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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2002

OR

For the transition period from                  to                

Commission File Number 1-3196

CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

(804) 819-2000

(Registrant’s telephone number)

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

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

None

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

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

Indicate by check mark whether the registrant is an accelerated filer.  Yes  ¨  No  x

The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 28, 2003, was zero.

As of February 28, 2003, there were issued and outstanding 100 shares of the registrant’s common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I.(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

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Consolidated Natural Gas Company

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Part I

The Company

Consolidated Natural Gas Company (CNG or the Company) operates in all phases of the natural gas business, explores for and produces oil, and provides a variety of retail energy marketing services. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company headquartered in Richmond, Virginia. The Company is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act).

On January 28, 2000, Dominion completed the acquisition of CNG and merged CNG into a subsidiary (New Company) of Dominion. The New Company was incorporated in Delaware in 1999 and at the time of the merger changed its name to Consolidated Natural Gas Company. The “Company” is used throughout this report and, depending on the context of its use, refer to CNG, one of CNG’s consolidated subsidiaries, or the entirety of CNG and its consolidated subsidiaries, both before and after the merger with Dominion.

At December 31, 2002, the Company had approximately 4,500 employees. Approximately 2,700 employees are subject to collective bargaining agreements.

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

Operating Segments

The Company manages its operations through three principal operating segments: Delivery, Energy and Exploration & Production.

Energy manages the Company’s gas transmission pipeline, certain gas production, storage and by-product operations and energy marketing activities. Delivery manages the Company’s retail gas distribution system and customer service operations. Exploration & Production manages the Company’s onshore and offshore gas and oil exploration, development and production operations. They are located in several major producing basins in the lower 48 states, including the outer continental shelf and deep-water areas of the Gulf of Mexico.

The Company also reports the activities of CNG International Corporation and other minor subsidiaries in its Corporate and Other segment. CNG International was involved in, among other activities, the development and operation of a 26-megawatt power plant located on the island of Kauai, Hawaii. In 2000, management committed to a plan of disposal for CNG International. See Note 8 to the Consolidated Financial Statements for more information.

While the Company manages its daily operations as described above, the assets remain wholly-owned by its legal subsidiaries. For additional financial information on operating segments and geographical areas, see Note 25 to the Consolidated Financial Statements.

Seasonality

Gas sales in the Delivery segment typically vary seasonally based on increased demand for gas by residential and commercial customers for heating use based on changes in temperature. The Energy segment is also impacted by seasonal changes in the prices of commodities that it actively markets. For the Exploration & Production segment, gas prices can vary seasonally as well.

Competition

Delivery

Deregulation is at varying stages in the three states in which the Company’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, the Company offers an Energy Choice program to customers on its own initiative, in cooperation with the Public Utilities Commission of Ohio (Ohio Commission).

West Virginia legislation currently does not require customer choice in its retail natural gas markets and the Company has not voluntarily initiated an Energy Choice program. However, the West Virginia Public Service Commission (West Virginia Commission) recently issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future. In 2002, the West Virginia Commission proposed rules that require competitive gas service providers be licensed in West Virginia. In

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addition, the West Virginia Commission is developing rules for a code of conduct between utilities and their marketing affiliates, as well as consumer protection regulations and marketer licensing rules.

See Regulated Gas Distribution Operations in Future Issues and Outlook in Item 7. Management’s Discussion and Analysis of Results of Operations (MD&A) for additional information.

Energy

The Company’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. The Company’s pipelines are part of an interconnected gas transmission system which continues to provide local distribution companies, marketers, power generators, and industrial and commercial customers the accessibility of supplies nationwide.

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

Exploration & Production

The Company conducts exploration and production operations in several major gas and oil producing basins in the lower 48 states, including the outer continental shelf and deep-water areas of the Gulf of Mexico. Competitors range from major international oil companies to smaller, independent producers.

The Company faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since the Company 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, the Company sells most of its deliverable natural gas and oil into short and intermediate-term markets. The Company faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. In the wake of the current industry developments, several energy trading participants have exited the business, reducing the number of active purchasers in the marketplace and reducing the Company’s delivery flexibility. However, the Company 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

General

The Company is subject to regulation by the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency (EPA), Department of Energy (DOE), the Army Corps of Engineers and other federal, state and local authorities.

State Regulation

The Company’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they  operate—Ohio, Pennsylvania and West Virginia. When necessary the Company’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, certain of the Company’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 recovered through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs incurred that are expected to be recovered in future rates are deferred as regulatory assets.

In November 2002, the Company filed comments in response to the Ohio Commission’s request for information needed to ensure that Ohio public utilities are not impacted by adverse financial consequences of parent or affiliate company unregulated operations. The Company informed the Ohio Commission that its affiliate and parent company transactions are governed by the rules of the 1935 Act. The Ohio Commission has not acted on the comments filed or given any indication as to how it will proceed at this time.

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For additional information on deregulation in the gas industry and current rate matters, see above in Competition and Regulated Gas Distribution Operations in Future Issues and Outlook in MD&A.

Public Utility Holding Company Act of 1935

The Company and Dominion are registered holding companies under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of the Company, Dominion and their subsidiaries with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business, and other matters. Over the past few years, several bills have been introduced in Congress to repeal the 1935 Act, and repeal provisions are currently pending before Congress. The likelihood that such repeal will be enacted is highly uncertain.

Federal Energy Regulatory Commission

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

The Company’s interstate gas transportation and storage activities are regulated under the Natural Gas Act of 1938 and are conducted in accordance with certificates, tariffs and service agreements on file with FERC. The Company is also subject to the Natural Gas Pipeline Safety Act of 1968, which authorizes the establishment and enforcement of federal pipeline safety standards and places jurisdiction of these standards with the Department of Transportation.

Competition in the natural gas industry was increased by FERC Order 636, issued in 1992. 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 supplies, whether purchased from the Company or from another gas supplier.

In the spring of 2003, FERC expects to issue new rules governing standards of conduct between interstate electric transmission and gas transportation and storage providers and its energy related affiliates. One goal of FERC is to eliminate the separate standards of conduct regulations for natural gas pipelines and electric transmission utilities and replace these requirements with uniform standards applicable to interstate “Transmission Providers” of both natural gas and electricity. For additional discussion on FERC matters, see Interstate Gas Transmission Operations—FERC Policy Developments in Future Issues and Outlook in MD&A.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations govern both current and future operations and potentially extend to plant sites formerly owned or operated by its subsidiaries, or their predecessors.

The Company is subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of 1990 (collectively referred to as the Clean Air Act), which require Title V permits for major facilities. The Clean Air Act also requires installation of Maximum Available Control Technology (MACT) to control the emissions of certain hazardous air pollutants from compressor engines. The Company is evaluating MACT proposed regulations but has not yet estimated the cost of expenditures that may ultimately be required.

The states within the Company’s operating area are currently developing regulations to reduce nitrogen oxide (NO_x) emissions to reach NO_x budget targets established by the EPA in order to meet goals under the Clean Air Act Amendments of 1990. Estimates of future cost impacts range from $15 to $18 million.

The EPA amended its oil pollution prevention regulations in July 2002. The total projected cost of compliance with the new regulations is estimated to range from $11 to $25 million, representing primarily capital expenditures.

For discussion of significant aspects of these matters, see Environmental Matters in Future Issues and Outlook in MD&A, Item 3. Legal Proceedings, and Note 21 to the Consolidated Financial Statements.

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Gas Supply

The Company’s gas supply is obtained from various sources, including: purchases from major and independent producers in the Southwest and Midwest regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from the Company’s and third-party underground storage fields.

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

Gas Storage

The Company’s underground storage facilities play an important part in balancing gas supply with sales demand and are essential to servicing the the Mid-Atlantic and Northeast’s large volume of space-heating business. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity. The Company operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. The Company owns 20 of these storage fields and has joint-ownership with other companies in six of the fields. The total designed capacity of the storage fields, including native gas, is approximately 960 bcf. The Company’s share of the total capacity is about 717 bcf. About one-half of the total capacity is base gas which remains in the reservoirs at all times to provide the primary pressure which enables the balance of the gas to be withdrawn as needed.

Dominion Transmission, Inc. (Dominion Transmission) operates 756 bcf of the total designed storage capacity and owns 514 bcf of the Company’s capacity. Dominion Transmission utilizes a large portion of its turnable capacity to provide approximately 242 bcf of gas storage service for others. This service is provided principally to local distributors, end-users and other customers serving the Northeast.

The East Ohio Gas Company (Dominion East Ohio) and The Peoples Natural Gas Company (Dominion Peoples) own and operate the remaining 203 bcf of storage capacity. In addition to owning their own storage, these companies, as well as several of the Company’s other subsidiaries, have access to a portion of the storage capacity operated by Dominion Transmission. The distribution subsidiaries also have capacity available in storage fields owned by others. The Company controls other acreage in the Appalachian area suitable for the development of additional storage facilities which would enable further expansion of capacity to meet possible future storage needs.

Gas Production

The Company owns 4.5 trillion cubic feet equivalent of proved natural gas reserves and produced almost 800 million cubic feet of natural gas per day and 23 thousand barrels of oil per day in 2002.

The Company utilized production handling and firm transportation contracts to support delivery of our gas and oil in certain market areas. Additional information can also be found in Note 21 to the Consolidated Financial Statements.

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The Company shares its principal executive office in Richmond, Virginia, with its parent company, Dominion. Such office space is leased. The Company leases corporate offices in other cities in which its subsidiaries operate.

Energy and Delivery assets are located primarily in the states of Ohio, West Virginia and Pennsylvania, while Exploration & Production assets include proved reserves located in the Gulf of Mexico, Permian Basin, Mid-Continent Region, the Gulf coast, and the Appalachian area.

The Energy segment’s storage operations include 26 storage fields, approximately 373,000 acres of operated leaseholds and 2,000 storage wells. The Energy segment has approximately 7,900 miles of gas transmission, gathering and storage pipelines. The Company also has more than 100 compressor stations with approximately 577,000 installed compressor horsepower located in Ohio, West Virginia, Pennsylvania and New York. See map below for the Company’s gas transmission pipelines and storage facilities.

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

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Information detailing the Company’s gas and oil operations presented on the following pages includes the activity from the Exploration & Production segment and certain production activity in the Energy segment.

Company-Owned Proved Gas and Oil Reserves

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

Certain subsidiaries of the Company 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 Company subsidiaries. The proved reserves reported in the table above represent the Company’s share of proved reserves for all properties, based on the Company’s ownership interest in each property. For properties operated by the Company, the difference between the proved reserves reported on Form EIA-23 and the Company-owned proved reserves, reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2002 are based upon studies for each of the Company’s property prepared by the Company’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or Ryder Scott Company, L.P.

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

Quantities of Gas and Oil Produced

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

The average sales price per thousand cubic feet (mcf) of gas (including transfers to other Dominion operations at market prices) realized during the years 2002, 2001 and 2000 was $3.60, $4.03 and $3.12, respectively. The respective average prices without hedging results per mcf of gas produced during the years 2002, 2001 and 2000 were $3.25, $4.14 and $3.90. The respective average prices realized for oil with hedging results were $23.73, $24.58 and $22.96 per barrel and the average prices without hedging results were $25.03, $24.71 and $24.65 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2002, 2001 and 2000 was $0.51, $0.49 and $0.43, respectively.

Net Wells Drilled in the Calendar Year

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

As of December 31, 2002, 63 gross (47 net) wells were in process of drilling, including wells temporarily suspended.

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Acreage

The following table sets forth the gross and net developed and undeveloped acreage of the Company at December 31, 2002:

Productive Wells

The number of productive gas and oil wells in which Dominion’s subsidiaries had an interest at December 31, 2002, follow:

The number of productive wells includes 196 gross (73 net) multiple completion gas wells and 10 gross (4 net) multiple completion oil wells.

From time to time, the Company and its subsidiaries are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans, or permits issued by various federal, state and local agencies for the construction or operation of facilities. From time to time, there may be administrative proceedings on these matters pending. In addition, in the normal 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 the Company’s financial position, liquidity or results of operations.

See Regulation under Item 1. Business, Rate Matters in Future Issues and Outlook in MD&A and Note 21 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

Before being acquired by Dominion, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) and two predecessor companies were named as a defendant in several lawsuits originally filed in 1995 that were subsequently consolidated. The lawsuit is now pending in the Texas 93rd Judicial District Court in Hildago 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 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. In 2002, the valuation portion of the claim was dismissed. The plaintiff has filed an appeal.

In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against 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; however, the suit remains consolidated with the Grynberg case.

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In 1999, a class action was filed by Quinque Operating Co. and others parties against approximately 300 defendants, including CNG and several of its subsidiaries, in Stevens County, Kansas. The complaint seeks damages for alleged fraud, misrepresentation, conversion and assorted other claims, in the measurement and payment of gas royalties from privately held gas leases. The plaintiffs will seek class certification and expedited discovery in Kansas. The defendants have filed motions to dismiss the case. A motion in opposition to class certification was argued in January 2003.

None.

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Part II

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

The Company paid quarterly cash dividends on its common stock to Dominion during 2002 and 2001 as follows. Restrictions on the payment of dividends by the Company are discussed in Note 19 to the Consolidated Financial Statements.

Omitted pursuant to General Instruction I.(2)(a).

Introduction

Management’s Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The “Company” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion.

Risk Factors and Cautionary Statements That May Affect Future Results

This report contains statements concerning the Company’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by words such as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These factors include weather conditions; fluctuations in energy-related commodities prices and the effect these could have on the Company’s earnings, liquidity position and the underlying value of its assets; counterparty credit risk; capital market conditions, including equity price risk due to marketable equity securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting standards; the risks of operating businesses in regulated industries that are becoming deregulated; completing the divestiture of CNG International Corporation (CNG International); collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation rates). Some more specific risks are discussed below.

The Company bases its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements are made. The Company cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, materially differ from actual results. The Company undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

The Company’s operations are weather sensitive—The Company’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes, can be destructive, disrupting operations and causing production delays and unusual maintenance or repairs.

The Company is subject to complex government regulation that could adversely affect its operations—The Company’s operations are subject to extensive regulation and require numerous permits, approvals

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and certificates from federal, state and local governmental agencies. The Company must also comply with environmental legislation and other regulations. Management believes the necessary approvals have been obtained for the Company’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 the Company to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed the Company’s estimates—Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment and monitoring obligations. In addition, the Company 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 costs and compliance, 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.

The use of derivative instruments could result in financial losses—The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In the future, the Company 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 instruments 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 value of the reported fair value of these contracts. For additional information concerning derivatives, see Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2 and 11 to the Consolidated Financial Statements.

The Company’s exploration and production business is dependent on factors including commodity prices which cannot be predicted or controlled—The Company’s exploration and production business is subject to numerous risks beyond its control. These factors include fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, the Company’s ability to acquire additional land positions in competitive lease areas, and operational risks that are inherent in the exploration and production business and could result in the disruption of production. In addition, in connection with the use of financial derivatives to hedge future sales of gas and oil production, the Company’s liquidity may sometimes be affected by margin requirements. Under these requirements, the Company must deposit funds with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Some of these factors could have compounding effects that could also affect the Company’s financial results. Also, because the Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange Commission (SEC), short-term market declines in the prices of natural gas and oil could adversely affect its financial results. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. The principal limitation is that these capitalized amounts may not exceed the present value of estimated future net revenue based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test). 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.

An inability to access financial markets could affect the execution of the Company’s business plan—The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from its operations. Management believes that the Company will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company’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 the Company’s credit ratings. Restrictions on the Company’s ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing rating agency requirements could negatively affect the Company’s growth and business strategy—As of March 1, 2003, the Company’s senior unsecured debt is rated BBB+, stable outlook, by Standard & Poor’s

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Ratings Group, a division of The McGraw-Hill Companies, Inc. (Standard & Poor’s), and Baa1, negative outlook, by Moody’s Investors Service (Moody’s). Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company’s credit ratings by either Standard & Poor’s or Moody’s could increase its borrowing costs and adversely affect operating results.

Potential changes in accounting practices may adversely affect the Company’s financial results—The Company cannot predict the impact of future changes in accounting regulations or practices in general with respect to public companies, the energy industry or on its operations specifically. New accounting standards could be issued by the Financial Accounting Standards Board (FASB) or the SEC that could change the way the Company records revenue, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company’s reported earnings or increases in liabilities.

Operating Segments

In general, management’s discussion of the Company’s results of operations focuses on the contributions of its operating segments. The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on the three primary operating segments: Delivery, Energy and Exploration & Production.

Delivery manages the Company’s retail gas distribution systems, as well as customer service. The operating results of the Delivery segment reflect the impact of weather on demand for natural gas and customer growth as influenced by overall economic conditions. The Delivery businesses are subject to cost-of-service rate regulation; changes in prices of commodities consumed or delivered are generally recoverable in rates charged to customers. However, certain rates may be subject to price caps, limiting recovery of higher costs in certain circumstances.

Energy manages the Company’s gas transmission pipeline, certain gas production, storage and by-product operations and energy marketing activities. The operating results of the Energy segment also reflect the impact of weather on demand for natural gas, customer growth as influenced by overall economic conditions and changes in prices of commodities. The Energy segment’s gas transmission operations are subject to cost-of-service rate regulation.

Exploration & Production manages the Company’s onshore and offshore 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 deep-water areas of the Gulf of Mexico. The operating results of the Exploration & Production segment reflect the successful discovery of and production from natural gas and oil reserves, as well as changes in prices of natural gas and oil. Exploration & Production manages commodity risk through the use of derivative contracts such as forwards, swaps and options.

In addition, the Company also reports the corporate functions as a segment.

For more information on the Company’s segments, see Note 25 to the Consolidated Financial Statements.

Critical Accounting Policies

The Company has identified the following accounting policies that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions.

Accounting for risk management contracts at fair value—The Company uses derivative instruments to manage its commodity and financial market risks. The accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing. All derivatives, other than specific exceptions, are reported on the Consolidated Balance Sheets at fair value, beginning in 2001. Changes in fair value, except those related to derivative instruments designated as cash flow hedges, are generally included in the determination of the Company’s net income at each financial reporting date until the contracts are ultimately settled. The measurement of fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on

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valuation methodologies deemed appropriate by management. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of 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 affect the timing of recognition for changes in fair value of certain derivatives used as hedges. See Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2 and 11 to the Consolidated Financial Statements.

Accounting for gas and oil operations—The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using a unit-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as dismantlement and abandonment costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proved reserve quantities and estimates of the amount and timing of future expenditures to develop the proved reserves. Proved reserves, and the cash flows related to these reserves, are estimated based on a combination of historical data and estimates of future activity. Actual reserve quantities and development expenditures may differ from the forecasted amounts. In addition, the Company has significant investments in unproved properties which are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base. Capitalized costs in the depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenue to be derived from the production of proved gas and oil reserves. The Company performs the test quarterly, on a country-by- country basis, and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. Any impairment of excess gas and oil property costs over the ceiling is charged to operations. Given the volatility of natural gas and oil prices, it is possible that the Company’s estimate of discounted future net cash flows from proved natural gas and oil reserves could change in the near term. If natural gas or oil prices decline, even if for only a short period, or if the Company revises its estimated proved reserves downward, recognition of natural gas and oil property impairments could occur in the future. See Notes 2 and 26 to the Consolidated Financial Statements.

Use of estimates in impairment testing—The Company is required to test at least annually its goodwill for potential impairment. As part of that test, the Company is required to determine the fair value of its reporting units. The Company estimates the fair value of its reporting units using discounted cash flow analyses and other valuation techniques based on multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on many subjective factors, including the selection of appropriate discount and growth rates, the selection of peer group companies and recent transactions and management’s estimate of future cash flows. The cash flow estimates used by the Company are based on the best information available at the time the estimates are made; however, estimates of future cash flows are by nature highly uncertain and may vary significantly from actual results.

The Company performed the transitional impairment test upon adoption of Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, as of January 1, 2002 and its annual test later in the year. The fair value of each of the Company’s reporting units exceeded the related carrying amounts, resulting in no impairment. The underlying assumptions and estimates involved in preparing these fair value calculations could change significantly from period to period. If the Company’s estimates of the fair value of its reporting units are substantially reduced, impairment may be indicated and the Company would be required to perform the second step of the goodwill impairment test. That step measures the amount of impairment, if any, and requires the further use of fair value estimates. A goodwill impairment charge would result in a charge to earnings, with a corresponding reduction of the carrying amount of goodwill on the balance sheet. The Company had $625 million and $519 million of goodwill at December 31, 2002 and 2001, respectively. See Notes 2 and 13 to the Consolidated Financial Statements for further discussion of goodwill impairment tests.

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

Accounting for regulated operations—Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition used for accounting purposes, the Company’s Consolidated Financial Statements may recognize a regulatory asset for expenditures that otherwise would be expensed, based on the approval from the appropriate regulatory authority. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenue associated with expected customer credits through rates. Management makes assumptions regarding the probability of regulatory asset recovery through future rates approved by applicable regulatory authorities. The expectations of future recovery are generally based upon historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, they would be expensed in the period such assessment is made. See Notes 2 and 14 to the Consolidated Financial Statements.

Results of Operations

The Company’s discussion of its results of operations includes a tabular summary of contributions by its operating segments to net income, an overview of consolidated results of operations and a more detailed discussion of the results of segment operations.

Overview of Consolidated Operating Results

Net income in 2002 was $638 million, an increase of $247 million, as compared with net income of $391 million in 2001. The operating results of 2002, as compared to 2001, reflected higher gas and oil production revenue, attributable to the full year operations of Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI) (see Note 5 to the Consolidated Financial Statements), the Company’s ongoing drilling programs, and lower operating expenses, principally in purchased gas costs, partially offset by natural production declines, and by the effects of lower regulated gas distribution service revenue and lower nonregulated gas sales. The increased 2002 operating results also reflected the impacts of the following 2001 charges: a $22 million ($14 million after taxes) cumulative effect of a change in accounting principle related to the adoption of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (see Note 11 to the Consolidated Financial Statements); $108 million ($69 million after taxes) in connection with the impairment of forward natural gas contracts due to reorganization of Enron Corp. and certain of its subsidiaries (collectively referred to as Enron) under Chapter 11 bankruptcy proceedings (see Note 11 to the Consolidated Financial Statements); and the restructuring and other merger-related costs totaling $45 million ($31 million after taxes) (see Notes 5 and 7 to the Consolidated Financial Statements). In addition, the Company’s effective income tax rate decreased in 2002, reflecting the $16 million net effect,

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allocated to the Company, of including certain subsidiaries in Dominion’s consolidated state income tax returns (see Note 9 to the Consolidated Financial Statements).

Total operating revenue was $3.9 billion in 2002, a decrease of $337 million from $4.2 billion in 2001. Regulated gas sales and gas transport service revenue combined, decreased $514 million, as compared to 2001. Lower regulated gas sales volumes reflected customers opting for alternate suppliers under the Energy Choice programs, offset by the effect of cooler weather experienced in the franchise service areas. Nonregulated gas sales revenue decreased $172 million, as compared to 2001, reflecting both lower sales volumes due to lower activity and lower prices. Gas and oil production revenue increased $284 million, attributable to the full year operations of DOTEPI and the Company’s ongoing drilling programs, partially offset by natural production declines.

Total operating expense was $2.8 billion in 2002, a decrease of $674 million as compared to $3.5 billion in 2001. Purchased gas, the largest expense category for the Company, represents volumes purchased to meet sales requirements for regulated and nonregulated operations. This expense is influenced primarily by changes in regulated gas sales requirements, the price of gas supplies and the timing of recoveries of deferred purchased gas costs by the rate-regulated subsidiaries. Purchased gas costs decreased $670 million, as compared to 2001, reflecting lower purchased gas prices resulting from lower overall market prices and lower volume requirements. Other operations and maintenance expense was lower in 2002, reflecting a decrease in 2002 salary expense, an overall reduction in 2002 operating costs and the 2001 charge related to the impairment of Enron natural gas contracts. The lower other operations and maintenance expense was offset by the effects of higher depreciation, depletion and amortization expense, due primarily to higher levels of gas and oil production resulting from DOTEPI’s full year operations and the Company’s ongoing drilling programs.

Segment Results

Due to the regulated nature of the Delivery segment and the transmission business of the Energy segment being subject to cost-of-service rate regulation, operating results can be affected by regulatory delays when price increases are sought through general rate filings to recover higher costs of operations. Weather is also an important factor since a major portion of the gas sold or transported by the distribution and transmission operations is ultimately used for space heating.

Delivery Segment

The Company’s Delivery segment manages the Company’s retail gas distribution systems and customer service operations. The Delivery segment includes the results of the Company’s retail gas distribution subsidiaries: The East Ohio Gas Company (Dominion East Ohio), The Peoples Natural Gas Company (Dominion Peoples) and Hope Gas, Inc. (Dominion Hope). These subsidiaries sell gas and provide transportation services to residential, commercial and industrial customers in Ohio, Pennsylvania and West Virginia and are subject to price regulation by their respective state utility commissions.

Sales growth in the Company’s residential service areas of Ohio, Pennsylvania and West Virginia has generally been limited since these areas have experienced minimal population growth, and the vast majority of households in these areas already use natural gas for space heating. Sales are being affected by regulatory and legislative initiatives to deregulate natural gas at the retail level. Similar to the unbundling of the services provided by gas pipeline companies, gas distribution companies are adapting to the deregulation and unbundling of the retail energy market. Under open access programs in Ohio and Pennsylvania, customers may now choose a gas supplier other than their local gas utility and have the local utility provide transportation of the commodity through its existing delivery system. Since the Company’s retail gas distribution subsidiaries provide the transportation service to customers without regard to whether the gas is supplied by the Company or by an alternate supplier, the gas distribution subsidiaries’ results of operations are generally not impacted by customers who choose alternate gas suppliers. For the Company’s regulated gas sales, the cost of purchased gas is usually recovered from customers through rates, although certain rates may be subject to price caps, limiting recovery of higher costs in certain circumstances.

At December 31, 2002, approximately 647,000 of the Company’s 1.2 million Ohio customers and approximately 106,000 residential and small commercial customers in the Company’s Pennsylvania service area were participating in open-access and purchasing natural gas from other suppliers. Large industrial customers in Ohio also source their own

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natural gas supplies. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from unregulated suppliers.

The following table presents summarized information relating to the Company’s Delivery segment:

Operating Results

The Delivery segment contributed $168 million to net income in 2002, as compared to $148 million in 2001. The 2002 results for the Delivery segment reflected lower regulated gas sales revenue, offset by the effects of higher transportation revenue, lower purchased gas costs and lower other operations and maintenance expense, as compared to 2001.

Total operating revenue of the Delivery segment decreased $500 million in 2002 from $1.7 billion in 2001. Regulated gas sales revenue was $876 million, a decrease of $533 million as compared to $1.4 billion in 2001. The lower regulated gas sales revenue in 2002, as compared to 2001, reflected a $370 million decrease due primarily to the pass through of lower purchased gas costs and a $163 million decrease due to lower sales volumes. The lower sales volumes reflected a $191 million decrease for the migration of customers, opting for alternate suppliers, from regulated gas sales to transportation service and lower levels of industrial activity, partially offset by a $28 million increase resulting from cooler weather experienced in the Company’s retail service areas. The heating degree-days for 2002 were 4 percent higher than in 2001. Average sales rates for all customer groups decreased, reflecting the pass through of lower purchased gas costs. The higher gas transportation volumes in 2002 reflected the migration of residential and commercial customers from sales to transport service under the Energy Choice programs in Ohio and Pennsylvania.

Total operating expenses of the Delivery segment in 2002 were $971 million, a decrease of $513 million, as compared to 2001. Purchased gas costs decreased $489 million in 2002, reflecting lower purchased gas prices resulting from lower overall market prices and lower volume requirements. Other operations and maintenance expense was $31 million lower in 2002, as compared to 2001. The decrease in other operations and maintenance expense was due primarily to lower administrative and general salary expenses, reductions in materials and supplies and contractor services in 2002, partially offset by an increase in uncollectible accounts expense.

Throughput

Since Delivery sales volumes largely represent gas used for space heating, changes in volumes are primarily a function of the weather. In addition to sales of gas, Delivery provides gas transportation services to a wide range of customers, including residential, commercial and industrial end-users. Therefore, the volume of gas transported can be affected by the weather and by changes in both economic and market conditions. Both gas sales and transportation volumes are also being impacted by the migration of customers from sales to transport service under the Energy Choice programs.

Gas sales volumes were 123 billion cubic feet (bcf) in 2002, as compared to 141 bcf in 2001. The year-to- year comparison reflected decreased sales in 2002 due to the migration of customers from sales to transport under the Energy Choice programs, offset by the effect of cooler weather. Residential gas sales volumes decreased 12 bcf in 2002, to 94 bcf, while volumes transported for residential customers increased 16 bcf. Sales to commercial customers totaled 26 bcf in 2002, a decrease of 5 bcf from 2001, while volumes transported to these customers increased 6 bcf to 49 bcf. Total throughput to industrial customers was 110 bcf in 2002, as compared to 106 bcf in 2001.

Energy Segment

The Energy segment manages the Company’s gas transmission pipeline, certain gas production, storage and by-product operations and energy marketing activities. The Energy segment includes Dominion Transmission, Inc. (Dominion Transmission), Dominion Field Services, Inc. (Dominion Field Services), Dominion Retail, Inc. (Dominion Retail) and other subsidiaries. Dominion Transmission, an interstate pipeline company regulated by the Federal Energy Regulatory Commission (FERC), provides gas transportation, storage and related services to affiliates, utilities and end-users in the Midwest, the Mid-Atlantic

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states and the Northeast. In addition, Dominion Transmission engages in gas and oil production activities in the Appalachian basin. Dominion Field Services is engaged in activities related to gathering and processing of Appalachian area natural gas supply and provides natural gas storage facilities services. Dominion Retail, a nonregulated company, markets natural gas, electricity and related products and services to residential, commercial and small industrial customers, including those within the Company’s traditional retail service areas. Dominion Retail is expected to enable the Company to take advantage of emerging deregulated energy markets for both gas and electricity.

On September 5, 2002, the Company acquired 100 percent ownership of Cove Point LNG Limited Partnership (Dominion Cove Point), a cost-based rate-regulated entity, from a subsidiary of The Williams Companies. Dominion Cove Point’s assets include a liquefied natural gas import facility located near Baltimore, Maryland that is under reconstruction, a liquefied natural gas storage facility and an approximately 85-mile natural gas pipeline. The Company expects Dominion Cove Point to become fully operational in 2003.

The following table presents summarized information relating to the Company’s Energy segment:

Operating Results

The Energy segment contributed $205 million to net income in 2002, as compared to $167 million in 2001. The 2002 results for the Energy segment reflected lower nonregulated gas sales and gas transportation revenue, offset by the effect of lower operating costs, principally in purchased gas costs, as compared to 2001.

Total operating revenue of the Energy segment was $1.5 billion in 2002, a decrease of $171 million, as compared to $1.7 billion in 2001. Nonregulated gas sales revenue was $811 million, decreasing $223 million from 2001, primarily as a result of lower sales prices, although sales volumes decreased by 10 bcf. The average sales price was $3.92 per thousand cubic feet (mcf) in 2002, as compared to $4.76 per mcf in 2001, resulting in a $186 million decrease in nonregulated gas sales revenue. Lower sales volumes resulted in a $37 million decrease in nonregulated gas sales revenue. Nonregulated electric sales revenue increased $89 million in 2002, as compared to 2001, reflecting $71 million of retail energy sales revenue and $18 million of revenue generated from the new power generation facility at the Company’s Armstrong station in Pennsylvania. The facility became available for commercial operations during the second quarter of 2002, and the Company began operating the new facility under an operating lease with Dominion Equipment, Inc., a Dominion subsidiary. See Note 21 to the Consolidated Financial Statements. Revenue from natural gas by-products sales was $65 million in 2002, as compared to $70 million in 2001. The decrease reflected lower average sales prices for all by-products in 2002, partially offset by higher sales volumes. Gas transportation revenue was $316 million, a decrease of $24 million from 2001, primarily as a result of lower rates, partially offset by higher transportation volumes.

Total operating expenses of the Energy segment in 2002 was $1.1 billion, a decrease of $226 million, as compared to 2001. Purchased gas was the largest component of the operating expenses, decreasing $234 million to $769 million in 2002, reflecting the lower prices paid in 2002, as compared to 2001. Electric fuel energy purchases increased $62 million in 2002, as compared to 2001. Substantially all of the increase related to higher volumes purchased during 2002, reflecting the Company’s energy marketing operations that are not subject to cost-based rate regulation. Liquids, pipeline capacity and other purchases decreased $50 million in 2002, as compared to 2001, primarily reflecting comparably lower levels of rate recoveries for certain costs of transmission operations in 2002. The difference between actual expenses and amounts recovered in the period are deferred, pending future rate adjustments. Other operations and maintenance expense was $10 million lower in 2002, as compared to 2001. The decrease in other operations and maintenance expense was due primarily to reduction in overall operating costs in 2002.

Exploration & Production Segment

The Exploration & Production segment manages the Company’s onshore and offshore gas and oil exploration, development and production operations.

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The Exploration & Production segment includes the results of Dominion Exploration & Production, Inc. (Dominion E&P). The activities of Dominion E&P are conducted primarily in the Gulf of Mexico, the Mid-Continent region, the Permian Basin, the Appalachian Basin and other selected regions in the continental United States. Effective January 1, 2001, Dominion E&P transferred its 21 percent interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion. Proved reserves associated with the Canadian properties approximated 1 bcf of gas and 6.6 million barrels of oil at December 31, 2000. The property was transferred at a market value of $4.5 million. Also included in this segment are CNG Main Pass Gas Gathering Corporation and CNG Oil Gathering Corporation. These two subsidiaries hold equity investments in gas and oil gathering systems located in the Gulf of Mexico.

On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma (see Note 5 to the Consolidated Financial Statements). Dominion acquired Louis Dreyfus by merging it into a newly formed, wholly-owned subsidiary of Dominion, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. The results of DOTEPI have been included in the Consolidated Financial Statements since that date. The acquisition of DOTEPI doubled the Company’s proved gas and oil reserves.

The following table sets forth information relating to the Company’s Exploration & Production segment:

Operating Results

The Company’s Exploration & Production segment contributed $256 million to net income in 2002, as compared to $202 million in 2001. The 2002 results for the Exploration & Production segment reflected higher gas and oil production levels, partially offset by lower average realized prices, including the results of hedging, higher depreciation, depletion and amortization, other operations and maintenance and interest expenses, as compared to the same period in 2001.

Total operating revenue of the Exploration & Production segment increased $311 million to $1.3 billion in 2002 . Gas and oil production revenue was $1.1 billion in 2002, increasing $283 million, as compared to $772 million in 2001, reflecting higher overall gas and oil production levels, offset by the effect of lower average realized prices. The $283 million increase included higher gas production revenue of $227 million, reflecting an increase of $349 million due to higher sales volumes, offset by the effect of lower realized prices of $122 million. Oil production revenue increased by $56 million, reflecting an increase of $57 million due to higher sales volumes, offset by the effect of lower realized prices of $1 million. The higher production levels were attributed to the full year operations of DOTEPI and the Company’s ongoing drilling programs, partially offset by natural production

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declines. Revenue from gas and oil brokering activities was $247 million in 2002, an increase of $18 million from 2001, due primarily to higher transaction volumes, partially offset by lower prices realized from brokering activities.

Total operating expenses for 2002 were $866 million, as compared to $674 million in 2001. Higher operating costs included increases of $145 million in depreciation, depletion and amortization expense, reflecting the higher production levels from DOTEPI’s full year operations and the Company’s ongoing drilling programs, and $31 million in other taxes, as compared to 2001, due primarily to higher gross receipts taxes. Interest expense was $75 million in 2002, an increase of $30 million, as compared to 2001, primarily due to the full year operations of DOTEPI.

Corporate and Other Segment

The Corporate and Other segment includes the activities of CNG International and other minor subsidiaries, as well as costs of the Company’s corporate functions and certain expenses that are not allocated to the operating segments. CNG International is engaged in energy-related activities outside the United States. However, the Company has decided to focus on the United States gas and oil markets and, accordingly, is pursuing the sale of CNG International (see Note 8 to the Consolidated Financial Statements).

The net income for the Corporate and Other segment for 2002 was $9 million, as compared to a $126 million loss in 2001. The increase in net income reflected higher equity investment earnings and the following charges:

n  2001 restructuring and other merger-related costs of $45 million ($31 million after taxes) (see Note 7 to the Consolidated Financial Statements);

n  2001 cumulative effect of adopting SFAS No. 133 of $22 million ($14 million after taxes) (see Note 11 to the Consolidated Financial Statements); and

n  2001 estimated impairment of natural gas contracts of $108 million ($69 million after taxes), resulting from the Company’s exposure to Enron (see Note 11 to the Consolidated Financial Statements).

Contractual Obligations

Presented below is a summary of the Company’s contractual obligations as of December 31, 2002. These items are discussed in Notes 16, 17 and 21 to the Consolidated Financial Statements.

The Company expects to fund these obligations and commitments with cash flows from operations and short-term borrowings. These amounts do not include planned capital expenditures or working capital commitments, such as the repayment of short-term debt and settlement of derivative contracts or amounts for interest or distributions payable on securities issued by the Company.

Future Issues and Outlook

Regulated Gas Distribution Operations

Gas Deregulation Legislation

Each of the three states in which the Company 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 Public Utilities Commission of Ohio (Ohio Commission), the Company, on its own initiative, offers retail choice to customers. At December 31, 2002, approximately 647,000 of the Company’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.

In November 2002, the Company filed proposed tariffs to comply with the Ohio Commission’s rules that implement House Bill 9. House Bill 9 establishes minimum standards for suppliers and aggregators participating in natural gas customer choice programs. The Ohio Commission has not acted on any of the tariff filings made or given any indication as to when such action can be expected.

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Pennsylvania—At December 31, 2002, approximately 106,000 residential and small commercial customers had opted for Energy Choice in the Company’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from unregulated 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 Public Service Commission (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. In addition, the West Virginia Commission is developing rules for a code of conduct between utilities and their marketing affiliates, as well as Consumer Protection regulations and Marketer Licensing Rules. In 2002, the West Virginia Commission proposed rules that require that competitive gas service providers be licensed in West Virginia.

Rate Matters—Gas Distribution

When necessary, the Company’s gas distribution subsidiaries in Ohio, Pennsylvania and West Virginia seek general rate increases on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, certain 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 recovered through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs incurred that are expected to be recovered in future rates are deferred as regulatory assets.

Ohio—In December 2002, the Ohio Commission conditionally approved an earlier application by the Company to implement a four-month Gas Cost Recovery (GCR) rate. The Ohio Commission approved the adjustment components of the GCR and directed the Company to leave the Expected Gas Cost portion of the GCR at the previous level for one more month before filing for a new three-month rate.

In January 2003, the Ohio Commission approved the settlement of the Company’s 2001 GCR financial and management performance audit. The settlement contained no disallowances and provided for a review of the corporate gas supply group expense recovery through the GCR and an internal audit of gas procurement processes and affiliate company gas purchase transactions.

In February 2002, the Company filed a report with the Ohio Commission that addressed the results of a payment matching program approved by the Ohio Commission in 2001 and deferral of certain uncollectible residential customer receivables in excess of the amount already recovered in rates. The report required no action by the Ohio Commission. Recovery of the deferred amount will be requested in the Company’s next rate case. The Company believes that it will recover those amounts deferred.

Pennsylvania—The Pennsylvania Public Utility Commission (Pennsylvania Commission) accepted a settlement filed by the Company and other parties to the Company’s gas cost recovery proceeding in September 2002. No disallowances were incurred as part of the settlement.

West Virginia—In 2001, the West Virginia Commission approved a settlement between the Company and certain third parties, regarding the costs of gas supplies and increased operating costs. The settlement stipulated that the Company would receive a $9.5 million increase in gas and non-gas revenue and also provides for a two-year rate moratorium. The new rates took effect on January 1, 2002 and will be in place through December 31, 2003.

Interstate Gas Transmission Operations

FERC Policy Developments

In October 2002, FERC hosted a public policy conference regarding various short and long-term issues that impact federal regulation of the natural gas industry. Among other issues, FERC examined supply and demand forecasts, the adequacy of natural gas infrastructure, regulatory policies applicable to liquefied natural gas (LNG) facilities, offshore gathering policies and the flexibility of interstate pipeline operations. As a result, FERC is considering adjustments to its future regulatory policies concerning the natural gas industry, including modification of its approach to regulation of LNG projects. The policy change is intended to encourage additional development of LNG terminals and to increase the availability of imported gas supplies.

FERC also continues to pursue a rulemaking that will eliminate the separate standards of conduct regulations for natural gas pipelines and electric transmission utilities and replace these requirements with uniform standards applicable to interstate “Transmission Providers.” The proposed standards would redefine the scope of affiliates covered by standards of conduct for

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most FERC-regulated companies. If the proposed policy is adopted, it will supersede the existing standards, that are applicable to the Company. The Company supports the policy goal to ensure competitive interstate energy markets; however, the Company has advocated adjustments to the proposed rules. The Company anticipates further action by FERC in early 2003. While the Company expects the outcome of a final rule to improve its ability to compete with similarly-situated transmission providers, it does not expect a final rule to have a short-term material impact on its results of operations, financial position or cash flows.

Rate Matters—Gas Transmission

The Company implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2002. In all material respects, these filings were approved by FERC in the form requested by the Company and were subject to only minor modifications. The Company has no significant rate matters pending before FERC at this time.

Exploration and Production Operations

Dominion continues to focus on increasing earnings from gas and oil properties primarily through acquisition and development activities, exploration and operating efficiencies. The November 2001 acquisition of Louis Dreyfus represented the addition of significant, long-lived natural gas reserves located in several onshore United States regions serving Northeast markets. This addition also provided significant new development drilling opportunities, complementing the Company’s existing development and exploration activities. The emphasis toward increased acquisition and development activities, as a complement to the higher risk exploration program, was further supported by the 2002 purchase of several onshore properties having additional development drilling and production enhancement potential.

Pipeline Operations

The Company plans to expand its natural gas transmission system with a $497 million, 279-mile interstate pipeline. The 279-mile Greenbrier Pipeline is planned to originate in Kanawha County, West Virginia and extend to Granville County, North Carolina. The Company owns 67 percent of Greenbrier Pipeline Company, LLC, with Piedmont Natural Gas owning the remaining 33 percent. In October 2002, FERC gave preliminary approval for the proposed project.

Environmental Matters

The Company 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. The Company also may seek recovery through regulated rates for environmental expenditures related to regulated gas transmission and distribution operations. See Note 21 to the Consolidated Financial Statements for additional discussion of environmental matters.

Although the Company is routinely engaged in environmental protection and monitoring efforts, the cost of such activities was not material in 2002 and 2001. Furthermore, the Company expects no material expenditures in 2003.

Accounting Matters

The FASB has issued several new standards that will affect the Company beginning in 2003. These include: SFAS No. 143, Accounting for Asset Retirement Obligations; Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—An Interpretation of FASB Statements No. 5, 57 and 107; and Interpretation No. 46, Consolidation of Variable Interest Entities. See Note 4 to the Consolidated Financial Statements for further discussion of the impact of adopting these new accounting standards and information about other standard-setting activities.

Outlook for 2003

The Company believes its operating businesses will provide a stable contribution to net income in 2003, with future growth in 2004. However, the Company’s earnings for 2003 will include the effects of the following items: severance costs under Workforce Reductions discussed below and the cumulative effect of implementing a change in the accounting for asset retirement obligations (see Note 4 to the Consolidated Financial Statements). The 2003 projections for the Company’s operating businesses anticipate higher sales of gas and oil, reflecting continued growth in production and higher realized prices and lower pension benefit credits.

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Other Matters

Pension Costs

As discussed in Note 20 to the Consolidated Financial Statements, the Company maintains qualified noncontributory defined benefit retirement plans for employees represented by recognized bargaining units of the Company’s subsidiaries. In addition, the Company’s employees not represented by bargaining units participate in the Dominion pension plan, which provides benefits to employees of multiple Dominion subsidiaries. Prior to 2002, the Company maintained a qualified pension plan for such employees; however, it was merged with the Dominion pension plan in 2002. The Company will recognize its allocated share of net periodic pension credits from the Dominion pension plan. Investment experience and market conditions, including interest rates, impact the measurement of these benefit obligations and the cost of providing such benefits. Accordingly, assumptions for discount rates and the expected long-term rate of return on investments are important considerations under SFAS No. 87, Employers’ Accounting for Pensions. However, since the objective of SFAS No. 87 is to recognize the cost of providing benefits over employees’ service period, it permits the delayed recognition of certain elements of retirement plan results.

Dominion, on behalf of its subsidiaries, including the Company, has reviewed the assumption used for the expected long-term rate of return on plan assets to better reflect anticipated future market conditions and has adopted an expected rate of 8.75 percent for 2003. This change, combined with other factors, such as a revised discount rate assumption of 6.75 percent for 2003, will reduce the Company’s allocable portion of 2003 pension credits from the Dominion pension plan, as well as the 2003 pension credits related to retirement plans for employees of the Company’s subsidiaries represented by recognized bargaining units, by an estimated $39 million, as compared to 2002.

Workforce Reductions

In connection with a plan announced by Dominion in January 2003, the Company expects to eliminate some union and salaried positions during 2003. The workforce reductions will affect primarily support positions. Affected workers will be offered severance packages, and benefits for union workers will be negotiated during 2003. Pending completion of the process to identify affected positions, the Company has not estimated the cost of the workforce reductions.

Expiration of Section 29 Tax Credits

Internal Revenue Code Section 29, “Credit for the Production of Fuel from Nonconventional Sources” (also referred to as the production tax credit), allows income tax credits for certain qualified production, including some natural gas, sold before January 1, 2003. Congress has not acted on legislation to extend this credit beyond 2002 for most qualified production. Whether Congress will take any action during the current term to extend the credit is uncertain. Dominion utilized approximately $10 million of these credits for the year ended December 31, 2002.

Effect of Changes in Commodity Prices

The Company’s operations are impacted by changes in energy commodity prices. When energy commodities are sold by one of the Company’s utilities subject to cost-of-service rate regulation, commodity costs are generally recovered through rates. Market price changes impact the Company’s revenue from natural gas and oil production and from commodity sales through unregulated subsidiaries. Dominion has established an enterprise risk management function to evaluate these risks and to recommend actions to management that are intended to mitigate such risks.

Market Rate Sensitive Instruments and Risk Management

The Company’s financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates and commodity prices as described below. Interest rate risk generally is related to the Company’s outstanding debt. Commodity price risk is present in the Company’s gas production and procurement operations and energy marketing operations due to the exposure to market shifts for prices received and paid for natural gas and oil. The Company uses derivative instruments to manage price risk exposures for these operations.

The Company’s 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 percent unfavorable change in interest rates and commodity prices.

Commodity Price Risk

The Company manages the price risk associated with purchases and sales of natural gas and oil by using derivative commodity instruments, including futures, forwards, options and swaps.

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For sensitivity analysis purposes, the fair value of the Company’s 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 percent unfavorable change in market prices of the Company’s derivative commodity instruments would have resulted in a decrease in fair value of approximately $347 million and $156 million as of December 31, 2002 and 2001, respectively.

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

Interest Rate Risk

The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company enters into interest rate sensitive derivatives, including interest rate swap agreements. For financial instruments outstanding at December 31, 2002, a hypothetical 10 percent increase in market interest rates would decrease annual earnings by approximately $2 million. A hypothetical 10 percent increase in market interest rates, as determined at December 31, 2001, would have resulted in a decrease in annual earnings of approximately $2 million.

Investment Price Risk

The Company sponsors employee pension and other postretirement benefit plans and participates in plans sponsored by Dominion 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 the Company’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed by the Company to the employee benefit plans.

Risk Management Policies

The Company 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 which 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.

Management believes, based on Dominion’s credit policies and the Company’s December 31, 2002 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. See Note 11 to the Consolidated Financial Statements for a discussion of the effects of Enron’s bankruptcy on the Company’s Consolidated Financial Statements.

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

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Index

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Report of Management

The Company’s management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company’s annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.

Management maintains a system of internal controls designed to provide reasonable assurance, at a reasonable cost, that the Company’s assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel, and internal audits. Management believes that during 2002 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by the Board of Directors. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and included a review of the Company’s accounting systems, procedures and internal controls to the extent necessary for the purpose of its report.

The Audit Committee of the Board of Directors of Dominion Resources, Inc. (the Company’s parent), composed entirely of directors who are not officers or employees of Dominion Resources, Inc. or its subsidiaries, meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. Both the independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

Consolidated Natural Gas Company

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Independent Auditors’ Report

To the Board of Directors of

Consolidated Natural Gas Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Consolidated Natural Gas Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Consolidated Natural Gas Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 13 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As discussed in Note 11 to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Also, as discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting used to develop the market-related value of pension plan assets in 2000.

/s/ DELOITTE & TOUCHE LLP

Richmond, Virginia

January 21, 2003

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Consolidated Natural Gas Company

Consolidated Statements of Income

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

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Consolidated Natural Gas Company

Consolidated Balance Sheets

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

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Consolidated Natural Gas Company

Consolidated Balance Sheets (Continued)