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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

For the transition period from                      to                    

Commission File Number 1-3196

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 (as defined in Exchange Act Rule 12b-2). Yes  ¨    No  x

The aggregate market value of the voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was zero.

As of February 1, 2005, 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

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).

The “Company” is used throughout this report and, depending on the context of its use, refers 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, 2004, the Company had approximately 4,600 full-time employees. Approximately 2,500 employees are subject to collective bargaining agreements. The contract of employees represented by the Utility Workers’ Union of America, United Gas Workers’ Local 69-11, AFL-CIO (Local 69-II) expires April 1, 2005. The Company and Local 69-II have begun negotiations for a new contract.

The Company was incorporated in Delaware in 1999. 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 along three primary operating segments: Delivery, Energy and Exploration & Production. The Company also reports Corporate and Other functions as a segment. While the Company manages its daily operations as described below, its assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Notes 1 and 23 to the Consolidated Financial Statements.

Delivery

Delivery includes the Company’s regulated gas distribution utilities and customer service operations as well as retail energy marketing operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Retail energy marketing operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest regions.

Competition

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 does not require customer choice in its retail natural gas markets at this time. See Regulation—State Regulations for additional information.

Regulation

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

Properties

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 and 203 billion cubic feet (bcf) of underground storage capacity in Ohio, Pennsylvania and West Virginia. See Energy—Properties for additional information regarding Delivery’s storage properties.

Sources of Fuel Supply

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

Seasonality

Gas sales in the Delivery segment typically vary seasonally based on demand by residential and commercial customers for heating use due to changes in temperature.

Energy

Energy includes the following operations:

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Competition

The Energy segment 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.

Regulation

Energy’s natural gas transmission, storage and LNG operations are subject to regulation by the Federal Energy Regulatory Commission (FERC). See Regulation—Federal Regulations for additional information.

Properties

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

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

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

Sources of Energy Supply

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 accessibility to supplies nationwide.

The Company’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Midwest, Mid-Atlantic and Northeast’s regions. In

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addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.

Seasonality

The Energy segment is affected by seasonal changes in the prices of commodities that it actively markets.

Exploration & Production

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.

Competition

Exploration & Production’s competitors range from major international oil companies to smaller independent producers. Exploration & Production faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Exploration & Production is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development.

In terms of its production activities, Exploration & Production sells most of its deliverable natural gas and oil into short and intermediate-term markets. Exploration & Production faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, Exploration & Production owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions which strengthens its knowledge of the marketplace and delivery options.

Regulation

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

Properties

Exploration & Production owns 5.1 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. Exploration & Production also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. Exploration & Production’s share of developed leasehold totals 2.3 million acres, with another 1.7 million acres held for future exploration and development drilling opportunities. See also Item 2. Properties for additional information on Exploration & Production’s properties.

Bcfe = billion cubic feet equivalent

Mmcfe = million cubic feet equivalent

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Seasonality

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

Corporate and Other

The Company also has a Corporate and Other segment. Corporate and Other includes the activities of CNG International (CNGI) 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. CNGI was 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, has sold the majority of CNG International’s assets (see Note 7 to the Consolidated Financial Statements). This segment also includes the results of the Company’s power generating facility.

Regulation

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

State Regulations

The Company’s gas distribution service is regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission.

Status of Gas Deregulation

Each of the three states in which 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, 2004, approximately 548,000 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, 2004, approximately 88,000 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 one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

Ohio— In December 2003, the Ohio Commission approved a joint application filed by 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 rates, the Company recovers all eligible bad debt expenses through the bad debt tracker and removes bad debt from base rates. Annually, the Company assesses the need to adjust the tracker based on the preceding year’s actual bad debt expense.

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

Federal Regulations

Public Utility Holding Company Act of 1935

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

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Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by the Company’s interstate gas pipeline subsidiaries, including Dominion Transmission, Inc. (DTI) and Dominion Cove Point LNG, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

FERC Order 636 requires transmission pipelines to operate as open-access transporters and provide transportation and storage services on an equal basis for all gas suppliers, whether purchased from the Company or from another gas supplier.

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 Pipeline Safety Act of 2002, which includes new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission and storage pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Company has evaluated its natural gas transmission and storage properties under the final regulations issued in December 2003 and has developed the required implementation plan including identification, testing and potential remediation activities.

The Company is also subject to FERC’s Standards of Conduct that govern conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The rule defines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences.

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

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

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

Environmental Regulation

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 19 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.

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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. The Company’s assets consist primarily of its investments in its subsidiaries, the principal properties which are described below and in Item 1. Business.

Information detailing the Company’s gas and oil operations presented below includes the activities of the Exploration & Production segment and the production activity of Dominion Transmission, Inc. (DTI), 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, 2004 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.

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 oper-ations at market prices) realized during the years 2004, 2003 and 2002 was $4.19, $4.15 and $3.60, respectively. The respective average prices without hedging results per mcf of gas produced were $5.83, $5.26 and $3.25, respectively. The respective average sales prices realized for oil with hedging results were $24.51, $24.80 and $23.73 per barrel and the respective average prices without hedging results were $39.96, $30.74 and $25.03 per bar-rel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2004, 2003 and 2002 was $0.78, $0.75 and $0.51 respectively.

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Acreage

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

Net Wells Drilled in the Calendar Year

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

As of December 31, 2004, 111 gross (79 net) wells were in process of being drilled, including wells temporarily suspended.

Productive Wells

The number of productive gas and oil wells in which the Company had an interest at December 31, 2004, follows:

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

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Item 3. Legal Proceedings

From time to time, the Company is alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Company, 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 is 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 19 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 Hidalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

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

In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against Dominion Exploration & Production, Inc. (formerly known as CNG Producing Company), a subsidiary of CNG, alleging various fraudulent valuation practices in the payment of royalties on federal leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against CNG Producing Company was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied the defendant’s motion to dismiss on jurisdictional grounds in January 2005. Discovery may begin in the matter in the spring of 2005.

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

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

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

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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 as follows (in millions):

Restrictions on the payment of dividends by the Company are discussed in Note 17 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:

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 through three primary operating segments: Energy, Delivery and Exploration & Production. 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. Those specific items are reported in the Corporate and Other segment.

Energy includes the following operations:

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 LNG facility are

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based primarily on cost-of-service rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flow provided by these regulated businesses results primarily from changes in rates and the demand for services. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding 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 arrangements 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 labor and benefits, 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 as well as retail energy marketing operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Retail energy marketing operations include the marketing of gas, electricity and related products and services to residential and small commercial customers in the Northeast, Mid-Atlantic and Midwest.

Revenue and cash flow provided by the Company’s gas distribution utility operations are based primarily on cost-of-service rates established by state regulatory authorities and state law. 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 cost of gas purchased and sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail marketing operations may vary in connection with changes in weather and commodity prices as well as the 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 maintains an active and ongoing 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.

Revenue and cash flow provided by exploration and production operations are based primarily on the production and sale of company-owned natural gas and oil reserves. Variability in 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 the storm-related damage caused by Hurricane Ivan. 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 or decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related exploration and production service industry costs, while severance and property taxes vary based on changes in revenue. A changing price environment impacts both operating costs and the cost of acquiring, finding and developing natural gas and oil reserves.

Corporate and Other includes the activities of CNG International (CNGI), the Company’s power generating facility, 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. CNGI was 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, has sold the majority of CNGI’s assets (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

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under different conditions or using different assumptions. Management has discussed the development, selection and disclosure of each of these with the Company’s Audit Committee.

Accounting for derivative contracts at fair value

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

Fair value of derivatives is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and use of statistical methods. For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions. The Company uses other option models when contracts involve different commodities or commodity locations and when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach. If pricing information is not available from external sources, judgment is required to develop estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

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

Use of estimates in goodwill impairment testing

As of December 31, 2004, the Company reported $623 million of goodwill on its Consolidated Balance Sheet. The majority of this goodwill is allocated to the Exploration & Production reporting unit, with the remainder allocated to the Energy reporting unit. In April of each year, the Company tests its goodwill for potential impairment, and performs additional tests more frequently if impairment indicators are present. The 2004 annual test did not result in the recognition of any impairment of goodwill, as the estimated fair values of the Company’s reporting units exceeded their respective carrying amounts.

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

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 and the anticipated rate of increase in health care costs and participant compensation, also have a significant impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants rather than immediately.

    The selection of expected long-term rates of return on plan assets, discount rates and medical cost trend rates are critical assumptions. 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:

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. The Company calculated its pension cost using an expected return on plan assets

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assumption of 8.75% for 2004 and 2003. The Company calculated its other postretirement benefit cost using an expected return on plan assets assumption of 8.0% for 2004 and 2003. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets and because other postretirement benefit activity, unlike the pension activity, is partially taxable.

Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under the Company’s plans. Due to declines in bond yields and interest rates, the Company reduced the discount rate used to calculate 2004 pension and other postretirement benefit cost to 6.25% from the 6.75% discount rate that the Company used to calculate 2003 pension and other postretirement benefit cost.

The medical cost trend rate assumption is established based on analyses performed by a third party actuarial firm of various factors including the specific provisions of the Company’s medical plans, actual cost trends experienced and projected, and demographics of plan participants. The Company’s medical cost trend rate assumption as of December 31, 2004 is 9.0% and is expected to gradually decrease to 5.0% in later years.

Accounting for regulated operations

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

Management evaluates whether or not recovery of its regulatory assets through future regulated rates is probable and makes various assumptions in its analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, the regulatory asset will be written off and an expense will be recorded in the period such assessment is made. Management currently believes the recovery of its regulatory assets is probable. See Notes 2 and 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 Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using the units-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves assuming period-end pricing adjusted for cash flow hedges in place. The Company performs the ceiling test quarterly and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil.

The Company’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Given the volatility of natural gas and oil prices, it is possible that the Company’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could change in the near term.

The process to estimate reserves is imprecise, and estimates are subject to revision. In the last five years, revisions to the Company’s estimates of proved developed and undeveloped reserves have averaged approximately 4% of the previous year’s estimate. If there is a significant variance in any of the Company’s estimates or assumptions in the future and revisions to the value of the Company’s proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2 and 25 to the Consolidated Financial Statements.

Income Taxes

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

Newly Adopted Accounting Standards

During 2004 and 2003, the Company was required to adopt several new accounting standards, the requirements of which are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affected the

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comparability of the Company’s 2004 Consolidated Statement of Income to prior years as follows:

Other

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

Under the primary guidance of Emerging Issue Task Force (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, the Company presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF is evaluating whether these types of transactions should be presented net in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on the Company’s results of operations or cash flows. The portion of the Company’s operating revenue from external customers related to buy/sell activity for the years 2004, 2003, and 2002 was 5.3%, 3.9%, and 4.4% respectively. Reported production volumes are not impacted, as only the initial sale of Company owned production is included in reported production volumes. It is estimated that approximately 62% of the Company’s 2004 oil production was marketed through the use of one or more crude oil buy/sell agreements. See Note 2 to the Consolidated Financial Statements.

Results of Operations

Presented below is a summary of contributions by the Company’s operating segments to net income:

Overview

2004 vs. 2003

Net income increased 36% to $867 million as compared to 2003. The Company’s primary operating segments contributed an additional $225 million to net income. See Note 23 to the Consolidated Financial Statements for more information about the Company’s operating segments. This increase largely reflects:

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Analysis of Consolidated Operations

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

An analysis of the Company’s results of operations for 2004 compared to 2003 follows:

Operating Revenue

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

Nonregulated electric sales revenue increased 68% to $390 million, resulting primarily from increased volumes ($165 million) and higher prices ($16 million) in the Company’s nonregulated retail energy marketing operations, partially offset by lower revenue ($19 million) due to the sale of CNGI’s generation assets in Hawaii in December 2003.

Nonregulated gas sales revenue increased 30% to $2.0 billion, which was largely offset by a corresponding increase in Purchased gas, net expense. This increase primarily reflects:

Gas transportation and storage revenue increased 7% to $819 million, primarily reflecting:

Gas and oil production revenue increased 10% to $1.3 billion as a result of:

Other revenue increased 84% to $640 million, primarily reflecting:

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Operating Expenses and Other Items

Purchased gas, net expense increased 27% to $2.8 billion, principally resulting from:

Electric fuel and energy purchases expense increased 78% to $349 million, primarily reflecting the following:

Liquids, pipeline capacity and other purchases expense increased 56% to $292 million, reflecting primarily a $108 million increase related to purchases of oil by exploration and production operations, as discussed above in Other revenue.

Other operations and maintenance expense increased 5% to $750 million, primarily reflecting the following:

Depreciation, depletion and amortization (DD&A) expense increased 8% to $627 million, primarily reflecting higher exploration and production finding and development costs, and higher depreciation expense resulting from property additions, including the consolidation of a variable interest entity as a result of adopting FIN 46R at December 31, 2003.

Other taxes increased 20% to $270 million, primarily due to higher gross receipts taxes and higher severance and property taxes associated with increased commodity prices.

Other income increased $87 million, primarily reflecting a $31 million benefit in 2004 related to the sale of a portion of CNGI’s equity investment in an Australian pipeline business, consisting of an $18 million favorable adjustment to the carrying amount of this investment and a $13 million gain on the sale. In 2003, a $62 million impairment charge was recognized on this investment, based on estimated fair value at that time.

Interest expense increased 12% to $172 million, primarily reflecting:

Income taxes—The Company’s effective tax rate decreased 0.7% to 35.8% for 2004, reflecting a net reduction in state tax expense partially offset by other factors.

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:

Segment Results of Operations

Energy Segment

Energy includes the Company’s natural gas transmission pipeline and storage system, certain gas production operations, an LNG import and storage facility and producer services operations which include aggregation of gas supply and related wholesale activities.

bcf = billion cubic feet

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

Energy’s net income contribution increased $15 million, primarily reflecting:

Delivery Segment

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

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

Delivery’s net income contribution increased $7 million, primarily reflecting:

Exploration & Production Segment

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

Exploration & Production’s net income contribution increased $203 million, primarily reflecting:

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Corporate and Other

Corporate and Other includes the Company’s corporate and other functions, including the activities of CNGI, the Company’s power generating facility and other minor subsidiaries.

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

Corporate and Other reported net expenses of $65 million for 2004, compared to net expenses of $69 million in 2003.

The net expenses in 2004 primarily reflected the following:

The 2003 results primarily reflect impairment losses totaling $78 million ($65 million after-tax) related to investments in the Australian pipeline business and a generation facility in Hawaii that was sold in December 2003. In addition, the following specific items attributable to operating segments contributed to the 2003 results:

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, 2004. 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, 2004, the Company held no collateral made available by its counterparties.

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 or ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are subject to changing regulatory structures; changes to regulated gas rates recoverable by the Company; realization of expected business interruption insurance proceeds; political and economic conditions (including inflation and deflation). 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, causing production delays and property damage that require the Company to incur additional expenses.

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The Company is subject to complex government regulation that could adversely affect its operations. The Company’s operations are subject to extensive federal, state and local regulation and may require numerous permits, approvals and certificates from various 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 which could adversely affect its results of operations. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, 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 and liquidity constraints. 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.

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

For additional information concerning derivatives and commodity-based trading contracts, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Market Rate Sensitive Instruments and Risk Management 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 and that could damage facilities, disrupt production or reduce the book value of its assets. Factors that may affect the Company’s financial results include weather that damages or causes the shutdown of its gas and oil producing facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and the Company’s ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.

Short-term market declines in the prices of natural gas and oil could adversely affect the Company’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) 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 February 1, 2005, the Company’s senior unsecured debt is rated BBB+, negative outlook, by Standard & Poor’s and A3, negative outlook, by Moody’s. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, 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 and could require it to post additional margin in connection with some of its marketing activities.

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

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

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 and oil 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 commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $454 million and $370 million as of December 31, 2004 and 2003, respectively.

The impact of a change in energy commodity prices on the Company’s commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are substantially 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, 2004, 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, 2003, 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, including the Company. 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, 2004 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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Item 8. Financial Statements and Supplementary Data

Index

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Report of Management’s Responsibilities

Because the Company is not an accelerated filer as defined in Exchange Act Rule 12b-2, it is not required to comply with Securities and Exchange Commission rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 until December 31, 2005.

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 2004 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent registered public accounting firm, who have been engaged by Dominion’s Audit Committee which is composed entirely of independent directors. Deloitte & Touche LLP’s audit was conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Board of Directors also serves as the Company’s Audit Committee and meets periodically with the independent registered public accounting firm, 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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2005

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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

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

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Consolidated Natural Gas Company

Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income