Back to GetFilings.com

Table of Contents

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

OR

For the transition period from             to

Commission File Number 1-3196

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 June 30, 2003 and February 27, 2004, was zero.

As of February 2, 2004, 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.

Table of Contents

Consolidated Natural Gas Company

2

Table of Contents

Part I

Item 1. Business

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.

As of December 31, 2003, the Company had approximately 4,600 full-time employees. Approximately 2,600 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 primary operating segments. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.

Delivery manages the Company’s gas distribution systems, customer service operations and the Company’s nonregulated retail energy marketing activities.

Energy manages the Company’s gas transmission pipeline and storage system, certain gas production operations, the Cove Point liquefied natural gas facility and field services and gas marketing operations.

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

While the Company manages its daily operations as described above, its assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Notes 1 and 24 to the Consolidated Financial Statements.

Business Developments

Since reactivating its Cove Point liquefied natural gas (LNG) facility in August 2003, the Company started construction on a fifth storage tank. The new tank is expected to be completed in the first quarter of 2005 and increases the current storage capacity from 5.0 billion cubic feet (bcf) to 7.8 bcf. In February 2004, the Company announced plans to increase the Cove Point storage tank capacity to 14.6 bcf and the plant’s deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. Associated with the Cove Point expansion, the Company also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed into service in 2008.

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

Seasonality

Gas sales in the Delivery segment typically vary seasonally based on increased demand by residential and commercial customers for heating use due to changes in temperature. The Energy segment is also impacted by seasonal changes in the prices of commodities that it actively markets and trades. For Exploration & Production, natural gas and oil prices can vary seasonally as well. See Risk Factors and Cautionary Statements That May Affect Future Results in Item 7. Management’s Discussion and Analysis of Results of Operations for additional information on how weather may affect the Company’s results of operations.

Regulation

The Company is subject to regulation by the Securities and Exchange Commission (SEC), 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 Regulatory Matters

The Company’s gas distribution service is regulated by the Public Utilities Commission of Ohio (Ohio Commission),

3

Table of Contents

Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission).

Status of Gas Deregulation

Each of the three states in which 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 Ohio Commission, the Company on its own initiative offers retail choice to customers. At December 31, 2003, approximately 670,000 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.

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

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

Rate Matters—Gas Distribution

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—Pennsylvania, Ohio and West Virginia. When necessary, the Company’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, certain of 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 generally subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective three-month or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchase gas cost expenses.

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

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

Rate Matters—Gas Transmission

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

Public Utility Holding Company Act of 1935

The Company is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of the Company and its subsidiaries with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters.

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.

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

4

Table of Contents

The Company’s interstate gas transportation and storage activities 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.

In November 2003, FERC issued new Standards of Conduct governing conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The new rule redefines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences. All transmission providers must be in compliance by June 2004. The Company has adopted an implementation plan and will train the appropriate personnel to ensure compliance with the new rules.

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

Environmental Regulations

Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, see Item 3. Legal Proceedings and Note 20 to the Consolidated Financial Statements.

From time to time the Company may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.

The Company has applied for or obtained the necessary environmental permits for the operation of its regulated facilities. Many of these permits are subject to re-issuance and continuing review.

Competition

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

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 Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. See Status of Gas Deregulation for additional information.

Energy

The Company’s large underground natural gas storage network and the location of its pipeline system provide 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 commercial and industrial customers the accessibility of supplies nationwide.

The Company competes with domestic and Canadian pipeline companies and gas marketers 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 producing basins in the lower 48 states, including the outer continental shelf and deepwater 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.

5

Table of Contents

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. 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.

Availability of Natural Gas for Retail Distribution

The Company is engaged in the sale and storage of natural gas through its operating subsidiaries. The Company’s natural 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.

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

6

Table of Contents

Item 2. Properties

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

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

Energy has approximately 7,900 miles of gas transmission, gathering and storage pipeline and 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 underground storage fields is approximately 960 billion cubic feet (bcf). The Company’s share of the total capacity is about 717 bcf. Energy also has 5 bcf of above ground storage capacity at its Cove Point liquefied natural gas facility. Energy’s storage operation also includes approximately 372,000 acres of operated leaseholds and more than 2,000 storage wells. Energy also has more than 100 compressor stations with approximately 597,000 installed compressor horsepower located in Ohio, Virginia, West Virginia, Pennsylvania and New York. Some of the stations are used interchangeably for several functions.

The map below illustrates the Company’s gas transmission pipelines and storage facilities.

7

Table of Contents

Exploration & Production owns 4.9 trillion cubic feet of proved equivalent natural gas reserves and produces approximately .9 billion cubic feet of equivalent natural gas per day from its leasehold acreage and facility investments. The Company, either alone or with partners, holds interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. The Company also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. The Company’s share of developed leasehold totals 2.2 million acres, with another 1.6 million acres held for future exploration and development drilling opportunities.

Information detailing the Company’s gas and oil operations presented on the following pages includes the activities of the Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included 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 gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2003 are based upon a study for each of the Company’s properties prepared by the Company’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

8

Table of Contents

Quantities of Gas and Oil Produced

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

The average sales price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Company operations at market prices) realized during the years 2003, 2002 and 2001 was $4.15, $3.60 and $4.03, respectively. The respective average prices without hedging results per mcf of gas produced were $5.26, $3.25 and $4.14, respectively. The respective average sales prices realized for oil with hedging results were $24.80, $23.73 and $24.58 per barrel and the respective average prices without hedging results were $30.74, $25.03 and $24.71 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2003, 2002 and 2001 was $0.75, $0.51 and $0.49 respectively.

Acreage

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

Net Wells Drilled in the Calendar Year

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

As of December 31, 2003, 60 gross (42 net) wells were in process of drilling, including wells temporarily suspended.

Productive Wells

The number of productive gas and oil wells in which the Company had an interest at December 31, 2003, follow:

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

9

Table of Contents

Item 3. Legal Proceedings

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 local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Company 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 in Item 1. Business and Note 20 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 the Company, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hildalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

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

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

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

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

10

Table of Contents

Part II

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

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 2003 and 2002 as follows:

Restrictions on the payment of dividends by the Company are discussed in Note 18 to the Consolidated Financial Statements.

Item 6. Selected Financial Data

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

Item 7. Management’s Discussion And Analysis Of Results Of Operations

Management’s Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The “Company” or “CNG” 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.

Contents of MD&A

The reader will find the following information in this MD&A:

n Forward-Looking Statements

n Introduction

n Accounting Matters

n Results of Operations

n Segment Results of Operations

n Credit Risk

n Risk Factors and Cautionary Statements That May Affect Future Results

Forward-Looking Statements

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 predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

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.

Introduction

CNG is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services.

The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on three primary operating segments: Delivery, Energy and Exploration & Production. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.

The contributions to net income by the Company’s primary operating segments are determined based upon a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments.

11

Table of Contents

Those specific items are reported in the Corporate and Other segment.

Energy includes the following operations:

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

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

n Certain natural gas production operations located in the Appalachian basin and

n Field services operations, representing aggregation of gas supply and related wholesale activities related to the Appalachian area.

Energy’s revenue and cash flows are derived from both regulated and nonregulated operations. Revenue and cash flow provided by gas transmission operations and the Company’s LNG facility are based primarily on cost-of-service rates established by Federal Energy Regulatory Commission (FERC). 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. Variability in revenue and cash flow provided by these regulated businesses results primarily from changes in rates while sales volumes and prices charged to customers affect the variability in revenue and cash flow provided by the nonregulated businesses. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding the use of resources for operations and maintenance or capital-related activities.

Revenue and cash flow for the Energy segment’s nonregulated businesses are subject to variability associated with changes in commodity prices. Energy’s nonregulated businesses use physical and financial contracts to hedge this price risk. Certain hedging activities may require cash deposits to satisfy margin requirements. In addition, reported earnings for this segment reflect changes in the fair value of certain derivatives and these values may change significantly from period to period. Variability in expenses for these nonregulated businesses relates largely to the costs of purchased commodities for resale and payments under financially-settled contracts.

Delivery includes the Company’s regulated gas distribution utilities and customer service operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. The segment also includes nonregulated retail marketing businesses that supply gas, electricity and related products and services to residential and small commercial customers in the Northeast and Midwest.

Revenue and cash flow provided by the Company’s gas distribution utility operations are based primarily on cost-of-service rates established by state regulatory authorities. Variability in Delivery’s revenue and cash flow relates largely to changes in volumes, which are primarily weather sensitive. In addition, for distribution utility operations, revenue may vary based on changes in levels of rate recovery for the costs of gas purchased and sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail marketing of gas and electricity may also be affected by changes in weather and commodity prices as well as acquisition and potential loss of customers.

Sales growth in the regulated 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 also being affected by regulatory and legislative initiatives to deregulate natural gas at the retail level. Under open access programs in Ohio and Pennsylvania, customers may 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. Delivery’s retail energy marketing businesses currently have gas customers in Ohio, Pennsylvania and Illinois.

Large industrial customers in Ohio source their own natural gas supplies. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

Variability in expenses results from changes in the cost of purchased gas and routine maintenance and repairs (including labor and benefits as well as decisions regarding the use of resources for operations and maintenance or capital-related activities). For gas distribution utility operations, the Company is permitted to seek recovery of the cost of gas purchased and sold to customers.

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

The Company operates a drilling program focused on low risk development drilling in several proven onshore regions of the United States, while also maintaining some exposure to higher risk exploration opportunities. Significant development drilling programs are currently underway in West Texas, the Appalachians and the Rocky Mountains where the Company holds sizeable acreage positions and operational experience. While each region provides the Company with exploration opportunities, most exploratory drilling takes place in the Gulf Coast region, including the deepwater Gulf of Mexico. The Company maintains an active and ongoing drilling program, participating in 763 net wells during 2003, and replacing approximately 230 percent of its 2003 production.

Revenue and cash flow provided by exploration and production operations are based primarily on the production and

12

Table of Contents

sale of company-owned natural gas and oil reserves. Variability in the segment’s revenue and cash flow relates primarily to changes in commodity prices, which are market based, and volumes, which are impacted by numerous factors including drilling success, timing of development projects, as well as external factors such as severe weather. The Company manages commodity price volatility by hedging a substantial portion of its near term expected production.

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

Corporate and Other includes the activities of CNG International and other minor subsidiaries, as well as costs of the Company’s corporate functions. It also includes specific items attributable to the Company’s operating segments that are reported in Corporate and Other. CNG International is engaged in energy-related activities primarily outside of 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 7 to the Consolidated Financial Statements).

Accounting Matters

Critical Accounting Policies and Estimates

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

Accounting for derivative contracts at fair value

The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.

Generally, derivatives are reported on the Consolidated Balance Sheets at fair value. Changes in the fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, 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 valuation methodologies considered appropriate by the Company’s 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 the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.

Use of estimates in goodwill impairment testing

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

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

Use of estimates in long-lived asset impairment testing

Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset’s carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

13

Table of Contents

Employee benefit plans

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

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

n Historical return analysis to determine expected future risk premiums;

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

n Expected inflation and risk-free interest rate assumptions and

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

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

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. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through rates. Regulatory liabilities represent probable future reductions in revenue associated with expected customer credits through rates or amounts collected from customers for expenditures not yet incurred. Management makes assumptions regarding the probability of regulatory asset recovery through future rates approved by applicable regulatory authorities. The expectations of future recovery are generally based upon orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, they would be expensed in the period such assessment is made. See Notes 2 and 12 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 capitalized asset retirement costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proved reserve quantities and estimates of the amount and timing of future expenditures to develop the proved reserves. Proved reserves, and the cash flows related to these reserves, are estimated based on a combination of historical data and expected future activity. Actual reserve quantities and development expenditures may differ from the forecasted amounts.

In addition, 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 revenues to be derived from the production of proved gas and oil reserves assuming period-end hedge-adjusted prices. The Company performs the ceiling test quarterly, on a country-by-country basis, and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. Any impairment of excess gas and oil property costs over the ceiling is charged to operations. Given the volatility of natural gas and oil prices, it is possible that 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 have declined as of the date of the ceiling test, or if the Company revises its estimates of the quantities or timing of future production from its proved reserves, recognition of natural gas and oil property impairments could occur. See Notes 2 and 25 to the Consolidated Financial Statements.

14

Table of Contents

Newly Adopted Accounting Standards in 2003

During 2003, the Company was required to adopt several new accounting standards which affect the comparability of its Consolidated Financial Statements. The requirements of those standards are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The following discussion is presented to provide an understanding of the financial statement impacts of those standards when comparing the 2003 Consolidated Financial Statements to prior years.

SFAS No. 143

Adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003 affected the comparability of the Company’s 2003 Consolidated Financial Statements to those of prior years as follows:

n Recognition of asset retirement obligations of $198 million and reversal of $84 million that had been previously recorded in the accumulated provision for depreciation, depletion and amortization and

n Recognition of $109 million of capitalized asset retirement costs in property, plant and equipment and a $3 million increase in accumulated depreciation, depletion and amortization, representing the depreciation of such costs through December 31, 2002.

FIN 46R

Upon adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R), on December 31, 2003 with respect to special purpose entities, the Company was required to consolidate a variable interest lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet at December 31, 2003 reflects an additional $223 million in net property, plant and equipment and deferred charges and an additional $234 million of related debt.

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

Results of Operations

Following is a summary of contributions by its operating segments to net income for the year ended December 31, 2003 and 2002:

Overview

2003 vs. 2002

Net income in 2003 was $638 million, reflecting no change from 2002. The Company’s primary operating segments contributed an additional $81 million to net income. This increase largely reflects the benefits of higher natural gas prices during 2003 on sales of the Company’s gas and oil production. See Note 24 to the Consolidated Financial Statements for information about the Company’s operating segments. The increased contribution by the operating segments was offset by several specific charges to income recognized by the Company during 2003 and reported in the Corporate and Other segment, including:

n $65 million of after-tax charges for asset impairments related to its international business that is held for sale;

n $11 million after-tax loss from adopting new accounting standards and

n $4 million of after-tax severance costs for workforce reductions.

Analysis of Consolidated Operations

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

15

Table of Contents

An analysis of the Company’s results of operations for 2003 compared to 2002 follows:

Operating Revenue

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

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

n Comparably colder weather in the first and fourth quarters of 2003 ($79 million), reflecting 7% more heating degree-days in 2003.

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

Nonregulated gas sales revenue increased 73% to $1.5 billion primarily reflecting a $642 million increase in revenue from field services and retail energy marketing operations, reflecting higher prices ($473 million) and higher volumes ($169 million). The increase includes $533 million of higher gas sales to another Dominion affiliate, as part of Dominion’s enterprise-wide price risk management strategy. See Note 23 to the Consolidated Financial Statements.

Gas transportation and storage increased 4% to $767 million primarily reflecting higher storage revenues related to the reactivation of the Cove Point LNG facility in August 2003.

Gas and oil production revenue increased 19% to $1.2 billion due primarily to higher average realized prices for gas and oil. It also includes $43 million related to deliveries under a volumetric production payment (VPP) transaction.

Other revenue increased 40% to $579 million, primarily reflecting:

n A $107 million increase in nonregulated electric revenue primarily resulting from customer growth in retail energy sales ($76 million) and increased revenue from the Company’s power generation facilities ($31 million);

n A $22 million increase in sales of extracted products;

n An $18 million increase in brokered oil sales primarily due to higher realized prices and

n A $13 million increase in gathering service revenue associated with the distribution operations.

Operating Expenses and Other Items

Purchased gas expense increased 77% to $2.2 billion, primarily reflecting:

n A $591 million increase associated with field services and retail energy marketing, reflecting higher prices ($442 million) and higher volumes ($149 million);

n A $335 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue and

n A $30 million increase associated with brokered gas sales, reflecting higher commodity prices.

The increase includes $343 million of higher gas purchases from another Dominion subsidiary. See Note 23 to the Consolidated Financial Statements.

Electric fuel and energy purchases expense increased 90% to $196 million, associated with nonregulated electric energy marketing operations, related primarily to higher volumes, including $44 million of additional energy purchases from another Dominion subsidiary. See Note 23 to the Consolidated Financial Statements.

Liquids, pipeline capacity and other purchases expense increased 20% to $187 million reflecting primarily $16 million of higher Exploration & Production segment oil purchases and $15 million of gas transmission and storage costs that were recovered through rates and reflected in gas transportation and storage revenue.

Other operations and maintenance expense increased 25% to $712 million, primarily reflecting the following increases:

n Costs related to current year gas and oil production activities ($61 million);

n Decrease in net pension credits and an increase in other postretirement benefit (OPEB) costs ($56 million);

n Accretion expense for asset retirement obligations ($12 million);

n Asset impairment loss related to the Company’s generation facility in Kauai, Hawaii that was sold in December 2003 ($16 million) and

n Provision for workforce reductions ($6 million).

These increases were partially offset by lower bad debt expense ($7 million).

Depreciation, depletion and amortization (DD&A) expense increased 5% to $581 million, primarily reflecting higher finding and development costs.

Other taxes increased 11% to $225 million, primarily due to higher gross receipts taxes and severance taxes, partially offset by lower sales and use taxes.

Other income (loss) decreased $67 million, primarily reflecting an impairment loss related to CNG International’s equity investment in Australian natural gas pipelines that are held for sale.

Income taxes—The Company’s effective tax rate increased to 36.5% for 2003, primarily as a result of the expiration of nonconventional fuel credits as of January 1, 2003, benefits related to including certain subsidiaries in consolidated state income tax returns in 2002 and the establishment of a valuation allowance in 2003.

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

n A $5 million after-tax loss related to SFAS No. 143, and

n A $6 million after-tax loss related to FIN 46R.

Segment Results of Operations

Energy Segment

The Energy segment includes the Company’s natural gas transmission pipeline and storage businesses, including the

16

Table of Contents

Cove Point LNG facility, certain natural gas production and field services (aggregation of gas supply and related wholesale activities) operations.

bcf = billion cubic feet

Presented below are the key factors that impacted the Energy segment’s operating results:

The increase in net income primarily reflects the following:

n Field services operations benefited from higher commodity sales prices and higher volumes;

n Reactivation of the Cove Point LNG unloading facility in August 2003 and

n Higher realized prices received on Appalachian natural gas production.

Delivery Segment

The Delivery segment includes the Company’s regulated gas distribution and customer service business and nonregulated energy marketing operations and related products and services.

Presented below are the key factors that impacted the Delivery segment’s operating results:

The increase in net income primarily reflects the following:

n Weather often has a significant impact on Delivery’s distribution operations. Higher gas sales and transport volumes were attributed to comparably colder weather in the first quarter and fourth quarter of 2003. Heating degree-days were 7% higher in the franchise service areas in 2003;

n Decrease in net pension credits and an increase in OPEB costs and

n Bad debt expenses were lower in 2003. In December 2003, the Public Utility Commission of Ohio approved a bad debt rider, effective January 1, 2003, that permits the Company to recover all qualifying actual incremental bad debt expense for customers in that gas utility service territory. The 2003 benefit relates to the deferral of 2003 bad debt expenses as a regulatory asset, pending future recovery.

Exploration & Production Segment

The Exploration & Production segment includes the Company’s gas and oil exploration, development and production business.

bbl = barrel

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

Presented below are the key factors that impacted the segment’s operating results:

17

Table of Contents

The increase in net income primarily reflects the following:

n Higher average realized prices for gas and oil;

n Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production. A reduction in production associated with the sale of mineral rights under a volumetric production payment agreement (VPP) was more than offset by increased Gulf of Mexico gas production;

n Higher DD&A rate applied to current year production, reflecting increased acquisition, finding and development costs;

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

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

n Higher income taxes primarily reflecting the expiration of Section 29 production credits beginning in 2003.

Corporate and Other

Corporate and other includes the operations of CNG International and other minor subsidiaries.

The net loss for Corporate and Other was $69 million for 2003, compared to net income of $12 million in 2002. The 2003 net loss primarily reflected:

n A $78 million ($65 million after-tax) charge for impairment losses related to certain CNG International investments classified as assets held for sale (see Note 7 to the Consolidated Financial Statements);

n A $6 million ($4 million after-tax) charge for severance costs related to workforce reductions, including $3 million, $2 million and $1 million attributable to the Energy, Delivery and Exploration & Production segments, respectively;

n A $6 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of FIN 46R on December 31, 2003 (see Note 3 to the Consolidated Financial Statements); and

n A $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 on January 1, 2003 (see Note 3 to the Consolidated Financial Statements) attributable to the Energy segment.

Credit Risk

The Company’s exposure to potential credit risk results primarily from its marketing of natural gas and sales of gas and oil production. Presented below is a summary of the Company’s net credit exposure as of December 31, 2003. The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. At December 31, 2003, the Company held no collateral made available by its counterparties.

18

Table of Contents

Risk Factors and Cautionary Statements That May Affect Future Results

Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; 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; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; political and economic conditions (including inflation and deflation) and completing the divestiture of investments held by CNG International Corporation. Other more specific risk factors are as follows:

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, causing production delays and unusual maintenance and repair that require the Company to incur additional expenses.

The Company is subject to complex governmental regulation that could adversely affect its operations. The Company’s operations are subject to extensive regulation and require numerous permits, approvals and certificates from federal, state and local governmental agencies. The Company must also comply with environmental legislation and associated 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 expenses 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 and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

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 contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 9 to the Consolidated Financial Statements.

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

An inability to access financial markets could affect the execution of 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 and its subsidiaries 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

19

Table of Contents

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 February 2, 2004, the Company’s senior unsecured debt was rated BBB+, negative outlook, by Standard & Poor’s, and A3, negative outlook, by Moody’s. Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or modify its business plans in ways that may adversely affect its growth and earnings per share. A reduction in 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 future changes in accounting standards or practices may have on public companies in general or the energy industry or its operations specifically. New accounting standards could be issued that could change the way the Company records revenue, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company’s reported earnings or could increase reported liabilities.

20

Table of Contents

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part II, Item 7. MD&A of this Form 10-K. The reader’s attention is directed to those paragraphs and Risk Factors and Cautionary Statements That May Affect Future Results in MD&A, for discussion of various risks and uncertainties that may affect the future of the Company.

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 in prices received and paid for natural gas and oil. The Company uses derivative instruments to manage price risk exposures for these operations.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market rate sensitive instruments over a selected time period due to a 10% 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. 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% unfavorable change in market prices of the Company’s derivative commodity instruments would have resulted in a decrease in fair value of approximately $370 million and $352 million as of December 31, 2003 and 2002, 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 real- ized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are substantially offset by recognition of the hedged transaction, such as revenue from sales.

Interest Rate Risk

The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swap agreements. For financial instruments outstanding at December 31, 2003, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $3 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2002, would have resulted in a decrease in annual earnings of approximately $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. Based on Dominion’s credit policies and the Company’s December 31, 2003 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

21

Table of Contents

Item 8. Financial Statements and Supplementary Data

Index

22

Table of Contents

Report of Management’s Responsibilities

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 2003 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by Dominion’s Audit Committee which is composed entirely of independent directors. Deloitte & Touche LLP’s 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 Board of Directors also serves as the Company’s Audit Committee and 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.

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

Consolidated Natural Gas Company

23

Table of Contents

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, 2003 and 2002, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

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

/s/    DELOITTE & TOUCHE LLP

Richmond, Virginia

February 26, 2004

24

Table of Contents

Consolidated Natural Gas Company

Consolidated Statements of Income

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

25

Table of Contents

Consolidated Natural Gas Company

Consolidated Balance Sheets

26

Table of Contents

Consolidated Natural Gas Company

Consolidated Balance Sheets (Continued)