Net
Property, plant and equipment		3			6
Accumulated depreciation, depletion and amortization		—			(3	)
Total property, plant and equipment, net		3			3
Deferred Charges and Other Assets		125			37
Total assets	$	19,161		$	19,215
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,090		$	268
Short-term debt		306			573
Payables and short-term borrowings due to affiliates		16			82
Accrued interest and taxes		129			108
Other		39			5
Total current liabilities		1,580			1,036
Long-Term Debt
Long-term debt		5,284			6,069
Notes payable to affiliates		822			848
Total long-term debt		6,106			6,917
Deferred Credits and Other Liabilities		49			59
Total liabilities		7,735			8,012
Preferred Stock		—			665
Common Shareholders’ Equity
Common stock, no par(1)		10,888			10,052
Other paid-in capital		92			61
Retained earnings		1,442			1,054
Accumulated other comprehensive loss		(996	)		(629	)
Total common shareholders’ equity		11,426			10,538
Total liabilities and shareholders’ equity	$	19,161		$	19,215

(1) 500 million shares authorized; 340 million shares and 325 million shares outstanding at December 31, 2004 and 2003, respectively.

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

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Dominion Resources, Inc. (Parent Company)

Schedule I—Condensed Financial Information of Registrant

Condensed Statements of Cash Flows

Year Ended December 31,	2004			2003			2002
(millions)
Net Cash Provided By Operating Activities	$	754		$	690		$	547
Investing Activities
Investment in affiliates		(527	)		(77	)		(95	)
Affiliate (advances) repayment, net		64			(1,296	)		(2,435	)
Loans to affiliates		—			(220	)		—
Purchase of Dominion Fiber Ventures senior notes		—			(633	)		—
Escrow release (deposit) for debt refunding		—			500			(500	)
Other		—			—			(3	)
Net cash used in investing activities		(463	)		(1,726	)		(3,033	)
Financing Activities
Issuance of common stock		839			990			2,020
Repurchase of common stock		—			—			(66	)
Issuance of long-term debt		300			2,120			1,680
Repayment of long-term debt		(268	)		(1,500	)		—
Issuance (repayment) of short-term debt, net		(267	)		219			(294	)
Repayment of short-term borrowings from affiliates, net		(24	)		—			—
Repayment of notes payable to affiliates		—			(15	)		(227	)
Common dividends paid		(861	)		(825	)		(723	)
Other		(9	)		(18	)		(11	)
Net cash (used in) provided by financing activities		(290	)		971			2,379
Increase (decrease) in cash and cash equivalents		1			(65	)		(107	)
Cash and cash equivalents at beginning of the year		9			74			181
Cash and cash equivalents at end of the year	$	10		$	9		$	74
Supplemental Cash Flow Information:
Noncash transactions from investing and financing activities:
Conversion of short-term advances and other amounts receivable from subsidiaries to investment in subsidiaries	$	84		$	1,220		$	959
Return of preferred stock from beneficially owned trust		665			—			—
Forgiveness of Dominion Fiber Ventures, LLC notes receivable		644			—			—
Conversion of interest receivable from subsidiaries to long-term note receivable		—			125			—
Subsidiary common stock received in exchange for reduction in amounts receivable from subsidiary		—			—			150
Exchange of debt securities		219			500			450

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

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Dominion Resources, Inc. (Parent Company)

Schedule I — Condensed Financial Information of Registrant

Notes to Condensed Financial Statements

1. Basis of Presentation

Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Dominion Resources, Inc. (the Company) do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2004 Form 10-K, Part II, Item 8.

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

Income Taxes—The Company and its subsidiaries file a consolidated federal income tax return and participate in an intercompany tax allocation agreement. At December 31, 2004 and 2003, the Company’s Balance Sheets include current taxes receivable from affiliates of $32 million and current taxes payable to affiliates of $14 million, respectively. Under the 1935 Public Utility Holding Company Act (1935 Act), the Company is restricted in the amount of cash reimbursements that it may receive from subsidiaries.

2. Long-Term Debt

At December 31,	2004 Weighted average Coupon(1)	2004			2003
(millions)
Unsecured Senior and Medium-Term Notes:
2.25% to 7.625%, due 2004 to 2008	4.85%	$	2,002		$	1,740
5.0% to 8.125%, due 2009 to 2033(2)	6.25%		3,880			3,680
Unsecured Equity-Linked Senior Notes, 5.75% due 2008	5.75%		330			743
Unsecured Convertible Senior Notes, 2.125%, due 2023(3)			220			220
Unsecured Nonrecourse Debt:
Variable Rates, due 2004			—			18
			6,432			6,401
Fair value hedge valuation(4)			2			2
Amount due within one year	5.85%		(1,090	)		(268	)
Unamortized discount			(60	)		(66	)
			5,284			6,069
Notes Payable—Affiliates:
Unsecured Other Affiliated Notes Payable, 6.0%, due 2005(5)			—			26
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% to 8.4%, due 2027 to 2041	8.22%		825			825
			825			851
Amount due within one year			—			—
Unamortized discount			(3	)		(3	)
			822			848
Total long-term debt		$	6,106		$	6,917

(1) Represents weighted-average coupon rates during 2004 for debt outstanding as of December 31, 2004.

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

(3) Convertible into a combination of cash and Dominion’s common stock at any time after March 31, 2004 when the average closing price of Dominion common stock reaches $88.32 per share for a specified period. At the option of holders on December 15, 2006, December 15, 2008, December 15, 2013, or December 15, 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest.

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

(5) Debt was redeemed in December 2004.

Based on the stated maturity dates rather than the early redemption dates that could be elected by the instrument holders, noted above, the scheduled principal payments of long-term at December 31, 2004 were as follows (in millions):

2005	2006		2007		2008		2009		Thereafter		Total
$1,090	$	512	$	—	$	730	$	300	$	4,625	$	7,257

The Company’s long-term debt agreements contain customary covenants and default provisions. As of December 31, 2004, there were no events of default under those covenants.

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3. Guarantees, Letters of Credit and Surety Bonds

Guarantees Supporting Related Parties

As of December 31, 2004, substantially all of the officers’ borrowings under executive stock loan programs, which were guaranteed by the Company, have been repaid. Because of restrictions on corporate loans or guarantees for executives under the Sarbanes-Oxley Act of 2002, the Company has ceased its program of third party loans to executives for the purpose of acquiring company stock.

Guarantees Supporting Subsidiaries

As of December 31, 2004, the Company had issued the following types of guarantees of behalf of its subsidiaries:

	Amount
(millions)
Subsidiary debt(1)	$	1,484
Commodity transactions(2)		2,345
Lease obligation for power generation facility(3)		898
Nuclear obligations(4)		509
USGen facilities(5)		656
Miscellaneous		302
Total subsidiary obligations	$	6,194

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

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

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

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

(5) Guarantee associated with a subsidiary’s commitment to purchase three electric generating facilities from USGen New England, Inc. The guarantee expired when the acquisition was completed on January 1, 2005.

Surety Bonds and Letters of Credit

At December 31, 2004, the Company had purchased $17 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $182 million. The Company enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. As of December 31, 2004, no amounts had been presented for payment under the letters of credit.

Indemnifications

In addition, as part of commercial contract negotiations in the normal course of business, the Company may sometimes agree tomake payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2004, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.

4. Dividend Restrictions

The Company received dividends from its consolidated subsidiaries in the amounts of $1.2 billion, $1.1 billion, and $945 million for the years 2004, 2003, and 2002, respectively.

The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. In response to the Company’s request, the SEC granted relief in 2000, authorizing payment of dividends by CNG from other capital accounts to the Company in amounts up to $1.6 billion, representing CNG’s retained earnings prior to the Company’s acquisition of CNG. The SEC granted further relief in 2004, authorizing the Company’s nonutility subsidiaries to pay dividends out of capital or unearned surplus in situations where such subsidiary has received excess cash from an asset sale, engaged in a restructuring, or is returning capital to an associate company. The Company’s ability to pay dividends on its common stock at declared rates was not impacted by the restrictions discussed above during 2004, 2003 and 2002.

The Virginia State Corporation Commission (Virginia Commission) may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate, if found not to be in the public interest. At December 31, 2004, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with the Company’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Company’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2004.

See Note 17 to the Consolidated Financial Statements included in the 2004 Form 10-K, Part II, Item 8., for a description of potential restrictions on dividend payments by the Company and certain subsidiaries in connection with the deferral of distribution payments on trust preferred securities.

D 2004/ Page 105

Signatures

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

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

Date: February 28, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2005.

Signature	Title
/s/    THOS. E. CAPPS         Thos. E. Capps	Chairman of the Board of Directors and Chief Executive Officer
/s/    PETER W. BROWN         Peter W. Brown	Director
/s/    RONALD J. CALISE         Ronald J. Calise	Director
/s/    GEORGE A. DAVIDSON, JR.         George A. Davidson, Jr.	Director
/s/    JOHN W. HARRIS         John W. Harris	Director
/s/    ROBERT S. JEPSON, JR.         Robert S. Jepson, Jr.	Director
/s/    BENJAMIN J. LAMBERT, III         Benjamin J. Lambert, III	Director
/s/    RICHARD L. LEATHERWOOD         Richard L. Leatherwood	Director
/s/    MARGARET A. MCKENNA         Margaret A. McKenna	Director
/s/    K. A. RANDALL         K. A. Randall	Director
/s/    FRANK S. ROYAL         Frank S. Royal	Director
/s/    S. DALLAS SIMMONS         S. Dallas Simmons	Director
/s/    DAVID A. WOLLARD         David A. Wollard	Director
/s/    THOMAS N. CHEWNING         Thomas N. Chewning	Executive Vice President and Chief Financial Officer
/s/    STEVEN A. ROGERS         Steven A. Rogers	Vice President, Controller and Principal Accounting Officer

D 2004/ Page 106