SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

       For the fiscal year ended December 31, 2001

OR

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

       For the transition period from                        to                       

Commission File Number 1-3196

CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction
of incorporation or organization) 54-1966737 (I.R.S. Employer
Identification Number)

120 Tredegar Street Richmond, Virginia (Address of principal executive offices) 23219 (Zip Code)

(804) 819-2000

(Registrant’s telephone number, including area code)

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

Title of Each Class	Name of Each Exchange on Which Registered
7 1/4% Notes due 2004	New York Stock Exchange
6.0% Debentures due 2010	New York Stock Exchange
6.8% Debentures due 2027	New York Stock Exchange
6 5/8% Debentures due 2008	New York Stock Exchange
6 7/8% Debentures due 2026	New York Stock Exchange
7 3/8% Debentures due 2005	New York Stock Exchange
6 5/8% Debentures due 2013	New York Stock Exchange
5 3/4% Debentures due 2003	New York Stock Exchange
7.8% Trust Preferred Securities, (cumulative) $25 par value	New York Stock Exchange

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

None

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

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

The aggregate market value of the voting stock held by non-affiliates of the registrant as of March 1, 2002, was zero.

As of March 1, 2002 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.

CONSOLIDATED NATURAL GAS COMPANY

Item Number		Page
	PART I
1.	Business	3
	The Company	3
	Recent Developments	3
	Operating Segments	3
	Competition	4
	Delivery	4
	Energy	5
	Exploration and Production	5
	Regulation	5
	General	5
	State Regulation	6
	Public Utility Holding Company Act of 1935	6
	Federal Energy Regulatory Commission	6
	Environmental Matters	7
	Gas Supply	7
	Gas Purchased	7
	Gas Storage	7
	Gas and Oil Producing Activities	8
	Future Sources of Gas Supply	9
2.	Properties	9
3.	Legal Proceedings	13
4.	Submission of Matters to a Vote of Security Holders	13
	PART II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters	14
6.	Selected Financial Data	14
7.	Management’s Discussion and Analysis of Results of Operations	14
7A.	Quantitative and Qualitative Disclosures about Market Risk	28
8.	Financial Statements and Supplementary Data Index	29
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	75
	PART III
10.	Directors and Executive Officers of the Registrant	75
11.	Executive Compensation	75
12.	Security Ownership of Certain Beneficial Owners and Management	75
13.	Certain Relationships and Related Transactions	75
	PART IV
14.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	76

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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, shall refer to CNG, one of CNG’s consolidated subsidiaries, or the entirety of CNG and its consolidated subsidiaries, both before and after the merger with Dominion.

At December 31, 2001, the Company had approximately 4,800 employees. Approximately 2,700 employees are subject to collective bargaining agreements. The contracts of employees represented by Service Employees International Union (SEIU) Local 69-II expire at the end of the first quarter of 2002. The Company and SEIU Local 69-II have begun negotiations for new contracts.

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

Recent Developments

On January 28, 2000, Dominion acquired all of the outstanding shares of the Company’s common stock for $6.4 billion, consisting of approximately 87 million shares of Dominion common stock valued at $3.5 billion and approximately $2.9 billion in cash.

In November 2001, Dominion acquired Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) for $1.8 billion in cash and Dominion common stock. Louis Dreyfus is a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. Upon acquisition, Louis Dreyfus was merged with a newly formed wholly-owned subsidiary of Dominion, Dominion Oklahoma Texas Exploration and Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to CNG.

The acquisition of Louis Dreyfus provided a 60 percent increase in Dominion’s proved gas and oil reserves and an 100 percent increase in the Company’s proved reserves. With this acquisition, Dominion became the second largest North American integrated energy company and one of the top five independent exploration and production companies in terms of North American reserves and production. The Louis Dreyfus assets are located in some of the largest and most mature natural gas basins in the United States and will support the acceleration of growth in the Company’s exploration and production activities.

For additional information regarding the above merger and acquisition, see Note 5 to the Consolidated Financial Statements.

Operating Segments

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

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Delivery manages the Company’s retail gas distribution systems and customer service operations. Delivery includes three gas distribution subsidiaries with service territories in Ohio, Pennsylvania, and West Virginia. At December 31, 2001, the Company served at retail approximately 1.7 million customers.

To secure regulatory approval for their merger, Dominion and the Company agreed to divest Virginia Natural Gas, Inc. (VNG), the Company’s gas distribution subsidiary located in Norfolk, Virginia. In October 2000, VNG was sold to AGL Resources, Inc.

Energy manages the Company’s 7,600 miles of gas pipeline, 959 billion cubic foot natural gas storage network, by-product operations and certain gas production and storage operations. Energy provides gas transportation, storage and related services to affiliates and to utilities and end-users in the Midwest, the Mid-Atlantic states and the Northeast. Energy also engages in activities related to Appalachian area natural gas supply and provides natural gas storage facilities, services and other activities of a full service gas storage business.

Exploration and Production (E&P) manages the Company’s onshore and offshore gas and oil exploration, development and production operations. E&P operates on the outer continental shelf and deep water areas of the Gulf of Mexico, the Appalachian Basin the Permian Basin, the Mid-Continent Region, and other selected regions in the continental United States.

The Company also reports the activities of CNG International and other minor subsidiaries in its Corporate and Other segment. However, the Company is no longer investing in energy businesses overseas but is focusing on its core operating segments above. In October 2000, the Company divested its Argentine assets as part of a plan of disposal of international assets. The Company continues to explore the sale of remaining operations in Australia.

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

COMPETITION

Delivery

Competition in the markets served by the distribution subsidiaries continues to increase. As the gas industry has restructured and government regulations have changed, a marketplace has evolved with new and traditional competitors—the usual oil and electric companies, other gas companies, producers seeking to gain direct access to the Company’s customers, and gas brokers and dealers seeking to replace supplies with spot market gas. Natural gas faces price competition with other energy forms, and certain distribution companies’ industrial customers have the ability to switch to fuel oil or coal if desired. In addition, competition is increasing among local distribution companies to provide gas sales and transportation services to commercial and residential customers. Currently, local distribution companies operate in what are essentially dual markets—a traditional utility market, where a utility has an obligation to provide service and offers a ‘‘bundled’’ package of services to all customers and a ‘‘contract’’ market, where obligations are defined by contract terms. In the latter market, large customers can elect individually or in various combinations whatever gas supplies, storage and/or transportation services that they require. The Company has responded to this competitive environment by offering a variety of firm and interruptible services, including gas transportation, storage, supply pooling and balancing, and brokering, to industrial and commercial customers.

Competition 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 Energy Choice to customers on its own initiative, in cooperation with

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The Public Utilities Commission of Ohio. West Virginia legislation currently does not require customer choice in its retail natural gas markets nor has the Company voluntarily initiated an Energy Choice program. However, the West Virginia Public Service Commission recently issued regulations to govern pooling services; these services are one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future.

See Gas Deregulation Legislation in Future Issues and Outlook of Management’s Discussion and Analysis (MD&A) for additional information.

Energy

Energy’s large underground storage capacity and the location of its gridlike pipeline system are a significant link between the country’s major gas pipelines and large markets on the East Coast. The Company’s pipelines are part of an interconnected gas transmission system which continues to provide retail end-users the accessibility of supplies nationwide as gas utilities unbundle services at the retail level.

Energy competes with domestic, as well as Canadian, pipeline companies and gas marketers seeking to provide or arrange transportation, storage and other services for customers. Alternative energy sources, such as fuel oil or coal, are another source 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 individual needs of customers.

Exploration and Production (E&P)

E&P conducts exploration and production operations in several major gas and oil producing basins in the United States, both onshore and offshore. Competitors range from major international oil companies to the smaller, independent producers.

E&P faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since E&P 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, E&P faces a diverse and active market with purchasers seeking to balance the advantage of flexible spot market supplies with the security of longer-term contracts. The growth of gas and energy marketing firms has added additional competition for E&P. When the economics warrant, the Company attempts to sell its gas production under long-term contracts to customers such as electric power generators and others that require a secure source of supply. However, these arrangements represent only a portion of the Company’s gas production. The deliverability of gas produced is influenced by competition for downstream pipeline transportation capacity. The Company continues to develop marketing strategies, contracts and arrangements to address customer needs for intermediate and long-term gas supplies as well as swing, peaking and other energy services. E&P also participates in price risk management activities to manage exposure to price risk in connection with the production and sale of natural gas and oil.

REGULATION

General

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

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State Regulation

The Company’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Pennsylvania, Ohio, and West Virginia. The Company’s regulated gas subsidiaries continue to seek general rate increases with regard to their regulated gathering, transmission, storage and gas distribution services. Such rate changes are requested on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, certain gas distribution subsidiaries of the Company make separate filings with their respective regulatory commissions to reflect changes in the costs of purchased gas.

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

Public Utility Holding Company Act of 1935 (1935 Act)

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

Federal Energy Regulatory Commission (FERC)

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

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

FERC Order 636 (the Order), issued in 1992, significantly increased competition in the natural gas industry. The Order requires that transmission pipelines operate as open-access transporters and provide transportation and storage services on an equal basis for all gas supplies, whether purchased from the Company or from another gas supplier.

FERC has also issued a Notice of Proposed Rulemaking on modifying conduct regulations. FERC proposes to eliminate the separate code of conduct regulations for natural gas pipelines and electric transmission utilities and replace these requirements with uniform standards applicable to interstate “Transmission Providers” of both natural gas and electricity. For additional discussion on this matter, see Interstate Gas Transmission Operations—FERC Policy Developments in Future Issues and Outlook of MD&A.

The Company implemented various rate filings, tariff changes, and negotiated rate service agreements during 2001. In all material respects, the 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.

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Environmental Matters

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

The Company is subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of 1990 (collectively referred to as the Clean Air Act), which require Title V permits for major facilities. The Clean Air Act also requires installation of Maximum Available Control Technology (MACT) to control the emissions of certain hazardous air pollutants from compressor engines. The Company currently cannot estimate what its expenditures for MACT-related controls will be.

The exact nature of environmental issues that the Company may encounter in the future cannot be predicted. At present, no estimate of any such additional liability, or range of liability amounts, can be made. However, the amount of any such liabilities could be material.

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

GAS SUPPLY

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

Gas Purchased

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. While the average term of the Company’s gas purchase agreements has decreased, the reliability of supply continues to be adequate. The availability of supplies and heightened competition has forged a viable market, which has proven capable of satisfying the firm delivery requirement for supplies to the Company’s markets in a highly reliable manner. Purchased gas volumes were 374 billion cubic feet (bcf) or about 72 percent of the total 2001 supply.

Considering the Company’s large storage capacity, the volumes obtainable under its firm interstate pipeline capacity and gas supply contracts, Company-owned proved gas reserves, and assuming the future availability of spot market gas, the Company believes that supplies will be available to meet sales requirements for at least the next several years.

Gas Storage

The Company’s underground storage facilities play an important part in balancing gas supply with sales demand and are essential to servicing the Company’s large volume of space-heating business. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity. The Company operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. The Company owns 20 of these storage fields and has joint-ownership with other companies in

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six of the fields. The total designed capacity of the storage fields, including native gas, is approximately 959 bcf. The Company’s share of the total capacity is about 717 bcf. About one-half of the total capacity is base gas which remains in the reservoirs at all times to provide the primary pressure which enables the balance of the gas to be withdrawn as needed.

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

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

Gas and Oil Producing Activities

Following the acquisition by Dominion, the Company changed its method of presenting gas and oil financial and statistical information from a ‘‘net before royalty’’ basis to a ‘‘net revenue’’ basis to conform to Dominion’s presentation. As a result, amounts previously reported for revenue, royalty expense, and proved gas and oil reserves and production have been restated. The change to the ‘‘net revenue’’ basis also conforms the Company’s presentation to that widely used by the industry.

The following table sets forth 2001 drilling activity by region:

	Wells Drilled
	Exploratory		Development
	Gross	Net	Gross	Net
Onshore (Southwest and West)	37	21	131	111
Gulf of Mexico	23	10	12	6
Appalachian Region	3	1	124	123
Total	63	32	267	240

Of the total 330 gross wells drilled in 2001, 306 were successful, a 93 percent success rate. Of the 63 gross exploratory wells drilled, 39 were successful.

Total Company-owned proved gas reserves at year-end were 2,742 bcf, up from 1,224 bcf at the end of 2000. Proved oil reserves were 124.7 million barrels, compared with 57.3 million barrels in 2000.

At year-end 2001, the Company held 3.2 million net acres of exploration and production properties, up from 2.1 million acres in 2000. The Company’s lease holdings include about 1.2 million net acres in the Appalachian area, 756,000 in the offshore Gulf of Mexico, and 1.3 million in the inland areas of the Southwest, Gulf Coast and West. Effective January 1, 2001, the Company transferred its interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion.

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FUTURE SOURCES OF GAS SUPPLY

In November 2001, Dominion acquired Louis Dreyfus for $1.8 billion in cash and Dominion common stock. The acquisition of Louis Dreyfus provided a 60 percent increase in Dominion’s proved gas and oil reserves and an 100 percent increase in the Company’s proved reserves.

The Company plans to expand its natural gas transmission system with a $497 million, 263-mile interstate pipeline. Plans call for the Greenbrier Pipeline to originate in Kanawha County, West Virginia, with connections to Dominion Transmission and Tennessee Gas pipelines and extend through southwest Virginia into Granville County, North Carolina. Piedmont Natural Gas is a 33 percent owner in the pipeline project.

In 2001, the Company announced it would go forward with the development of its Devils Tower field. The project will utilize a spar that can produce up to 60,000 barrels of oil per day. First production is expected in mid-2003. The Company owns a 75 percent working interest in Devils Tower. Pioneer Natural Resources Company owns the remaining 25 percent interest.

During 2000, the Company acquired 167 billion cubic feet equivalent (bcfe) of gas reserves and additional acreage for exploratory and developmental drilling through a number of purchase transactions. Significant acquisitions during the year included the purchase of additional interests in two deepwater Gulf of Mexico properties and various South Texas gas fields. In January 2000, the Company acquired an additional 12.5 percent interest in Popeye, a deepwater gas producing property, increasing its interest to 50 percent. In August 2000, the Company acquired the operating interests of Suemaur Exploration & Production, LLC and several partners in three Texas Gulf Coast natural gas fields.

ITEM 2.    PROPERTIES

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

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

The Company’s storage operations include 26 storage fields, 342,105 acres of operated leaseholds, 2,069 storage wells, and 822 miles of pipe. Investment in gas transmission facilities includes 6,440 miles of pipe, extending through parts of Ohio, West Virginia, Pennsylvania, Maryland, New York, and Virginia. The Company also has 104 compressor stations with 555,628 installed compressor horsepower located in Ohio, West Virginia, Pennsylvania, and New York. See map below for the Company’s gas transmission pipelines and storage facilities.

The Company’s gas distribution companies are located in the states of Ohio, Pennsylvania and West Virginia and include 27,277 miles of pipe, exclusive of service pipe.

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For additional information on the Company’s gross investment in its property, plant and equipment, see Note 12 to the Consolidated Financial Statements.

Company-Owned Proved Reserves

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

	2001		2000		1999*
	Proved Developed	Total Proved	Proved Developed	Total Proved	Proved Developed	Total Proved
Proved gas reserves (bcf):
United States	2,283	2,742	973	1,223	959	1,204
Canada	–	–	1	1	1	1
Total proved gas reserves	2,283	2,742	974	1,224	960	1,205
Proved oil reserves (000 bbls):
United States	55,176	124,691	21,328	50,691	32,290	42,643
Canada	–	–	6,582	6,582	6,644	6,644
Total proved oil reserves	55,176	124,691	27,910	57,273	38,934	49,287

* Restated from a ‘‘net before royalty’’ basis to a ‘‘net revenue’’ basis.

Certain subsidiaries of the Company file Form EIA-23 with the DOE. The difference between the proved reserves reported on Form EIA-23 and the company-owned proved reserves does not exceed five percent.

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Estimated proved reserves as of December 31, 2001 are based upon studies prepared by the Company’s staff engineers and reviewed by Ralph E. Davis Associates, Inc. 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 follow:

	Year Ended December 31
	2001	2000	1999*
Gas production (bcf):
United States	170	173	153
Canada	—	—	—
Total gas production	170	173	153
Oil production (000 bbls):
United States	6,953	6,861	8,216
Canada	—	352	329
Total oil production	6,953	7,213	8,545

* Restated from a ‘‘net before royalty’’ basis to a ‘‘net revenue’’ basis.

The average sales prices (including transfer to other operations as determined under Financial Accounting Standards Board rules) per thousand cubic feet (mcf) of gas produced during the years 2001, 2000, and 1999 were $4.07, $3.08 and $2.26, respectively. The average sales prices for oil were $22.00, $18.60, and $12.67 per barrel. The average production (lifting cost) per mcf equivalent of gas and oil produced during the years 2001, 2000, and 1999 were $0.49, $0.43 and $0.40, respectively.

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Productive Wells

The number of productive gas and oil wells in which the Company’s subsidiaries have an interest at December 31, 2001, follow:

	Gross	Net
Total gas wells	17,913	10,742
Total oil wells	278	206

Includes 177 gross (69 net) multiple completion gas wells and 8 gross (3 net) multiple completion oil wells.

Acreage

The following table sets forth the gross and net developed and undeveloped acreage of the Company’s subsidiaries at December 31, 2001:

	Developed		Undeveloped
	Gross	Net	Gross	Net
Acreage	3,228,426	2,052,480	2,144,098	1,184,870

Net Wells Drilled in the Calendar Year

The numbers of net wells completed during each of the last three years follow:

	Year Ended December 31,
	2001	2000	1999
Exploratory:
United States:
Productive	18	2	7
Dry	14	9	6
Total exploratory	32	11	13
Development:
United States:
Productive	239	125	49
Dry	1	2	1
Total United States	240	127	50
Canada:
Productive	—	9	2
Dry	—	—	—
Total Canada	—	9	2
Total development	240	136	52
Total wells drilled	272	147	65

As of December 31, 2001, 60 gross (45 net) wells were in the process of being drilled, including wells temporarily suspended.

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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. From time to time, there may be administrative proceedings pending on these matters. In addition, in the normal 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 under Item 1. BUSINESS, Regulated Gas Distribution Operations in Future Issues and Outlook of MD&A, and Note 21 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.

In 2001, the Delaware Court of Chancery dismissed a Class Action Complaint that was filed against the Company and certain directors in 1999 upon the announcement of Dominion’s acquisition of the Company.

In July 1997, Jack Grynberg, an oil and gas entrepreneur brought suit against the Company and several of its subsidiaries. The suit seeks damages for alleged fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. In April 2001, the U.S. District Court of the Eastern District of Wyoming issued an order denying a motion to dismiss. The defendants in this matter have filed a motion to certify the case for appeal.

In 1999, Quinque Operating Co. and others filed a class action suit against approximately 300 defendants, including the Company and several of its subsidiaries, in Stevens County, Kansas. The complaint seeks damages for alleged fraud, misrepresentation, conversion and assorted other claims, in the measurement and payment of gas royalties from privately held gas leases. The case has been remanded to the Kansas state court by the federal judge overseeing the above Grynberg case. The plaintiffs will seek class certification and expedited discovery in Kansas. The defendants have filed motions to dismiss the case.

In August 1990, Dominion Transmission entered into a Consent Order and Agreement (the Order and Agreement) with the Commonwealth of Pennsylvania Department of Environmental Protection (DEP) in which Dominion Transmission agreed with the DEP’s determination of certain violations of the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law and related rules and regulations. No civil penalties have been assessed. The Order and Agreement requires Dominion Transmission to perform sampling, testing and analysis, and remediation at some of its Pennsylvania facilities. All actions under the Order and Agreement have been substantially completed as of December 31, 2001.

Before being acquired by Dominion, Louis Dreyfus was named as a defendant in several lawsuits originally filed in 1995 that were subsequently consolidated. The lawsuit is now pending in the Texas 93rd Judicial District Court in Hildago County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits as a result of the plume and seeks compensation for these items.

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

Prior to the acquisition of the Company by Dominion on January 28, 2000, the Company’s common stock was publicly traded. The principal market for the stock was the New York Stock Exchange. The price ranges of the common stock for the period January 1 through January 27, 2000 are shown in the following table. Effective with the January 28, 2000 acquisition, Dominion owns all of the Company’s common stock.

	Market Price Range
	High		Low
2000
January 1—January 27	$	68 1/2	$	63 9/16

Cash dividends paid to the Company’s former public shareholders for the period January 1 through January 27, 2000, at the rate of $.485 a share, were $47 million. Cash dividends paid by the Company to Dominion during 2001 and 2000 are presented below. Restrictions on the payment of dividends by the Company are discussed in Note 16 to the Consolidated Financial Statements.

	Quarter
	First		Second		Third		Fourth
	(Millions)
Dividends Paid:
2001	$	—	$	178	$	56	$	102
2000	$	46	$	—	$	—	$	611

ITEM  6.    SELECTED FINANCIAL DATA

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

ITEM  7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Introduction

Management’s Discussion and Analysis (MD&A) explains the results of operations and general financial condition of the Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The “Company” is used throughout MD&A and, depending on the context of its use, refers to Consolidated Natural Gas Company, either before or after the merger with Dominion Resources, Inc. (Dominion).

Cautionary Statements Regarding Forward-Looking Information

From time to time the Company makes statements concerning its 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”, “could”, “plan”, “may”, “should” or other similar words.

Forward-looking statements are made by the Company with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These factors include, but are not limited to:

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

• Catastrophic weather-related damage that could disrupt operations or cause unusual maintenance or repairs;

• Exposure to unanticipated changes in prices for energy commodities purchased or sold;

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• State and federal legislative and regulatory developments, including further deregulation and restructuring of the natural gas industry and changes in environmental and other laws and regulations to which the Company is subject;

• The effects of competition, including the extent and timing of the entry of additional competitors in the gas markets;

• The Company’s pursuit of potential business strategies, including acquisitions or dispositions of assets;

• Regulatory factors such as changes in the policies or procedures that set rates, changes in the Company’s ability to recover investments made under traditional regulation through rates, and changes to the frequency and timing of rate increases;

• Financial or regulatory accounting principles or policies imposed by standard setting bodies;

• Political, legal, and economic conditions and developments in the U.S. This would include the threat of domestic terrorism, inflation rates and monetary fluctuations;

• Changing market conditions and other factors related to physical and financial energy marketing activities, including commodity prices, basis, counterparty credit risk, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates and warranty risks;

• Financial market conditions, including availability and cost of capital, and the Company’s ability to obtain financing on favorable terms;

• The performance of the Company’s projects and the success of efforts to invest in and develop new opportunities, including development of gas and oil projects;

• Employee workforce factors, including collective bargaining agreements with union employees;

• Risks associated with exploring for, developing and producing natural gas and crude oil;

• Maintenance and growth of gas and oil production levels; and

• Anticipated natural gas reserve levels.

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. Interested parties should also consider other risks identified from time to time in the Company’s reports and registration statements filed with the Securities and Exchange Commission (SEC).

Operating Segments

In general, management’s discussion of the Company’s results of operations focuses on the contributions of its operating segments. The Company’s three primary operating segments are as follows:

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

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

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Exploration and Production manages the Company’s onshore and offshore gas and oil exploration, development and production operations. Operations are located on the outer continental shelf and deep water areas of the Gulf of Mexico and in selected regions in the lower 48 states. The operating results of the Exploration and Production segment reflect the successful discovery of and production from natural gas and oil reserves and changes in prices of natural gas and oil. Exploration and Production manages commodity risk through the use of derivative contracts such as forwards, swaps, and options.

In addition, the Company also reports Corporate and Other as a segment. The Corporate and Other segment includes the activities of CNG International (see Note 8 to the Consolidated Financial Statements) and other minor subsidiaries, and certain other charges not allocated to the Company’s other operating segments.

For more information on the Company’s operating segments, see Note 24 to the Consolidated Financial Statements.

Critical Accounting Policies

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

Accounting for risk management contracts at fair value—The Company uses derivatives to manage its commodity and financial market risks. The accounting requirements for derivatives and hedging activities are complex and interpretation of these requirements by standard-setting bodies is ongoing. All derivatives, other than specific exceptions, are reported on the Consolidated Balance Sheet at fair value, beginning in 2001. Changes in fair value, except those related to derivative instruments designated as cash flow hedges, are generally included in the determination of the Company’s net income at each financial reporting date until the contracts are ultimately settled. The measurement of fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies deemed appropriate by management. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition of changes in fair value of certain hedging derivatives. See Market Rate Sensitive Instruments and Risk Management in MD&A and Notes 2 and 11 to the Consolidated Financial Statements.

Accounting for gas and oil operations—The Company follows the full-cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full-cost method, all direct costs of property acquisition, exploration and development activities are capitalized. Depreciation of gas and oil producing properties is computed using the unit-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as dismantlement and abandonment costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proven reserve quantities and estimates of the amount and timing of future expenditures to develop the proven reserves. Actual reserve quantities and development expenditures may differ from the forecasted amounts. Also, amounts capitalized in the depreciable base of costs are subject to a ceiling test. 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. The Company performs the test quarterly and recognizes asset impairments to the extent capitalized costs exceed the ceiling. See Notes 2 and 25 to the Consolidated Financial Statements.

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Accounting for regulated operations—Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition used for accounting purposes, the Company’s consolidated financial statements may recognize a regulatory asset for expenditures that otherwise would be expensed, based on the approval from the appropriate regulatory authority. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. See Notes 2 and 13 to the Consolidated Financial Statements.

Results of Operations

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

	Year Ended December 31,
	Net Income									Operating Revenue									Operating Expenses
	2001			2000			1999			2001			2000			1999			2001			2000			1999
	(Millions)
Delivery	$	148		$	144		$	101		$	1,747		$	1,985		$	1,644		$	1,484		$	1,719		$	1,442
Energy		167			147			128			1,650			1,250			758			1,363			994			535
Exploration and Production		202			138			73			1,009			979			723			674			736			603
Corporate and Other		260			135			31			49			150			228			201			429			453
Eliminations		(386	)		(320	)		(196	)		(218	)		(349	)		(375	)		(218	)		(342	)		(374	)
Total	$	391		$	244		$	137		$	4,237		$	4,015		$	2,978		$	3,504		$	3,536		$	2,659

For additional information about the Company’s operating segments, see Note 24 to the Consolidated Financial Statements.

Consolidated Results of Operations

Net Income

Net income in 2001 was $391 million, an increase of $147 million as compared with net income of $244 million in 2000. Net income for both 2001 and 2000 was impacted by the cumulative effect of changes in accounting principle. In 2001, the effect of the accounting change was a decrease of $14 million related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities (see Note 11 to the Consolidated Financial Statements). In 2000, the effect of the accounting change was an increase of $31 million related to a change in the methodology of calculating the market-related value of pension plan assets (see Note 3 to the Consolidated Financial Statements). Income before the cumulative effect of changes in accounting principle increased $192 million to $405 million in 2001. Significant factors affecting earnings in 2001 and 2000 include:

• the impairment of forward natural gas contracts of approximately $108 million ($69 million after taxes) in 2001 in connection with the reorganization of Enron Corp. and certain of its subsidiaries (collectively referred to as Enron) under Chapter 11 bankruptcy proceedings (see Note 11 to the Consolidated Financial Statements);

• the sale of Virginia Natural Gas (VNG) which resulted in a gain of $163 million ($98 million after taxes) in 2000 (see Note 6 to the Consolidated Financial Statements);

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• the impairment of foreign investments held for sale which resulted in charges totaling $152 million ($99 million after taxes) in 2000 (see Note 8 to the Consolidated Financial Statements); and

• the restructuring and other merger-related costs in 2001, 2000 and 1999 totaling $45 million ($31 million after taxes), $270 million ($195 million after taxes) and $213 million ($145 million after taxes), respectively (see Notes 5 and 6 to the Consolidated Financial Statements).

Earnings in 2001 benefited from increased gas transportation and storage revenue due to rate case settlements by Dominion Transmission, higher gas and oil production revenue attributable to higher prices and, in part, to the acquisition of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) in November 2001 (see Note 5 to the Consolidated Financial Statements), and lower operating expenses. Operating expenses were lower due primarily to lower restructuring and other merger-related costs, and lower brokered gas and oil activities of exploration and production operations, partially offset by increased other operations and maintenance expense, as a result of the Company’s recognition of impairment related to its forward natural gas contracts with Enron (see Note 11 to the Consolidated Financial Statements).

Operating Revenue

Operating revenue includes revenue from regulated gas sales by the Company’s local distribution subsidiaries; nonregulated gas sales by the Company’s Appalachian supply marketing subsidiary and unregulated retail marketing subsidiary; gas transportation and storage services and gas and oil production activities. Other revenue includes oil brokering activities, by-products operations and nonregulated electricity sales. Total operating revenue was $4.2 billion in 2001, as compared to $4.0 billion in 2000.

Regulated gas sales revenue was $1.4 billion in 2001, a decrease of $310 million as compared to $1.7 billion in 2000. Regulated gas sales volumes were 141 billion cubic feet (bcf), a decrease of 83 bcf as compared to 2000. The decrease reflected lower sales to residential and commercial customers, due to the warmer weather experienced in the latter part of 2001, as compared to 2000. The decrease in 2001 sales volumes also reflected the sale of VNG in October 2000. Excluding the effect of VNG’s 2000 sales, volumes decreased 66 bcf. Average sales rates for all customer groups increased in 2001, reflecting the Company’s ability to bill the higher purchased gas costs to its customers.

Nonregulated gas sales revenue was $1.1 billion in 2001, as compared to $746 million in 2000. The increase was attributable to both higher sales volumes and higher prices.

Gas transportation and storage revenue totaled $718 million in 2001, an increase of $167 million, as compared to $551 million in 2000. Gas transportation revenue increased $152 million in 2001, to $572 million. The increase in transport was due primarily to the migration of customers from sales to transport under customer choice programs. Storage service revenue was $146 million in 2001, as compared with $131 million in 2000.

Gas and oil production revenue totaled $706 million in 2001, an increase of $174 million, as compared to $532 million in 2000. Gas production revenue was $575 million in 2001, an increase of $176 million as compared to 2000. Revenue in 2001 also reflected additional sales resulting from the acquisition of Louis Dreyfus in November 2001. Oil and condensate production revenue was $131 million in 2001, as compared to $133 million in 2000. The decrease reflected lower 2001 oil and condensate production volumes which was substantially offset by higher prices.

Other revenue decreased $118 million in 2001, to $349 million. Approximately $104 million of the decrease was attributable to lower volumes of brokered oil sales in 2001, as compared to $327 million of such sales in 2000. Revenue from the sale of products extracted from natural gas decreased $13 million in 2001, to $81 million, resulting from lower by-product prices and lower sales.

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Operating Expenses

Total operating expenses decreased $32 million to $3.5 billion in 2001.

Purchased gas represents the largest expense category for the Company, and relates to volumes purchased to meet sales requirements for regulated and nonregulated operations, including gas-brokering activities. This expense was influenced primarily by changes in gas sales requirements, the price of gas supplies, and the timing of recoveries of deferred purchased gas costs by the rate-regulated subsidiaries. Purchased gas costs were $1.9 billion in 2001, an increase of $212 million, as compared to $1.7 billion in 2000. The increase in 2001 was primarily due to higher purchase prices and recoveries through regulated rates, partially offset by lower volume requirements.

Liquids, pipeline capacity and other purchases include the cost of oil, condensate and by-products purchased for resale, electricity purchased for resale and pipeline capacity not associated with purchased gas. This expense decreased $59 million in 2001, to $269 million, due primarily to lower brokered oil sales.

Restructuring costs of $45 million were recognized in 2001 as a result of a focused review of operations initiated in the fourth quarter. In 2000, restructuring and other merger-related costs of $270 million were incurred in connection with a plan implemented to restructure operations, following the merger with Dominion on January 28, 2000. See Note 6 to the Consolidated Financial Statements.

Other operations and maintenance expense was $705 million in 2001, an increase of $114 million as compared to $591 million in 2000. This increase reflected a charge of approximately $108 million in the fourth quarter of 2001 related to the impairment of forward natural gas contracts with Enron (see Note 11 to the Consolidated Financial Statements).

Depreciation, depletion and amortization decreased $35 million in 2001 to $407 million. The decrease resulted from lower gas and oil production, which was mitigated by the production contribution resulting from the acquisition of Louis Dreyfus in November 2001.

Other taxes decreased $39 million, to $161 million in 2001. The decrease was attributable to lower Ohio property taxes, accompanied by the discontinuance of Pennsylvania gross receipts taxes in 2000 and other miscellaneous taxes.

Other Income (Loss)

Other income and expense included the pretax gain on the sale of VNG of $163 million in 2000. The Company sold VNG in October 2000 pursuant to conditions set forth by the Virginia State Corporation Commission and the Federal Trade Commission in connection with their approvals of the acquisition of the Company by Dominion (see Note 6 to the Consolidated Financial Statements). Other income and expense also included a $152 million pretax loss in 2000, representing impairments of CNG International’s Australian and Argentine investments, and the accrual for a probable equity contribution associated with the Australian investments (see Note 8 to the Consolidated Financial Statements). Other income was $27 million in 2001, as compared to $32 million in 2000.

Interest and Related Charges

Total interest and related charges were $156 million in 2001, as compared to $162 million in 2000. Interest on long-term debt increased $13 million in 2001, to $136 million. This increase was more than offset by the increased capitalized interest related primarily to unproved properties acquired as part of Louis Dreyfus in November 2001. The increase in long-term debt interest reflected primarily the issuances of three series of senior notes, consisting of $500 million of 6.85 percent senior notes in April 2001, $500 million of 5.375 percent senior

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notes in October 2001 and $450 million of 6.25 percent senior notes in October 2001, partially offset by the redemption of $84 million of 8.75 percent senior notes in the first quarter of 2001.

In addition, the Company issued $206 million of its 7.8 percent junior subordinated notes in October 2001 in exchange for the $200 million realized from the sale of trust preferred securities and $6 million of common securities that represent the remaining 3 percent beneficial ownership interest in the assets held by Dominion CNG Capital Trust I (see Note 17 to the Consolidated Financial Statements). On November 1, 2001, the Company assumed two outstanding series of Louis Dreyfus senior notes, totaling $294 million, as part of the acquisition (see Note 5 to the Consolidated Financial Statements).

Results of Operations—Operating Segments

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

Net income for each of the Company’s operating segments, which include affiliated transactions, for the years ended December 31, 2001 and 2000 follows. See Note 24 to the Consolidated Financial Statements for additional information.

	Delivery		Energy		Exploration and Production		Corporate and Other			Eliminations			Total
	(Millions)
2001
Income (loss) before cumulative effective of a change in accounting principle	$	148	$	167	$	202	$	274		$	(386	)	$	405
Cumulative effect of a change in accounting principle		—		—		—		(14	)		—			(14	)
Net income (loss) contribution	$	148	$	167	$	202	$	260		$	(386	)	$	391
2000
Income (loss) before cumulative effective of a change in accounting principle	$	144	$	147	$	138	$	101		$	(317	)	$	213
Cumulative effect of a change in accounting principle		—		—		—		34			(3	)		31
Net income (loss) contribution	$	144	$	147	$	138	$	135		$	(320	)	$	244

Delivery Segment

The Company’s Delivery segment includes the results of its retail gas distribution subsidiaries: The East Ohio Gas Company (Dominion East Ohio), The Peoples Natural Gas Company (Dominion Peoples) and Hope Gas, Inc. (Dominion Hope). These subsidiaries sell gas and provide transportation services to residential, commercial and industrial customers in Ohio, Pennsylvania and West Virginia, and are subject to price regulation by their respective state utility commissions. The Delivery segment also included the results of VNG prior to its sale in October 2000. VNG provided gas sales and transportation services to customers in Virginia, and was subject to price regulation by the Virginia State Corporation Commission.

Sales growth in the Company’s residential service areas of Ohio, Pennsylvania and West Virginia has generally been limited since these areas have experienced minimal population growth, and the vast majority of

20

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. Similar to the unbundling of the services provided by gas pipeline companies, gas distribution companies are adapting to the deregulation and unbundling of the retail energy market. Under open access programs in Ohio and Pennsylvania, customers may now choose a gas supplier other than their local gas utility and have the local utility provide transportation of the commodity through its existing delivery system.

During 1997, Dominion Peoples opened its system in Pennsylvania to customer choice. Also in 1997, the Public Utilities Commission of Ohio (Ohio Commission) approved the ‘‘Energy Choice’’ pilot program for certain customers of Dominion East Ohio. Under the pilot program, approximately 15 percent of Dominion East Ohio’s residential and small business customers had the opportunity to purchase their natural gas from competing suppliers. In the fall of 2000, the Ohio Commission approved the expansion of Energy Choice to the 1.2 million customers in the Dominion East Ohio service area. At December 31, 2001, approximately 125,000 customers of Dominion Peoples and 586,000 customers of Dominion East Ohio were participating in these open access programs.

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

	Year Ended December 31,
	2001		2000
	(Millions)
Operating revenue	$	1,747	$	1,985
Income from operations		263		266
	(Billion Cubic Feet)
Throughput:
Gas sales		141		224
Gas transportation		216		209
Total throughput		357		433

Operating Revenue

Total operating revenue of the Delivery segment decreased $238 million in 2001 from $2.0 billion in 2000. Regulated gas sales revenue was $1.4 billion, a decrease of $310 million from $1.7 billion in 2000. The decreased revenue in 2001 reflected warmer weather experienced in the Company’s retail service areas, partially offset by higher average sales rates. Weather in the Company’s retail service areas was milder in 2001, as compared to 2000, which was normal. Heating degree days in 2001 were 9 percent lower than in 2000. Average sales rates for all customer groups increased modestly, reflecting the pass through of higher purchased gas costs. Gas transportation and storage revenue increased $75 million in 2001, to $298 million. The increase was due primarily to higher gas transportation volumes, reflecting the continued migration of residential and commercial customers from sales to transport service under customer energy choice programs in Ohio and Pennsylvania.

Income from operations was $263 million in 2001, as compared to $266 million in 2000. Lower revenue nearly offset the lower operating costs.

Throughput

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

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Gas sales volumes were 141 bcf in 2001, as compared to 224 bcf in 2000. The year-to-year comparison reflected decreased sales in 2001 due to warmer weather, the migration of customers from sales to transport under customer choice programs, and the absence of VNG sales in 2001. Residential gas sales volumes decreased 67 bcf in 2001, to 106 bcf, while volumes transported for residential customers increased 34 bcf. Sales to commercial customers totaled 32 bcf in 2001, a decrease of 16 bcf from 2000, while volumes transported to these customers increased 2 bcf to 43 bcf. Total throughput to industrial customers were 106 bcf in 2001, as compared to 134 bcf in 2000. Industrial transport volumes in 2001 decreased 28 bcf, to 103 bcf, while sales were 3 bcf, a slight increase from the prior year.

Energy Segment

The Energy segment includes the operations of Dominion Transmission, Inc. (Dominion Transmission), Dominion Field Services, Inc. (Dominion Field Services), Dominion Retail, Inc. (Dominion Retail), and Dominion Products and Services, Inc. (Dominion Products and Services). Dominion Transmission, an interstate pipeline company regulated by the Federal Energy Regulatory Commission (FERC), provides gas transportation, storage, gas and oil production activities and related services to affiliates, utilities and end-users in the Midwest, the Mid-Atlantic and the Northeast states. Dominion Field Services is engaged in activities related to Appalachian area natural gas supply and provides services as a full-service gas storage business. Dominion Retail, a nonregulated company, markets natural gas, electricity and related products and services to residential, commercial and small industrial customers, including those within the Company’s traditional retail service areas. Dominion Retail is expected to enable the Company to take advantage of emerging deregulated energy markets for both gas and electricity. Dominion Products and Services provides energy-related services to customers of the Company’s local distribution subsidiaries and others.

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

	Year Ended December 31,
	2001		2000
	(Millions)
Operating revenue	$	1,650	$	1,250
Income from operations		287		256
	(Billion Cubic Feet)
Throughput:
Gas sales		216		187
Gas transportation		549		644
Total throughput		765		831

Operating Revenue

Total operating revenue of the Energy segment was $1.7 billion in 2001, as compared to $1.3 billion in 2000. Gas transportation revenue was $340 million, an increase of $62 million from 2000, primarily as a result of rate case settlements by Dominion Transmission. Storage service revenue was $164 million, an increase of $11 million over $153 million in 2000. Nonregulated gas sales revenue was $1.0 billion, increasing $309 million from 2000, as a result of higher sales volumes due to a higher level of activity and significantly higher sales prices in 2001. The average sales price was $4.76 per thousand cubic feet (mcf) in 2001, as compared to $3.87 per mcf in 2000. Revenue from the natural gas by-products sales was $70 million in 2001, a decrease of $7 million from $77 million in 2000. The decrease reflected lower average sales prices for all by-products in 2001, partially offset by higher sales volumes.

Income from operations was $287 million in 2001, as compared to $256 million in 2000. The higher revenue more than offset the higher operating costs. Purchased gas was the largest component of the operating expenses, increasing $330 million to $1.0 billion in 2001, reflecting the higher prices paid in 2001.

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Throughput

Gas transportation volumes decreased 95 bcf in 2001, to 549 bcf, primarily as a result of warmer weather. Gas marketing sales volumes in 2001 were 216 bcf, up 29 bcf over 187 bcf in 2000, reflecting an increase in Energy Choice customers in Ohio and Pennsylvania.

Exploration and Production Segment

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

On November 1, 2001, Dominion acquired Louis Dreyfus, a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma (see Note 5 to the Consolidated Financial Statements). Upon acquisition, Louis Dreyfus was merged with a newly formed wholly-owned subsidiary of Dominion, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. The results of DOTEPI have been included in the Consolidated Financial Statements since that date. The acquisition of DOTEPI doubled the Company’s proven gas and oil reserves.

The following table sets forth information relating to the Company’s Exploration and Production segment, including gas and oil production, average wellhead prices and other information:

	Year Ended December 31,
	2001		2000
	(Millions)
Operating revenue	$	1,009	$	979
Income from operations	$	335	$	242
Production:
Gas (bcf)		159		160
Oil (000 bbls)		6,544		7,199
Average Wellhead Prices:
Gas (per mcf)	$	4.07	$	3.11
Oil (per bbl)	$	22.00	$	18.67
Other Information:
DD&A (per mcfe)	$	1.24	$	1.30
Average production (lifting) cost (per mcfe)	$	.49	$	.43

bbl = barrel

bcf = billion cubic feet

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

Operating Revenue

Total operating revenue of the Exploration and Production segment increased $30 million to $1.0 billion in 2001. Gas and oil production revenue was $772 million in 2001, increasing $175 million, as compared to $597 million in 2000. Gas production revenue was $642 million in 2001, an increase of $178 million from the prior year, and oil production revenue was $130 million, decreasing $3 million from 2000. Following the nationwide trend in energy prices, the average wellhead prices for gas were higher in 2001. Gas production volumes were

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substantially unchanged from 2000. Revenue from gas and oil brokering activities was $224 million in 2001, a decrease of $103 million from 2000, due primarily to lower transaction volumes and prices for brokering activities.

Income from operations was $335 million in 2001, an increase of $93 million as compared to $242 million in 2000. Higher revenue resulting from higher realized gas prices more than offset the increased other operations and maintenance expense and other taxes.

Corporate and Other Segment

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

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

• 2001 estimated impaired fair value of forward natural gas contracts of $108 million ($69 million after taxes), resulting from the Company’s exposure to Enron (see Note 11 to the Consolidated Financial Statements);

• 2001, 2000 and 1999 restructuring and other merger-related costs of $45 million ($31 million after taxes), $270 million ($195 million after taxes) and $213 million ($145 million after taxes), respectively (see Note 6 to the Consolidated Financial Statements);

• 2000 impairment of foreign investments held for sale of $152 million ($99 million after taxes) (see Note 8 to the Consolidated Financial Statements);

• 2000 gain on the sale of VNG of $163 million ($98 million after taxes) (see Note 6 to the Consolidated Financial Statements); and

• 2000 cumulative effect of the change in pension accounting of $42 million ($31 million after taxes) (see Note 3 to the Consolidated Financial Statements).

Eliminations represent eliminating adjustments for transactions between the operating segments to reconcile the segment information to consolidated amounts.

Future Issues and Outlook

Regulated Gas Distribution Operations

Gas Deregulation Legislation

Each of the three states in which the Company has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.

Ohio — Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, the Company, on its own initiative, offers retail choice to customers. The Company’s Energy Choice program is available to all 1.2 million customers in the Company’s Ohio service area. At December 31, 2001, approximately 586,000 of the Company’s Ohio customers were participating in this open-access program. Large industrial customers in Ohio also source their own natural gas supplies.

24

Pennsylvania — At December 31, 2001, approximately 125,000 residential and small commercial customers had opted for Energy Choice in the Company’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from unregulated suppliers.

West Virginia — At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. The West Virginia Public Service Commission (West Virginia Commission) recently issued regulations to govern pooling services; these services are one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future.

Rate Matters—Gas Distribution

Ohio — In October 2001, the Ohio Commission approved a program developed by the Company to address the inability of certain customers to pay delinquent account balances. In many cases, these customers were impacted by last winter’s unusually high gas prices and cold weather. Under this one-time matching program, the Company matched dollar-for-dollar, up to $500 per customer, the first payment received by December 31, 2001 for qualifying customers who had received a disconnection notice or who had been disconnected as of October 31, 2001. Matching amounts totaling $10 million were credited to customers’ accounts at December 31, 2001.

The Ohio Commission and the Company also agreed that adjustments of approximately $100 million to depreciation were appropriate in order to reflect the effect of certain fixed assets exceeding their original estimated useful lives. The Ohio Commission initially held that payments made under the matching program and subsequent write-offs of bad debts in excess of the amount already recovered in rates could be offset by reductions in the excess depreciation reserve through a bad debt rider. The Ohio Commission revised its decision on the bad debt rider but allowed the payment-matching program to continue. Under the revised final order, the Ohio Commission authorized the deferral of certain amounts incurred by the Company in excess of the amount of bad debt expense already recovered in rates, pending recovery in the next rate case. The Company recognized a regulatory asset of $80 million, representing the excess customer bad debt costs as of December 31, 2001. The Company believes that it will recover those amounts deferred. See Note 13 to the Consolidated Financial Statements.

Pennsylvania — The Audit Bureau of the Pennsylvania Public Utility Commission (Pennsylvania Commission) has conducted a compliance audit of the Company’s purchased gas cost rates for the years 1997 through 1999. In the fourth quarter of 2001, the Company received an audit report in which the Audit Bureau noted certain exceptions and proposed adjustments that, if determined to be appropriate, would result in refunds to customers. The Company is discussing the matter with the Pennsylvania Commission and believes that the ultimate resolution of this issue will not have a material impact on its financial position, results of operations or cash flows.

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

Interstate Gas Transmission Operations

FERC Policy Developments

FERC’s most significant near-term policy initiative proposes to eliminate its existing, separate code of conduct regulations for natural gas pipelines and electric transmission utilities, and to replace these requirements with uniform standards applicable to interstate “Transmission Providers” of both natural gas and electricity. The

25

proposed standards would redefine the scope of affiliates covered by standards of conduct for most FERC-regulated companies. If the proposed policy is adopted, it will supersede the existing broad standards and will improve Dominion’s competitive standing among other integrated energy companies.

The Company supports FERC’s policy goal to ensure a competitive interstate energy market. However, the Company advocates certain adjustments to recognize the significant operational differences between gas pipelines and electric transmission companies. The Company anticipates further action by FERC by mid-2002. The Company does not expect the final rule to have a short-term material impact on its results of operations, financial position or cash flows.

Rate Matters—Gas Transmission

The Company implemented various rate filings, tariff changes, and negotiated rate service agreements during 2001. In all material respects, the filings were approved by the FERC in the form requested by the Company and were subject to only minor modifications. The Company has no significant rate matters pending before the FERC at this time.

Environmental Matters

The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. The Company also may seek recovery through regulated rates for environmental expenditures related to regulated gas transmission and distribution operations. See Note 21 to the Consolidated Financial Statements for additional environmental matters.

Environmental Protection and Monitoring Expenditures

The Company incurred approximately $3 million of expenses in both 2001 and 2000, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $4 million in 2002. In addition, capital expenditures related to environmental controls were $3 million and $1 million for 2001 and 2000, respectively. The amount estimated for 2002 for these expenditures is $5 million.

Accounting Matters

Recently Issued Accounting Standards

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, SFAS No. 143, Accounting for Asset Retirement Obligations, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. See Note 4 to the Consolidated Financial Statements for a discussion of the impact of adopting these new standards.

Restructuring Costs

After completing the transition period for fully integrating the Company into Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations in the fourth quarter of 2001. The objective of this review was to identify any activities or resources that were no longer necessary since the end of the transition period. As a result, restructuring charges of $45 million were recognized in the fourth quarter of 2001 for items such as employee severance and other termination benefits and abandonment of leased office space no longer needed. See Note 6 to the Consolidated Financial Statements. The Company’s 2001 and 2000 restructuring plans should reduce future annualized operating costs by approximately $8 million and $62 million, respectively, that would otherwise have been incurred.

26

Exploration and Production Operations

The Company recognized an impairment of its gas and oil producing properties at December 31, 2001, due primarily to the decline in gas wellhead prices. The non-cash charge was $83 million ($53 million after taxes). The effect of the impairment adjustment was offset in its entirety by the reclassification of certain deferred gains from accumulated other comprehensive income to earnings. These deferred gains related to hedging contracts that were not considered in the calculation of the impairment charge.

Business Opportunities and Other Operations

Exploration and Production Operations

The Company continues to focus on increasing earnings from gas and oil properties primarily through acquisition and development activities, exploration, and operating efficiencies. The acquisition of Louis Dreyfus represents the addition of significant, long-lived natural gas reserves located in several onshore United States regions. This addition also provides significant new development drilling opportunities, complementing the Company’s existing development and exploration activities. See Note 5 to the Consolidated Financial Statements.

Additionally, the Company will seek opportunities to enhance the value of its reserves through the optimization of its gas storage facilities. Continued use of new and emerging production, prospecting and drilling technologies, when applied to sound business practices developed over time in gas and oil operations, should help improve operational efficiencies, as well as minimize finding, developing and lifting costs.

Effect of Changes in Commodity Prices

The Company’s operations are impacted by changes in energy commodity prices. To the extent that energy commodities are sold subject to cost-of-service rate regulation, such commodity costs are generally recovered through rates. Market price changes impact the Company’s revenue from natural gas and oil production and from commodity sales through unregulated subsidiaries. The Company has established an enterprise risk management function to reduce such price risk exposures.

Pipeline Operations

The Company plans to expand its natural gas transmission system with a $497 million, 263-mile interstate pipeline. The Greenbrier Pipeline will originate in Kanawha County, West Virginia, and extend through southwest Virginia into Granville County, North Carolina. Piedmont Natural Gas is a 33 percent owner in the pipeline project.

Market Rate Sensitive Instruments and Risk Management

The Company’s financial instruments, derivative financial instruments and derivative commodity instruments are exposed to potential losses due to adverse changes in commodity prices and interest rates 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 due to the exposure to market shifts for prices received and paid for natural gas and oil. The Company uses derivative commodity instruments to manage price risk exposures for these operations.

The Company’s sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10 percent unfavorable change in interest rates and commodity prices.

27

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 non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange.

A hypothetical 10 percent unfavorable change in market prices of the Company’s derivative commodity instruments would have resulted in a decrease in fair value of approximately $15 million and $7 million as of December 31, 2001 and December 31, 2000, respectively.

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

Interest Rate Risk

The Company enters into interest rate sensitive derivatives, including interest rate swap agreements. For financial instruments outstanding at December 31, 2001 and 2000, a hypothetical 10 percent increase in market interest rates would have decreased annual earnings by approximately $2 million for both periods.

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 price risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis.

Management believes, based on Dominion’s credit policies and the Company’s December 31, 2001 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance. See Note 11 to the Consolidated Financial Statements for a discussion of the effects of Enron’s bankruptcy on the Company’s December 31, 2001 consolidated financial statements.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Market Rate Sensitive Instruments and Risk Management under MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS.

28

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX

	Page No.
Report of Management	30
Independent Auditors’ Report	31
Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999	33
Consolidated Balance Sheets at December 31, 2001 and 2000	34
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2001, 2000 and 1999	36
Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999	37
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999	38
Notes to Consolidated Financial Statements	39

29

REPORT OF MANAGEMENT

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

Management maintains a system of internal accounting 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 accounting control and, therefore, cannot provide absolute assurance that the objectives of the established internal accounting 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 2001 the system of internal control was adequate to accomplish the intended objectives.

The Consolidated Financial Statements for the years ended December 31, 2001 and 2000 have been audited by Deloitte & Touche LLP, independent auditors, who were designated by the Board of Directors. The Consolidated Financial Statements for the year ended December 31, 1999 have been audited by PricewaterhouseCoopers LLP, independent accountants. Their audits were conducted in accordance with auditing standards generally accepted in the United States of America and included a review of the Company’s accounting systems, procedures and internal controls, and the performance of tests and other auditing procedures sufficient to provide reasonable assurance that the Consolidated Financial Statements are not materially misleading and do not contain material errors.

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

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 and corporate conduct. This responsibility is characterized and reflected in Dominion’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

/s/    THOMAS N. CHEWNING         Thomas N. Chewning Executive Vice President and Chief Financial Officer /s/    STEVEN A. ROGERS         Steven A. Rogers Vice President and Controller (Principal Accounting Officer)

30

INDEPENDENT AUDITORS’ REPORT

The Board of Directors

Consolidated Natural Gas Company

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, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the two years in the period ended December 31, 2001. 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 the Company at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 11, the Company adopted Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities on January 1, 2001, and as discussed in Note 3, the Company changed its method of accounting used to develop the market related value of pension plan assets in 2000.

/s/    DELOITTE & TOUCHE LLP

Pittsburgh, Pennsylvania

January 22, 2002

31

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholder

of Consolidated Natural Gas Company

In our opinion, the consolidated statements of income, comprehensive income, shareholder’s equity and cash flows for the year ended December 31, 1999 present fairly, in all material respects, the results of operations and cash flows of Consolidated Natural Gas Company and its subsidiaries for the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 14(a)2 on page 76 present fairly, in all material respects, the information set forth therein at December 31, 1999 and for the year ended December 31, 1999 when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/    PRICEWATERHOUSECOOPERS LLP

Pittsburgh, Pennsylvania

January 26, 2000

32

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2001			2000			1999
	(Millions)
Operating Revenue
Regulated gas sales	$	1,409		$	1,719		$	1,397
Nonregulated gas sales		1,055			746			278
Gas transportation and storage		718			551			567
Gas and oil production		706			532			366
Other		349			467			370
Total operating revenue		4,237			4,015			2,978
Operating Expenses
Purchased gas, net		1,917			1,705			912
Liquids, pipeline capacity and other purchases		269			328			280
Restructuring and other merger-related costs		45			270			213
Other operations and maintenance		705			591			679
Depreciation, depletion and amortization		407			442			380
Other taxes		161			200			195
Total operating expenses		3,504			3,536			2,659
Income from operations		733			479			319
Other income (loss):
Gain on sale of subsidiary		—			163			—
Loss on net assets held for sale		—			(152	)		—
Other		27			32			15
Total other income		27			43			15
Interest and related charges		156			162			124
Income before income taxes		604			360			210
Income taxes		199			147			73
Income before cumulative effect of changes in accounting principle		405			213			137
Cumulative effect of changes in accounting principle (net of income taxes of $8 in 2001 and $11 in 2000)		(14	)		31			—
Net Income	$	391		$	244		$	137

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

33

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

	At December 31,
	2001		2000
	(Millions)
A S S E T S
Current Assets
Cash and cash equivalents	$	53	$	58
Accounts receivable:
Customers (less allowance for doubtful accounts of $52 in 2001 and $51 in 2000)		594		976
Other		32		12
Receivables and advances from affiliates		155		18
Inventories:
Materials and supplies (average cost method)		24		21
Gas stored—current portion		122		75
Derivative assets		289		—
Unrecovered gas costs		9		264
Deferred income taxes		107		—
Margin deposit assets		20		284
Prepayments		174		154
Net assets held for sale		76		57
Other		53		140
Total current assets		1,708		2,059
Investments		237		196
Property, Plant and Equipment
Property, plant and equipment		12,608		9,336
Less accumulated depreciation, depletion and amortization		5,169		4,968
Total property, plant and equipment, net		7,439		4,368
Deferred Charges and Other Assets
Goodwill, net		519		—
Regulatory assets, net		267		176
Prepaid pension cost		568		434
Derivative assets		200		—
Other		89		26
Total deferred charges and other assets		1,643		636
Total assets	$	11,027	$	7,259

34

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

	At December 31,
	2001		2000
	(Millions)
L I A B I L I T I E S  A N D  S H A R E H O L D E R ’ S  E Q U I T Y
Current Liabilities
Short-term debt	$	776	$	1,215
Accounts payable, trade		577		688
Estimated rate contingencies and refunds		43		41
Amounts payable to customers		91		—
Payables to affiliates		312		33
Accrued interest		40		26
Accrued payroll		35		52
Accrued taxes		111		178
Derivative liabilities		205		27
Deferred income taxes		—		87
Margin deposit liabilities		88		—
Other		248		209
Total current liabilities		2,526		2,556
Long-Term Debt		3,445		1,721
Deferred Credits and Other Liabilities
Deferred income taxes		1,566		788
Deferred investment tax credits		16		18
Derivative liabilities		132		14
Other		139		196
Total deferred credits and other liabilities		1,853		1,016
Total liabilities		7,824		5,293
Commitments and Contingencies (see Note 21)
Minority Interests		3		—
Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust*		200		—
Common Shareholder’s Equity
Common stock, no par value, 100 shares authorized, 100 shares outstanding		1,816		1,816
Other paid-in capital		936		40
Accumulated other comprehensive income (loss)		82		(1	)
Retained earnings		166		111
Total common shareholder’s equity		3,000		1,966
Total liabilities and shareholder’s equity	$	11,027	$	7,259

* As described in Note 17 to the Consolidated Financial Statements, the 7.8% Junior Subordinated Notes totaling $206 million principal amount constitute 100% of the Trust’s assets.

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

35

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

	Common Stock					Other Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Treasury Stock
	Shares		Amount												Shares		Amount			Total
	(Millions)
Balance at December 31, 1998	96		$	264		$	570		$	(7	)	$	1,599		—	**	$	(26	)	$	2,400
Purchase of treasury stock	—			—			—			—			—		—	**		(13	)		(13	)
Sale of treasury stock	—			—			(5	)		—			—		—	**		38			33
Comprehensive income	—			—			—			3			137		—			—			140
Dividends and other adjustments	—			—			2			—			(186	)	—			—			(184	)
Balance at December 31, 1999	96			264			567			(4	)		1,550		—	**		(1	)		2,376
Merger with Dominion	(96	)		2,163			(526	)		—			(1,637	)	—			—			—
Retirement of treasury stock	—			—			(1	)		—			—		—	**		1			—
Comprehensive income	—			—			—			3			244		—			—			247
Dividends and other adjustments	—			(611	)		—			—			(46	)	—			—			(657	)
Balance at December 31, 2000	—	*		1,816			40			(1	)		111		—			—			1,966
Acquisition of Louis Dreyfus	—			—			894			—			—		—			—			894
Comprehensive income	—			—			—			83			391		—			—			474
Tax benefit of stock option exercise	—			—			2			—			—		—			—			2
Dividends and other adjustments	—			—			—			—			(336	)	—			—			(336	)
Balance at December 31, 2001	—	*	$	1,816		$	936		$	82		$	166		—		$	—		$	3,000

* Following the merger with Dominion, 100 shares of common stock, no par value, were issued and outstanding.

** Share amounts were not material.

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

36

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	Before-Tax Amount			Income Tax (Expense) Benefit			After-Tax Amount
	(Millions)
2001
Net income							$	391
Other comprehensive income:
Net deferred gains on derivatives—hedging activities	$	358		$	(131	)		227
Cumulative effect of a change in accounting principle		(162	)		57			(105	)
Amounts reclassified to net income:
Net gains on derivatives—hedging activities*		(62	)		23			(39	)
Other comprehensive income	$	134		$	(51	)		83
Comprehensive income							$	474
2000
Net income							$	244
Other comprehensive income:
Foreign currency translation adjustments	$	(2	)	$	1			(1	)
Amounts reclassified to net income		6			(2	)		4
Other comprehensive income	$	4		$	(1	)		3
Comprehensive income							$	247
1999
Net income							$	137
Other comprehensive income:
Foreign currency translation adjustments	$	2		$	1			3
Other comprehensive income	$	2		$	1			3
Comprehensive income							$	140

* As described in Note 11 to the Consolidated Financial Statements, $83 million ($53 million after income taxes) of unrealized gains were reclassified to offset an impairment of gas and oil producing properties.

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

37

CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2001			2000			1999
	(Millions)
Cash Flows From (Used In) Operating Activities
Net income	$	391		$	244		$	137
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of changes in accounting principle, net of income taxes		14			(31	)		—
Loss on net assets held for sale		—			152			—
Sale of Virginia Natural Gas		—			(168	)		—
Depreciation, depletion and amortization		407			442			380
Deferred income taxes—net		74			29			47
Changes in current assets and current liabilities:
Accounts receivable		406			(395	)		7
Receivables and advances due from affiliates		(166	)		28			—
Derivative assets and liabilities		(98	)		18			(10	)
Inventories		(43	)		(12	)		20
Unrecovered gas costs		255			(225	)		(3	)
Broker margin deposits		352			(251	)		(20	)
Prepayments		(27	)		(28	)		10
Accounts payable, trade		(213	)		382			(126	)
Payables to affiliates		287			(27	)		—
Amounts payable to customers		62			(1	)		(38	)
Accrued expenses		(55	)		46			16
Other		67			(46	)		(30	)
Other		(189	)		111			(22	)
Net cash from operating activities		1,524			268			368
Cash Flows From (Used In) Investing Activities
Plant construction and other property additions:
Acquisition of exploration and production assets		(741	)		(218	)		(166	)
Other		(415	)		(543	)		(444	)
Proceeds from disposition of property, plant and equipment, net		(19	)		13			7
Proceeds from sale of Virginia Natural Gas		—			532			—
Proceeds from sale of Argentine investments		—			145			—
Acquisition of Louis Dreyfus, net of cash		(902	)		—			—
Other investments		(30	)		(7	)		(42	)
Other		(1	)		(4	)		—
Net cash used in investing activities		(2,108	)		(82	)		(645	)
Cash Flows From (Used In) Financing Activities
Issuance of preferred securities of subsidiary trust		200			—			—
Issuance of long-term debt		1,439			—			397
Repayment of long-term debt		(291	)		(45	)		(125	)
Issuance (repayment) of short-term debt, net		(435	)		527			126
Dividends paid		(336	)		(704	)		(186	)
Other		2			—			21
Net cash from (used in) financing activities		579			(222	)		233
Decrease in cash and cash equivalents		(5	)		(36	)		(44	)
Cash and cash equivalents at beginning of the year		58			94			138
Cash and cash equivalents at end of the year	$	53		$	58		$	94
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (excluding capitalized amounts)	$	137		$	164		$	121
Income taxes	$	139		$	103		$	31
Noncash transactions from investing activities:
Dominion’s contribution of Louis Dreyfus	$	894		$	—		$	—
Transfer of split dollar life insurance to Dominion	$	56		$	—		$	—

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

38

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.    Nature of Operations

On January 28, 2000, Dominion Resources, Inc. (Dominion) completed the acquisition of Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). The Company was merged into a new subsidiary (New Company) of Dominion and Consolidated Natural Gas Company became the name of the New Company. To give effect to the continuity of the Company and New Company, the term “Company” as used throughout this report refers to Consolidated Natural Gas Company either before or after the merger unless the context of a statement requires the use of separate references to each company.

The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces oil and provides a variety of energy marketing services. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline system services each of its distribution subsidiaries, non-affiliated utilities and end-users in the Midwest, Mid-Atlantic states and the Northeast. The Company’s exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore. The Company also provides a variety of energy marketing services and holds an equity investment in energy activities in Australia that is classified as net assets held for sale.

The Company’s retail gas distribution subsidiaries include The East Ohio Gas Company (Dominion East Ohio), The Peoples Natural Gas Company (Dominion Peoples), and Hope Gas, Inc. (Dominion Hope). These subsidiaries sell gas and provide transportation services to residential, commercial and industrial customers in Ohio, Pennsylvania and West Virginia, and are subject to price regulation by their respective state utility commissions.

Dominion Transmission, Inc. (Dominion Transmission) operates a regional interstate pipeline system, regulated by the Federal Energy Regulatory Commission (FERC), that provides gas transportation and storage services to each of the Company’s retail gas distribution subsidiaries, and to nonaffiliated pipeline, utility and end-user customers in the Midwest, the Mid-Atlantic states and the Northeast. Dominion Transmission also holds a 24.72 percent partnership interest in the Iroquois Gas Transmission System, L.P., a limited partnership that owns and operates an interstate natural gas pipeline that transports Canadian gas to utility and power generation customers in New York and New England.

Dominion Exploration & Production, Inc. (Dominion E&P) explores for and produces gas and oil, primarily in the Gulf of Mexico, the Appalachian region, the southern and western United States and in Canada prior to 2001. Effective January 1, 2001, Dominion E&P’s Canadian properties were transferred by sale to another subsidiary of Dominion. CNG Main Pass Gas Gathering Corporation (CNG Main Pass Gas Gathering) and CNG Oil Gathering Corporation (CNG Oil Gathering) hold 13.6 percent and 33.3 percent, respectively, equity investments in gas and oil gathering systems located in the Gulf of Mexico.

Dominion Field Services, Inc. (Dominion Field Services) is engaged in activities related to the Appalachian area natural gas supply and provides natural gas storage facilities, services and other activities of a full-service gas storage business. Dominion Retail, Inc. (Dominion Retail) pursues opportunities arising from the deregulation of the energy industry at the retail level. Dominion Products and Services, Inc. (Dominion Products and Services) provides certain energy-related services to customers of the Company’s retail gas distribution subsidiaries and others.

CNG International Corporation (CNG International) is engaged in energy-related activities outside the United States through equity investments. However, management has committed to a plan of disposal for CNG International. See Note 8 for more information.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At the time of the merger with Dominion in 2000, Dominion created a subsidiary service company, Dominion Resources Services, Inc. (Dominion Services), under the 1935 Act that serves Dominion’s various subsidiaries. The Company also operated a service company, Consolidated Natural Gas Service Company, Inc. (CNG Services), during 2000 and 1999. Effective January 1, 2001, Dominion combined the two service companies and Dominion Services became the surviving service company.

On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. Upon acquisition, Louis Dreyfus was merged with a newly formed wholly-owned subsidiary of Dominion, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. DOTEPI’s results of operations have been included in the consolidated financial statements since that date. The acquisition of DOTEPI doubled the Company’s proven gas and oil reserves.

The Company manages its daily operations along three primary operating segments: Delivery, Energy, and Exploration and Production. The Delivery segment is comprised of the retail gas distribution subsidiaries. The Energy segment is comprised of the pipeline, storage and by-product operations, gas and oil production activities of Dominion Transmission, and the activities of the Company’s gas marketing subsidiaries, Dominion Field Services, Dominion Retail and Dominion Products and Services. The Exploration and Production segment is comprised of the exploration and production operations of Dominion E&P, DOTEPI, CNG Main Pass Gas Gathering and CNG Oil Gathering.

Note 2.    Significant Accounting Policies

General

The Company includes certain estimates and assumptions in preparing consolidated financial statements in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

The consolidated financial statements represent the accounts of the Company and its subsidiaries after the elimination of intercompany transactions. The Company follows the equity method of accounting for investments in partnerships and corporate joint ventures when the Company is able to influence the financial and operating policies of the investee. For all other investments, the cost method is applied.

Certain amounts in the 2000 and 1999 consolidated financial statements have been reclassified to conform to the 2001 presentation.

Use of Fair Value Measurements

The Company reports certain contracts and instruments at fair value in accordance with applicable generally accepted accounting principles. Fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis. For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company uses a modified

40

CONSOLIDATED NATURAL GAS COMPANY

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Black-Scholes model and considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value.

Concentration of Credit Risk

The Company sells natural gas and provides distribution services to residential, commercial and industrial customers and transmission services to utilities and other energy companies. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. In addition, the Company enters into contracts with various companies in the energy industry for sales of its production of natural gas and oil and commodity-based financial contracts used in its hedging activities. Although this concentration could affect the Company’s overall exposure to credit risk, management believes that the Company is exposed to minimal risk. A significant portion of the Company’s hedging activities is conducted with major companies in the energy industry. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Dominion and its subsidiaries, including the Company, maintain credit policies with respect to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements, where deemed necessary, and in the case of hedging activities, the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. Dominion, on behalf of the Company and its subsidiaries, also monitors the financial condition of existing counterparties on an ongoing basis. The Company maintains a provision for credit losses based upon factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on Dominion’s credit policies and the Company’s December 31, 2001 provision for credit losses, that it is unlikely that a material adverse effect on the Company’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The primary types of sales and service activities reported as operating revenue include:

Regulated gas sales consists primarily of state-regulated retail natural gas sales.

Nonregulated gas sales consists primarily of sales of natural gas at market-based rates, brokered gas sales and other gas marketing activities. Natural gas sold includes gas produced by the Company as well as gas purchased from others.

Gas transportation and storage consists primarily of federally regulated sales of transmission, distribution and storage services. Also included are state-regulated gas distribution charges billed to retail customers opting for alternate suppliers.

Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by the Company. Gas and oil production revenue is reported net of royalties.

Other revenue consists primarily of service fees associated with rate-regulated gas distribution; brokered oil and other extracted products; gas and oil processing; capacity release and nonregulated sales of electricity.

41

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Purchased Gas — Deferred Costs

Where permitted by regulatory authorities, the differences between actual purchased gas expenses and the levels of recovery of such expenses in current rates are deferred and matched against recoveries in future rates. See Regulatory Assets and Liabilities discussed below and in Note 13.

Income Taxes

Subsequent to the January 28, 2000 merger with Dominion, the Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. However, under the 1935 Act, the Company’s cash payments to Dominion under the intercompany tax allocation agreement are reduced for any income tax benefits realized by Dominion, the holding company. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits.

Stock-based Compensation

The Company measures compensation cost for common stock awards issued to its employees in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation expense is measured as the difference between the fair market value of Dominion common stock and the exercise price of the underlying award on the date when both the price and number of shares the recipient is entitled to receive are known. This date is generally the date of grant. See Note 19.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2001 and 2000, accounts payable included the net effect of checks outstanding but not yet presented for payment of $36 million and $72 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a maturity of three months or less.

Property, Plant, and Equipment

Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, other direct costs and capitalized interest. The costs of repairs and maintenance, including minor additions and replacements, are charged to expense as incurred. In 2001, 2000, and 1999, the Company capitalized interest costs of $22 million, $10 million, and $9 million, respectively.

The depreciable cost of gas utility and transmission property retired and related cost of removal, less salvage, are charged to accumulated depreciation. The Company records gains and losses upon retirement of nonregulated utility property based upon the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.

Depreciation of property, plant, and equipment is computed on the straight-line method based on projected useful service lives or, in the case of gas and oil producing properties, the unit-of-production method. Estimated

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

useful lives of the Company’s property, plant and equipment are as follows: transmission 20-78 years, distribution 10-50 years, storage 20-78 years, and other 5-31 years.

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. The principal limitation is that these capitalized amounts may not exceed the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves as determined under a method established by the SEC (the ceiling test). If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed quarterly for each cost center.

Depreciation of gas and oil producing properties is computed using the unit-of-production method. Under the full-cost method of accounting, amortization is also accrued on estimated future costs to be incurred in developing proved gas and oil reserves, and on estimated dismantlement and abandonment costs net of projected salvage values. However, the costs of investments in unproved properties are excluded from amortization until it is determined whether proved reserves exist.

Impairment of Long-Lived Assets

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

Derivatives

The Company uses derivatives such as forwards, futures, swaps and options to manage the commodity and financial market risks of its business operations. Effective January 1, 2001, upon adoption of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, derivatives are generally recognized on the Consolidated Balance Sheet at fair value. See Note 11 for further discussion of the Company’s use of derivatives, including its risk management policy, its accounting policy for derivatives under SFAS No. 133 and the results of its hedging activities for the year ended December 31, 2001.

Prior to January 1, 2001, the Company considered derivative instruments to be effective hedges when the item being hedged and the underlying financial or commodity instrument showed strong historical correlation. The Company used deferral accounting to account for futures, forwards and other derivative instruments that were designated as hedges. Under this method, realized gains and losses (including the payment of any premium) related to effective hedges of existing assets and liabilities were recognized in earnings in conjunction with earnings of the designated asset or liability. Gains and losses related to effective hedges of firm commitments and anticipated transactions were included in the measurement of the subsequent transaction.

Goodwill, Net

Goodwill arising from acquisitions completed before July 1, 2001 was amortized on a straight-line basis over periods up to 40 years. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, goodwill is no longer subject to amortization for acquisitions subsequent to June 30, 2001; instead, it will be subject to new impairment testing criteria. See Note 4 for further discussion of the adoption of SFAS 142 effective January 1, 2002. See Note 5 for a discussion of the acquisition completed by the Company in 2001.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Regulatory Assets and Liabilities

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. The economic effects of allocations prescribed by regulatory authorities for ratemaking purposes must be considered in the application of generally accepted accounting principles. See Note 13 for additional information on regulatory assets and liabilities.

Amortization of Debt Issuance Costs

The Company defers and amortizes debt issuance costs and debt premiums or discounts over the lives of the respective debt issues. As permitted by regulatory commissions, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based regulation have also been deferred and amortized over the lives of the new issues.

Note 3.    Accounting Change for Pension Costs

Effective January 1, 2000 and in connection with Dominion’s acquisition of the Company, Dominion and its subsidiaries, including the Company, adopted a new company-wide method of calculating the market-related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. The Company believes the new method enhances the predictability of expected returns on pension plan assets, provides consistent treatment of all investment gains and losses, and results in calculated market-related pension plan asset values that are closer to market value than the values calculated under the pre-acquisition methods used by Dominion and the Company.

The $31 million cumulative effect of the change on prior years (net of income taxes of $11 million) was included in income for the year ended December 31, 2000. The effect of the change on 2000 was to increase income before cumulative effect of a change in accounting principle by $10 million and net income by $42 million.

Had the Company retroactively applied the new method, on a pro forma basis, net income for the year ended December 31, 1999 would have been $144 million, as compared to reported net income of $137 million.

Note 4.    Recently Issued Accounting Standards

Business Combinations and Goodwill

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS Nos. 141, Business Combinations, and 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 141 also includes guidance on the initial recognition and measurement of goodwill and other intangible assets arising from business combinations initiated after June 30, 2001. SFAS No. 142 prohibits the amortization of goodwill and intangible assets with indefinite useful lives. SFAS No. 142 requires that these assets be reviewed for impairment at least annually. Intangible assets with finite lives will continue to be amortized over their estimated useful lives.

The Company will adopt SFAS No. 142 effective January 1, 2002. The Company will test goodwill for impairment using the two-step process described in SFAS No. 142. The first step is a screen for potential impairment, while the second step measures the amount of the impairment, if any. The Company will perform the first step of the required impairment tests of goodwill as of January 1, 2002, before the end of the second quarter of 2002. The standard requires that if impairment were determined to exist under that test, it would be reflected as the cumulative effect of a change in accounting principle. The Company has not yet determined the effect these tests may have on its earnings or financial position.

44

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Asset Retirement Obligations

In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. The Company will adopt this standard effective January 1, 2003.

The Company has identified retirement obligations associated with certain dismantlement and restoration activities for its gas and oil exploration and development wells. However, the Company has not yet performed a complete assessment of possible retirement obligations associated with its gas utility property. The Company has not yet determined the financial impact of adopting the new standard.

Upon adoption of the new standard, the Company will discontinue its practice of accruing, as part of depreciation expense, amounts associated with the future costs of removal for its gas utility and gas and oil exploration and production assets. However, the Company may continue its practice of accruing for such costs subject to cost-of-service utility rate regulation when an asset removal obligation does not exist, but would do so through the recognition of regulatory assets and liabilities, as appropriate.

Impairment or Disposal of Long-Lived Assets

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. The Company will apply the provisions of this standard prospectively beginning January 1, 2002, and does not expect the adoption to have a material impact on its results of operations or financial condition.

Note 5.    Merger and Acquisition

Merger with Dominion

On January 28, 2000, Dominion acquired all of the outstanding shares of the Company’s common stock for $6.4 billion, consisting of approximately 87 million shares of Dominion common stock valued at $3.5 billion and approximately $2.9 billion in cash. Dominion completed the acquisition by merging the Company into a new subsidiary. Dominion changed the name of the new subsidiary to Consolidated Natural Gas Company at the time of the merger.

Acquisition of Louis Dreyfus

On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus, a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. Upon acquisition, Louis Dreyfus was merged with a newly formed wholly-owned subsidiary of Dominion, DOTEPI. Immediately after the merger, Dominion contributed DOTEPI to the Company. DOTEPI’s results of operations have been included in the consolidated financial statements since that date. The acquisition of Louis Dreyfus doubled the Company’s proven gas and oil reserves.

Goodwill was recognized in the acquisition to reflect the value attributable to: the complementary nature of the Louis Dreyfus assets in relation to Dominion’s growth strategy for its integrated energy businesses; Louis Dreyfus’ experienced exploration and production technical personnel; and potential operational efficiencies from the consolidation of Louis Dreyfus’ operations with the Company’s existing exploration and production operations. By providing Dominion and the Company with a presence in additional large natural gas basins and

45

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

increasing holdings in certain basins in which Dominion and the Company already operate, management believes that the acquisition results in a more balanced portfolio of producing properties, a more stable production profile and a larger platform for future growth. All goodwill recognized in the transaction was pushed down to the Company. The Company has not yet completed the assignment of goodwill associated with the Louis Dreyfus acquisition to its operating segments.

The aggregate purchase price was $1.8 billion, which consisted of approximately 14 million shares of Dominion common stock valued at $881 million and $902 million in cash. The value of the common stock issued was determined based on the average market price of common shares over the two-day period before and after the terms of the acquisition were agreed to and announced. In addition, Dominion issued approximately 675,000 stock options to the employees of Louis Dreyfus in exchange for outstanding Louis Dreyfus options with a fair value on the date of grant of approximately $13 million.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

	At November 1, 2001
	(millions)
Assets:
Current assets	$	89
Property, plant and equipment		2,387
Deferred charges and other assets		43
Goodwill		519
Total assets		3,038
Liabilities:
Current liabilities		167
Long-term debt*		1,426
Deferred credits and other liabilities		551
Total liabilities assumed		2,144
Net assets acquired	$	894

* Long-term debt includes approximately $1.1 billion of debt issued by the Company and preferred securities issued through an affiliated trust to finance the cash portion of the acquisition and refinance $185 million of Louis Dreyfus debt.

The Company is in the process of evaluating and measuring certain liabilities assumed in the acquisition; thus, the allocation of the purchase price is subject to refinement. Potential adjustments are not expected to be material. In accordance with SFAS No. 142, no goodwill amortization was recorded during 2001. See Note 4 for further discussion.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Unaudited Pro forma Results

The following unaudited pro forma combined results of operations for the years ended December 31, 2001 and 2000 have been prepared assuming that the acquisition of Louis Dreyfus had occurred at the beginning of each period. The pro forma results are provided for information only. The results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the indicated date, nor are they necessarily indicative of future results of operations of the combined businesses.

	Year Ended December 31,
	2001				2000
	As Reported		Pro Forma		As Reported		Pro Forma
	(Millions)
Operating revenue	$	4,237	$	4,791	$	4,015	$	4,489
Income before cumulative effect of changes in accounting principle		405		563		213		291
Net income		391		549		244		322

Note 6.    Restructuring and Other Merger-Related Activities

2001 Restructuring Costs

In the fourth quarter of 2001, after completing the transition period for fully integrating the Company into Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations. The objective of this review was to identify any activities or resources which were no longer necessary when the transition period had ended. As a result, the Company recognized $45 million of restructuring costs which included employee severance and related benefits, and the abandonment of leased office space no longer needed.

The Company recorded $34 million in total severance and related costs, including $21 million billed to the Company by Dominion Services. Under the restructuring plan, the Company identified approximately 141 salaried positions to be eliminated and recorded $13 million in employee severance-related costs. Employee terminations are expected to begin early in the first quarter of 2002. Severance payments were based on the individual’s base salary and years of service at the time of termination.

Restructuring and related costs for the year ended December 31, 2001 were as follows:

	2001
	(Millions)
Severance and related costs	$	13
Severance and related costs—Dominion Services(1)		21
Other, net(2)		11
Total restructuring costs	$	45
Severance liability at December 31, 2001	$	13
Lease abandonment liability at December 31, 2001	$	7

⁽¹⁾ Dominion Services, a Dominion subsidiary service company under the 1935 Act, provides certain services to Dominion’s operating subsidiaries. Accordingly, charges are allocated and billed among the operating subsidiaries in accordance with predefined service agreements. See Note 23.

⁽²⁾ Includes charges for abandonment of leased office space and related costs by the Company and Dominion Services.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2000 Restructuring and Other Merger-Related Costs

In 2000, following the merger with Dominion, Dominion and its subsidiaries implemented a plan to restructure the operations of the combined companies. The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP) and a transition plan to implement operational changes to provide efficiencies, including the consolidation of post-merger operations and the integration of information technology systems. Through December 31, 2001, 429 positions had been eliminated, and approximately $26 million of severance benefits had been paid. During 2000, approximately 450 employees elected to participate in the ERP, resulting in an expense approximating $62 million. This expense was offset, in part, by curtailment gains of $26 million attributable to reductions in expected future years of service as a result of ERP participation and involuntary employee terminations. Some of the ERP participants also received benefits under the involuntary severance package; benefits under the involuntary severance package were subject to reduction as a result of coordination with the additional retirement plan benefits provided by the ERP.

For the year ended December 31, 2000, the Company recorded $270 million of restructuring and other merger-related costs, as follows:

	2000
	(Millions)
Commodity contract losses	$	55
Settlement of certain employment contracts		47
ERP (see Note 20)		36
Information technology-related costs		35
Severance liability accrued		31
Seismic licensing agreements		26
Transaction fees		10
Lease termination or modification		8
Other		22
Total	$	270

The change in the liability for severance and related benefit costs during 2001 is presented below:

	(Millions)
Balance at December 31, 2000	$	13
Amounts paid		(8	)
Revision of estimates(1)		(2	)
Transfer due to merger of service companies*		(2	)
Balance at December 31, 2001	$	1

⁽¹⁾ Reflects a revision in severance benefits payable for differences between the estimates used in the plan and the actual base salaries and years of service for those employees terminated under the plan. Severance benefits were based on the individual’s base salary and years of service at the time of termination.

* CNG Services merged into Dominion Services (see Note 1).

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During the first quarter of 2000, Dominion created an enterprise risk management group with the responsibility of managing Dominion’s aggregate energy portfolio, including the related commodity price risk, across its consolidated operations. In connection with this change in risk management strategy, management evaluated the Company’s hedging strategy in relation to Dominion’s combined operations and designated its January 28, 2000 portfolio of derivative contracts as held for purposes other than hedging for accounting purposes. This action required a change to mark-to-market accounting, and resulted in $55 million of losses that were recognized in the first quarter of 2000. See Note 11.

In addition, the Company incurred costs including settlement of certain employment contracts, payments under seismic licensing agreements in gas and oil operations, information technology-related costs including excess amortization expense attributable to shortening the useful lives of capitalized software impacted by systems integration and related conversion costs, and lease termination and restructuring costs as a result of the consolidation of operations.

Sale of Virginia Natural Gas (VNG)

In October 2000, the Company completed the sale of VNG to AGL Resources Inc. (AGL). Cash proceeds from the sale amounted to $532 million. The Company was required to spin-off or sell VNG pursuant to conditions set forth by the Virginia State Corporation Commission and the Federal Trade Commission in connection with their approvals of the acquisition of the Company by Dominion.

In connection with the sale of VNG, the Company transferred the pension and postretirement medical benefit liabilities relating to VNG’s employees to AGL, together with the related plan assets. As a result, the Company recognized curtailment and settlement gains of $26 million. The total gain recognized on the sale of VNG, including the curtailment and settlement gains, amounted to $163 million ($98 million after taxes).

1999 Restructuring and Other Merger-Related Costs

Shareholder approval of the merger with Dominion constituted a change of control, as defined in the Company’s then-effective stock incentive plans. The change of control triggered acceleration of the vesting of stock options and certain other stock awards. Also, the change of control effectively granted limited stock appreciation rights to holders of vested stock options and certain other stock awards. Holders were permitted to elect to receive a cash payment in exchange for surrendering vested stock options and awards during 1999. The amount to be paid to the holders was based on the value determined per the associated plans, which considered the option exercise price, award value, and the change of control price as defined in the plans. Based on the value of the vested options and awards expected to be surrendered and cashed out, the Company recognized a charge of $154 million during the second quarter of 1999.

During 1999, the Company also recorded charges for the costs related to certain executive employment agreements and for other merger-related costs, including direct incremental costs (including fees of financial advisors, legal counsel and other costs).

For the year ended December 31, 1999, the Company recorded $213 million of restructuring and other merger-related costs.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 7.    Workforce Reduction Costs

During 1998, the Company recorded a provision for severance and other employee-related costs in connection with programs to improve efficiencies and reorganize business processes of its corporate and regulated subsidiaries. Certain severance benefits were enhanced under these programs which were completed during 1999. As a result, a total of 241 employees were separated from the Company in conjunction with these workforce reduction programs, resulting in a charge of $11 million ($7 million after taxes) in 1999. In addition, certain of the regulated subsidiaries have deferred these costs as a regulatory asset, see Note 13.

Note 8.    Impairment of International Investments

CNG International was engaged in energy-related activities outside of the United States, primarily through equity investments in companies located in Australia and Argentina. Consistent with its strategy to focus on its core business, in the first quarter of 2000, management committed to a plan to dispose the entire operations of CNG International. At December 31, 2001 and 2000, the Company recorded $76 million and $57 million, respectively, as net assets held for sale. The total loss related to CNG International, discussed below, was $152 million ($99 million after taxes) for the year ended December 31, 2000.

Argentine Investments

In July 2000, the Company sold CNG International’s Argentine assets for $145 million. Based upon anticipated proceeds from the sale, the carrying amount of these investments was adjusted, resulting in an impairment loss of $17 million ($11 million after taxes) in the second quarter of 2000. In October 2000, CNG International completed the sale of its Argentine assets for $145 million in cash.

Australian Investments

In March 1998, CNG International purchased a 33.3 percent ownership interest in the Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the Western Australian Government. One of CNG International’s partners in the purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3 percent ownership interest. In connection with their investments in DBNGP, CNG International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance). DBNGP Finance is owned 50 percent by CNG International and 50 percent by EPED Holding Company, a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP Finance, the equity ownership interests of CNG International and El Paso in DBNGP were transferred to DBNGP Finance.

In October 1998, DBNGP Finance borrowed $250 million at variable rates under a Senior Term Loan Facility (Term Loan). In 2001, under provisions of the Term Loan, its maturity date was extended to October 2003. CNG International entered into an equity contribution agreement with DBNGP Finance and was contractually obligated to make equity contributions equivalent to the $100 million received from the Term Loan proceeds, in the event that DBNGP Finance was unable to service the Term Loan.

In 2000, in connection with the Company’s decision to end its involvement with international activities, the Company recognized a loss of $35 million ($23 million after taxes) to write down the carrying amount of CNG International’s Australian investments to estimated fair value less cost to sell. In addition, the Company recognized a charge of $100 million ($65 million after taxes) for the equity contribution expected to be made pursuant to the agreement discussed above.

50

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 9.    Income Taxes

Details of income tax expense were as follows:

	Year Ended December 31,
	2001			2000			1999
	(Millions)
Current:
Federal	$	105		$	108		$	23
State		22			12			5
Total current		127			120			28
Deferred:
Federal		74			22			44
State		—			7			3
Total deferred		74			29			47
Amortization of deferred investment tax credits—net		(2	)		(2	)		(2	)
Total income tax expense	$	199		$	147		$	73

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

	Year Ended December 31,
	2001		2000		1999
U.S statutory rate	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
Amortization of investment tax credits	(0.3	)	(0.5	)	(1.1	)
Nonconventional fuel credit	(2.1	)	(2.8	)	(5.2	)
State taxes, net of federal benefit	2.5		3.3		2.7
SFAS No. 71 flow through item: employee pension and other benefits	(2.0	)	(2.2	)	(2.8	)
SFAS No. 71 flow through item: gain on sale of assets	—		1.9		—
Nondeductible change of control payments	—		2.2		2.1
CNG International equity earnings	—		—		1.8
Prior year tax adjustment	—		2.5		1.5
Other, net	(0.2	)	1.4		1.0
	(2.1	)	5.8		—
Effective tax rate	32.9	%	40.8	%	35.0	%

51

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company’s net accumulated deferred income taxes consist of the following:

	At December 31,
	2001					2000
	Deferred Income Taxes		Deferred Income Taxes - Current			Deferred Income Taxes		Deferred Income Taxes - Current
	(Millions)
Deferred income tax assets:
Gas storage inventory encroachment and other	$	—	$	38		$	86	$	—
Partnership basis differences		—		17			29		—
Uncollectible accounts		—		13			23		—
Deferred investment tax credits		—		8			10		—
Excise tax		—		—			8		—
Other		—		31			36		—
Total deferred income tax assets		—		107			192		—
Deferred income tax liabilities:
Depreciation method and plant basis differences		446		—			423		—
Exploration and intangible drilling costs		469		—			237		—
Geological, geophysical and other exploration differences		255		—			164		—
Postretirement and pension benefits		191		—			155		—
Unrecovered gas costs and supplier refunds		119		—			—		86
Other comprehensive income		81		—			—		—
Other		5		—			1		1
Total deferred income tax liabilities		1,566		—			980		87
Total net deferred income tax (assets) liabilities	$	1,566	$	(107	)	$	788	$	87

At December 31, 2001, the Company had U.S. federal net operating loss carryforwards of $79 million that will expire beginning in 2003. These amounts resulted from the acquisition of subsidiaries.

Note 10.    Gas Stored

At December 31, 2001 and 2000, stored gas inventory used in local gas distribution operations was valued at $84 million and $41 million, respectively, under the LIFO method. Based upon the average price of gas purchased during 2001, the current cost of replacing the inventory of gas stored—current portion exceeded the amount stated on a LIFO basis by approximately $308 million. At December 31, 2001 and 2000, the stored gas inventory of certain nonregulated gas operations of the Company was valued at $38 million and $34 million, respectively, using the weighted-average-cost method.

A portion of gas in underground storage used as a pressure base and for operational balancing was included in property, plant and equipment in the amount of $124 million and $126 million at December 31, 2001 and 2000, respectively. Property, plant and equipment also reflects a reduction for volumes temporarily withdrawn from storage and valued at replacement costs of $ 25 million and $ 211 million as of December 31, 2001 and 2000, respectively.

Note 11.    Derivatives and Hedge Accounting

Adoption of SFAS No. 133

The Company adopted SFAS No. 133 on January 1, 2001 and recorded an after-tax loss of $14 million (net of income taxes of $8 million), representing the cumulative effect of adopting SFAS No. 133 in its Consolidated

52

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Statements of Income. The Company also recorded a net after-tax charge to accumulated other comprehensive income (AOCI) of $105 million, net of taxes of $57 million. The Company reclassified approximately $117 million, net of taxes, of AOCI associated with the January 1, 2001 transition adjustment to earnings during 2001. The effect of the amounts reclassified from AOCI to earnings were generally offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Risk Management Policy

The Company uses derivatives to manage the commodity and financial market risks of its business operations. The Company manages the price risk associated with purchases and sales of natural gas and oil by utilizing derivative commodity instruments including futures, forwards, swaps and options. The Company manages its interest rate risk exposure, in part, by entering into interest rate swap transactions.

The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained regarding the use of derivatives. In addition, Dominion has established an independent function to monitor compliance with the price risk management policies of all subsidiaries.

The Company designates a substantial portion of its derivatives as fair value or cash flow hedges. A significant portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with purchases and sales of natural gas, oil and other commodities, using derivative instruments discussed in the preceding paragraphs. The Company also engages in fair value hedges by utilizing natural gas swaps, futures and options to mitigate the fixed-price exposure inherent in its firm commodity commitments. In addition, the Company has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt. Certain of the Company’s derivatives are not designated as hedges for accounting purposes. However, management believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices.

Accounting Policy

Under SFAS No. 133, derivatives are recognized on the Consolidated Balance Sheets at fair value, unless an exception is available under the standard. Commodity contracts representing unrealized gain positions are reported as derivative assets; commodity contracts representing unrealized losses are reported as derivative liabilities. In addition, purchased options and options sold are reported as derivative assets and derivative liabilities, respectively, at estimated market value until exercise or expiration.

For all derivatives designated as hedges, the Company formally documents the relationship between the hedging instrument and the hedged item, as well as the risk management objective and strategy for the use of the hedging instrument. The Company assesses whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value of the hedged item is recognized currently in earnings. Further, for derivatives that have ceased to be highly effective hedges, the Company discontinues hedge accounting prospectively.

For fair value hedge transactions in which the Company is hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative will generally be offset in the Consolidated Statements of Income by changes in the hedged item’s fair value. For cash flow hedge transactions

53

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

in which the Company is hedging the variability of cash flows related to a variable-priced asset, liability, commitment, or forecasted transaction, changes in the fair value of the derivative are reported in AOCI. Derivative gains and losses reported in AOCI are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of the change in fair value of derivatives and the change in fair value of derivatives not designated as hedges for accounting purposes are recognized in current-period earnings. For options designated either as fair value or cash flow hedges, changes in the time value are excluded from the measurement of hedge effectiveness and are, therefore, recorded in earnings.

Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in the Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. Changes in the fair value of derivatives not designated as hedges, and the portion of hedging derivatives excluded from the measurement of effectiveness are included in other operation and maintenance expense in the Consolidated Statements of Income. Cash flows resulting from the settlement of derivatives used as hedging instruments are included in net cash from operating activities in the Consolidated Statements of Cash Flows.

2001 Derivatives and Hedge Accounting Results

The Company recognized a pre-tax gain of approximately $1 million for fair value hedge ineffectiveness during 2001. In addition, the Company recognized a net pre-tax loss of approximately $35 million during 2001, representing the change in time value excluded from the measurement of effectiveness for options designated as cash flow hedges subsequent to January 1, 2001.

Approximately $47 million of net gains in AOCI at December 31, 2001 is expected to be reclassified to earnings during 2002. The actual amounts that will be reclassified to earnings in 2002 will vary from this amount as a result of changes in market prices. The effect of the amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies. As of December 31, 2001, the Company is hedging its exposure to the variability in future cash flows for forecasted transactions over periods of one to seven years.

In addition, $83 million of unrealized gains related to certain contracts designated as hedging instruments were reclassified from accumulated other comprehensive income to earnings in December 2001. This reclassification was required in relation to the Company’s recognition of an impairment of its gas and oil producing properties at December 31, 2001, due primarily to the decline in gas wellhead prices. See Note 12 for further discussion.

Enron Bankruptcy

On December 2, 2001, Enron Corp. and certain of its subsidiaries (collectively referred to as Enron) voluntarily filed for reorganization under Chapter 11 of the United States Bankruptcy Code. The Company is a party to various contracts with Enron that were initiated principally for purposes of hedging anticipated sales of natural gas. As a result of Enron’s bankruptcy filing, the Company reexamined the estimated collectibility of its net accounts receivable balance from Enron and the valuation of its Enron commodity contracts carried at fair value on the Company’s Consolidated Balance Sheet at December 2, 2001. In reexamining the valuation of these assets, the Company considered, among other factors, Dominion’s contractual ability to exercise the right of setoff, the likelihood of continued performance by Enron under its contracts and its expectation regarding amounts to be realized upon potential future termination of its contracts by Dominion.

54

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Based on management’s evaluation of these factors, the Company recorded a pre-tax charge to earnings of approximately $108 million in the fourth quarter of 2001 related to its estimated Enron exposure. This charge primarily represents the impaired fair value of natural gas forward and swap contracts with Enron. Management believes that this charge substantially eliminates any further Enron-related earnings exposure. However, various contingencies, including developments in the Enron bankruptcy proceedings, may affect the Company’s ultimate exposure to Enron.

Concurrent with the December 2, 2001 Enron bankruptcy filing, the Company’s Enron derivatives designated as cash flow hedges of anticipated sales of natural gas no longer qualified for hedge accounting and, accordingly, were de-designated from their hedging relationships for accounting purposes.

Other

Future interpretations of SFAS No. 133 by the FASB or other standard-setting bodies could result in fair value accounting being required for certain contracts that are not currently being subjected to such requirements. Accordingly, such future interpretations may impact the Company’s ultimate application of the standard. However, if future SFAS No. 133 interpretive guidance results in additional contracts becoming subject to fair value accounting, the Company would pursue hedging strategies to mitigate any potential future volatility in reported earnings.

Note 12.    Property, Plant and Equipment

Property, plant and equipment consists of the following:

	At December 31,
	2001		2000
	(Millions)
Utility:
Transmission	$	1,600	$	1,528
Distribution		1,736		1,694
Storage		755		573
Other		674		630
Plant under construction		47		41
Total utility		4,812		4,466
Nonutility:
Exploration and production:
Proved		6,022		3,909
Unproved		1,614		705
Other		160		256
Total nonutility		7,796		4,870
Total property, plant and equipment	$	12,608	$	9,336

Amortization of capitalized costs under the full-cost method of accounting for the Company’s United States and Canadian gas and oil exploration and production activities were as follows:

	Year Ended December 31,
	2001		2000		1999
	(Per Mcf Equivalent)
United States cost center	$	1.24	$	1.31	$	1.14
Canadian cost center	$	—	$	.17	$	.12

55

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Costs of unproved properties capitalized under the full-cost method of accounting that were excluded from amortization at December 31, 2001, and the years in which the excluded costs were incurred, follow:

	At December 31, 2001		Incurred in Years Ended December 31,
			2001		2000		1999		Prior
	(Millions)
Property acquisition costs	$	953	$	899	$	29	$	14	$	11
Exploration costs		187		120		46		11		10
Capitalized interest		34		26		2		2		4
Total	$	1,174	$	1,045	$	77	$	27	$	25

As described in Note 2, the Company follows the full-cost method of accounting for gas and oil producing activities as prescribed by the SEC. Under these rules, the Company recognized an impairment of its gas and oil producing properties at December 31, 2001, due primarily to the decline in gas wellhead prices. The non-cash charge amounted to $83 million and reduced 2001 net income by $53 million. The effect of the impairment adjustment was offset in its entirety by the reclassification of certain deferred gains from AOCI to earnings. These deferred gains related to hedging contracts that were not considered in the calculation of the impairment charge.

There were no significant properties, as defined by the SEC, excluded from amortization at December 31, 2001. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Note 13.    Regulatory Assets and Liabilities

The Company accounts for its regulated operations in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. See Note 2. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company’s regulatory assets and liabilities included the following:

	At December 31,
	2001		2000
	(Millions)
Regulatory assets:
Unrecovered gas costs	$	9	$	264
Workforce reduction costs		7		8
Other postretirement benefits		38		40
Income taxes recoverable through future rates		129		110
Customer bad debts		80		—
Other		13		18
Regulatory assets, net		267		176
Total regulatory assets	$	276	$	440
Regulatory liabilities:
Amounts payable to customers	$	91	$	—
Estimated rate contingencies and refunds		43		41
Total regulatory liabilities	$	134	$	41

56

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The incurred costs underlying regulatory assets may represent past expenditures by the Company’s rate regulated gas operations or may represent the recognition of liabilities that ultimately will be settled at some time in the future. At December 31, 2001, approximately $100 million of the Company’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of unrecovered gas costs and customer bad debts. Unrecovered gas costs are recovered within two years. Recovery of these customer bad debts is expected to be addressed in the next base rate case.

Where permitted by regulatory authorities, the differences between actual purchased gas expenses and the levels of recovery of such expenses in current rates are deferred and matched against recoveries in future rates.

Certain of the regulated subsidiaries have deferred costs associated with workforce reduction programs. See Note 7 for additional information.

Pending the expected recovery costs of SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, the Company’s rate-regulated subsidiaries deferred the differences between SFAS No. 106 costs and amounts included in rates. The rate-regulated subsidiaries have obtained approval for recovery in rates from their respective regulatory commissions for the increased level of expense resulting from SFAS No. 106.

Income taxes recoverable or refundable through future rates resulted from the recognition of additional deferred income taxes not previously recorded because of past ratemaking practices.

In 2001, the Public Utilities Commission of Ohio (Ohio Commission) authorized the deferral of costs associated with certain uncollectible customer accounts not contemplated by current rates. In many cases, these customers’ balances were adversely impacted by last winter’s unusually high gas prices and cold weather. The Company expects recovery of such costs, which will be included in Dominion East Ohio’s next base rate case.

Estimated Rate Contingencies and Refunds include certain increases in prices by the Company and other ratemaking issues that are subject to modification in the final disposition of regulatory proceedings. The related accumulated provisions, including interest, pertaining to these matters were $24 million and $40 million at December 31, 2001 and 2000, respectively. These provisions also reflected amounts refundable to customers of $16 million at December 31, 2001. Refunds received from suppliers under regulatory procedures amounted to $3 million and $1 million at December 31, 2001 and 2000, respectively.

Note 14.    Short-Term Debt and Credit Agreements

The Company has a commercial paper program backed by a credit facility that supports the combined commercial paper programs of Dominion, Virginia Electric and Power Company (Virginia Power), another subsidiary of Dominion, and the Company. This credit facility, established in May 2001, is for $1.75 billion and matures in the second quarter of 2002. The Company has full access to this credit facility; however, the internal allocation may vary depending upon the needs of the participating entities. The Company expects to renew this credit facility after its maturity.

The Company’s borrowings under the commercial paper program were $776 million and $1.2 billion at December 31, 2001 and 2000, with a weighted average interest rate of 4.22 percent and 7.05 percent, respectively.

57

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 15.    Long-Term Debt

	At December 31,
	2001		2000
	(Millions)
Senior Subordinated Debt:
9.25%, due 2004	$	94	$	—
Senior Notes:
5.375% to 7.375%, due 2003 to 2011		2,350		700
8.75%, due 2019(1)		—		84
6.875%, due 2026(2)		150		150
6.0% to 6.8%, due 2008 to 2027		800		800
		3,394		1,734
Fair value hedge valuation(3)		38		—
Unamortized discount and premium, net		13		(13	)
Total long-term debt	$	3,445	$	1,721

⁽¹⁾ The Company redeemed the remaining $84 million Senior Notes in the first quarter of 2001.

⁽²⁾ At the exercised option of holders, the Company will be required on October 15, 2006 to purchase the Senior Notes due October 15, 2026 at 100% of the principal amount plus accrued interest.

⁽³⁾ Represents changes in fair value of certain fixed-rate long-term debt associated with fair value hedging relationships, as described in Note 11.

The scheduled principal payments of long-term debt at December 31, 2001 were as follows (in millions):

2002	2003	2004	2005	2006	Thereafter	Total
$ —	$150	$494	$150	$500	$2,100	$3,394

Note 16.    Dividend Restrictions

At December 31, 2000, one of the Company’s indentures relating to its long-term debt contained restrictions on dividend payments by the Company. As of that date, $19 million of the Company’s consolidated retained earnings was free from such restrictions. In March 2001, the Company requested and obtained the consent of bondholders to amend the indenture to eliminate certain provisions of the indenture, including such dividend restrictions. In March 2001, the Company received an order from the SEC, approving the amendment of the indenture.

The 1935 Act prohibits registered holding companies and their subsidiaries from paying dividends out of capital or unearned surplus except when they have received specific SEC authorization. In 2000, the Company requested and obtained approval from the SEC to pay dividends to Dominion from its capital stock account for amounts up to the Company’s earned surplus that existed at the date the Company was acquired by Dominion. In January 2002, the Company filed an application with the SEC for relief from the restriction on paying dividends out of unearned surplus of DOTEPI, the subsidiary into which Louis Dreyfus was merged. The request was for relief up to an amount equal to Louis Dreyfus’ retained earnings before the merger.

Note 17.    Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust

In 2001, the Company established Dominion CNG Capital Trust I (CNG Capital Trust). In this transaction, CNG Capital Trust sold 8 million trust preferred securities for $200 million, representing preferred beneficial interests and a 97 percent beneficial ownership in the assets held by CNG Capital Trust.

58

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In exchange for the $200 million realized from the sale of the trust preferred securities and $6 million of common securities that represent the remaining 3 percent beneficial ownership interest in the assets held by CNG Capital Trust, the Company issued $206 million of its 2001 7.8 percent Junior Subordinated Notes (Junior Subordinated Notes) due October 31, 2041. The Junior Subordinated Notes constitute 100 percent of CNG Capital Trust’s assets.

Note 18.    Common Stock

Common Stock

Following the acquisition of the Company by Dominion on January 28, 2000, 100 shares of common stock, no par value, were issued and outstanding.

Treasury Stock

Prior to the acquisition by Dominion, the Company was authorized by the Board of Directors to purchase in the open market up to 10,000,000 shares of its common stock. The Company could also acquire shares of its common stock through certain provisions of the Company’s various stock incentive plans. Shares repurchased or acquired were held as treasury stock and were available for reissuance for general corporate purposes or in connection with various employee benefit plans. When treasury shares were reissued, the difference between the market value at reissuance and the cost of shares was reflected in other paid-in capital. At December 31, 1999, 10,443 shares were being held as treasury stock. Immediately prior to the merger with Dominion, all treasury stock held by the Company was retired.

Note 19.    Long-Term Incentives

Employees of the Company may receive stock-based awards, such as stock options and restricted stock, granted under Dominion-sponsored stock plans. Compensation expense associated with these awards was not material in 2001 and 2000. The pro forma impact on net income, had the Company measured compensation expense based on the fair value of the options on the date of grant, would not have been material for 2001 and 2000.

Prior to its acquisition by Dominion, the Company sponsored a stock plan and long-term incentive program under which it granted performance-based stock options and awards to its employees and directors. The Company granted stock awards, including performance shares, totaling 459,000 shares in 1999 with weighted average market prices per share on award dates of $53.91. The Company recorded compensation expense of $159 million for the year ended December 31, 1999, in connection with its performance shares, restricted stock and other stock compensation awards, and stock options that were surrendered and cashed out in connection with shareholder approval of the Company’s then-pending merger with Dominion. See Note 5.

59

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of activity related to stock options granted prior to the merger with Dominion follows:

	Number of Shares		Weighted Average Option Price Per Share
	(Thousands)
Balance at January 1, 1999	5,505		$	47.73
Granted(1)	3,800		$	53.79
Exercised	(700	)	$	46.55
Cancelled(1)	(2,266	)	$	53.51
Surrendered	(6,337	)	$	49.44
Balance at December 31, 1999	2		$	55.47
Surrendered	(2	)	$	55.47
Balance at December 31, 2000	—

⁽¹⁾ Includes 3,002,917 tri-annual options granted and 1,968,211 tri-annual options cancelled.

Note 20.    Employee Benefits Plans

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

The Company maintains qualified noncontributory defined benefit retirement plans covering substantially all employees. Retirement benefits payable under the plans are based primarily on years of service, age and compensation. The Company’s funding policy is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The pension program also includes nonqualified pension plans which provide payment of supplemental pension benefits to certain retirees. Beginning in 2001, participants of certain of the non-qualified pension plans became employees of Dominion Services. As a result of this change, all associated plan liabilities were transferred to Dominion, and the Company reported no net periodic benefit costs related to affected participants under these plans in 2001. However, to the extent such employees provided services to the Company during 2001, the Company has recognized such costs as part of the support services provided by Dominion Services.

Effective January 1, 2001, CNG Services was merged into Dominion Services. Employees of CNG Services became employees of Dominion Services but continued to participate in the Company’s pension and other postretirement benefit plans. See Notes 1 and 23. As a result, the information about the Company’s benefit plans presented in this Note for the year ended December 31, 2001 reflects all plan participants. However, amounts attributable to the employee benefit plans included in the Company’s consolidated financial statements will differ from the totals reported for the plans due to Dominion Services’ employees participating in the Company’s benefit plans.

The Company provides retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date, and years of service.

Following the January 28, 2000 merger, Dominion and its subsidiaries, including the Company, offered an ERP as part of a plan to restructure the operations of the combined companies. The ERP provided up to three

60

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

additional years of age and three additional years of employee service for benefit formula purposes, subject to age and service maximums under the Company’s postretirement medical and pension plans. Certain employees who satisfied minimum age and years of service requirements were eligible under the ERP. The effect of the ERP on the Company’s pension plan and postretirement benefit expenses was $42 million and $20 million, respectively. These expenses were offset, in part, by curtailment gains of approximately $19 million and $7 million from pension plans and other postretirement benefit plans, respectively, attributable to reductions in expected future years of service as a result of ERP participation and involuntary employee terminations.

In connection with the sale of VNG, the Company transferred the pension and postretirement medical benefit liabilities relating to VNG’s employees to the purchaser, together with the related plan assets. As a result, the Company recognized curtailment and settlement gains of $26 million.

In addition, effective January 1, 2000, Dominion and its subsidiaries, including the Company, adopted a change in the method of calculating the market-related value of pension plan assets. The cumulative effect of this change on prior years was reported as a change in accounting principle. See Note 3.

61

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following tables summarize the changes in the Company’s pension and other postretirement benefit plan obligations and plan assets for each of the years ended December 31, 2001 and 2000, and a statement of the plans’ funded status as of December 31, 2001 and 2000:

	Year Ended December 31,
	Pension Benefit Plans						Other Postretirement Benefit Plans
	2001			2000			2001			2000
	(Millions)
Change in benefit obligation:
Benefit obligation—January 1	$	1,006		$	970		$	363		$	297
Transferred to parent company		(27	)		—			—			—
Service cost		18			21			14			11
Interest cost		71			72			26			24
Plan amendments		4			—			18			(6	)
Actuarial loss		42			33			32			64
Change of control benefits		—			11			—			—
Special termination benefits		—			42			—			20
Curtailment		—			(19	)		—			(6	)
Sale of VNG		—			(45	)		—			(20	)
Benefit payments		(77	)		(79	)		(33	)		(21	)
Benefit obligation—December 31	$	1,037		$	1,006		$	420		$	363
Change in plan assets:
Fair value of plan assets—January 1	$	2,286		$	2,326		$	142		$	128
Actual return on plan assets		(46	)		69			10			10
Employer contributions		1			7			49			35
Sale of VNG		—			(37	)		—			(12	)
Benefit payments		(78	)		(79	)		(23	)		(19	)
Fair value of plan assets—December 31	$	2,163		$	2,286		$	178		$	142
Funded status:
Funded status—December 31	$	1,126		$	1,280		$	(243	)	$	(221	)
Unrecognized net obligation (asset)		(22	)		(18	)		117			129
Unrecognized (gain) loss-net		(508	)		(859	)		36			5
Unrecognized prior service cost		6			3			10			(10	)
Net amount recognized	$	602		$	406		$	(80	)	$	(97	)
Amounts recognized in the Consolidated Balance Sheets at December 31 consist of the following:
Prepaid benefit cost	$	568		$	434		$	—		$	—
Accrued benefit liability		(8	)		(34	)		(74	)		(97	)
Intangible asset		—			4			—			—
Accumulated other comprehensive income		2			2			—			—
Net amount recognized	$	562		$	406		$	(74	)	$	(97	)

62

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Company has nonqualified supplemental pension plans which do not have ‘‘plan assets’’ as defined by generally accepted accounting principles. The total projected benefit obligations for these plans were $7 million and $31 million at December 31, 2001 and 2000, respectively, and are included in the preceding table. The additional minimum liability recognized relating to these plans was $2 million and $6 million at December 31, 2001 and 2000, respectively. In 2000, a $4 million intangible asset related to these plans was recognized. Adjustments of the additional minimum liability and intangible asset due to changes in assumptions or the financial status of these plans resulted in a pre-tax charge or credit to other comprehensive income of less than $1 million for each of the years ended December 31, 2001 and 2000.

Net periodic benefit costs, as determined by independent actuaries, included the following components:

	Year Ended December 31,
	Pension Benefit Plans									Other Postretirement Benefit Plans
	2001			2000			1999			2001			2000			1999
	(Millions)
Service cost	$	18		$	21		$	29		$	14		$	11		$	10
Interest cost		71			72			71			26			24			20
Expected return on assets		(211	)		(193	)		(151	)		(8	)		(7	)		(6	)
Prior service cost amortization		1			1			—			(1	)		—			—
Actuarial gain		(43	)		(44	)		(14	)		—			—			(1	)
Transition obligation (asset) amortization		(9	)		(8	)		(8	)		11			11			11
Special termination benefits		—			42			—			—			20			—
Curtailment gain		—			(19	)		—			—			(7	)		—
Curtailment and settlement gain—Sale of VNG		—			(26	)		—			—			—			—
Special voluntary retirement programs		—			1			1			—			—			—
Net periodic benefit cost (credit)	$	(173	)	$	(153	)	$	(72	)	$	42		$	52		$	34
Company’s net periodic benefit cost (credit)	$	(161	)	$	(153	)	$	(72	)	$	40		$	52		$	34

Weighted average assumptions used in the determination of the benefit obligations include the following:

	Pension Benefit Plans				Other Postretirement Benefit Plans
	2001		2000		2001		2000
Discount rate	7.25	%	7.50	%	7.25	%	7.50	%
Expected return on plan assets	9.50	%	9.50	%	5.70	%	6.50	%
Rate of increase for compensation:
Non-union	5.00	%	5.00	%	5.00	%	5.00	%
Union	4.00	%	4.00	%	4.00	%	4.00	%
Medical cost trend rate					9.00	%(1)	9.00	%

⁽¹⁾ The medical cost trend rate is assumed to gradually decrease to 4.75% by 2006 and continue at that rate for years thereafter.

63

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement health care plans. A one-percentage-point change in the assumed health care cost trend rate would have the following effects on 2001 service and interest cost and the accumulated postretirement benefit obligation at December 31, 2001:

	1% Increase		1% Decrease
	(Millions)
Effect on aggregate service and interest cost components of net periodic cost	$	5	$	(4	)
Effect on the health care component of the accumulated postretirement benefit obligation	$	44	$	(37	)

The Company also sponsors employee savings plans which cover substantially all employees. Employer matching contributions of $9 million, $17 million and $17 million were expensed in 2001, 2000 and 1999, respectively.

The FERC and certain state regulatory authorities have held that amounts recovered in rates for other postretirement benefits must be deposited in irrevocable trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain subsidiaries fund postretirement benefit costs through Voluntary Employees’ Beneficiary Associations (VEBAs). The remaining subsidiaries do not prefund postretirement benefit costs but instead pay claims as presented. Assets held by the VEBAs consist primarily of short-term fixed income securities.

Note 21.    Commitments and Contingencies

As the result of issues generated in the course of daily business, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have an adverse material effect on the Company’s operations, financial position, liquidity or results of operations.

Rate Matters — Gas Distribution

The Audit Bureau of the Pennsylvania Public Utility Commission (Pennsylvania Commission) has conducted a compliance audit of the Company’s purchased gas cost rates for the years 1997 through 1999. In the fourth quarter of 2001, the Company received an audit report in which the Audit Bureau noted certain exceptions and proposed adjustments that, if determined to be appropriate, would result in refunds to customers. The Company is discussing the matter with the Pennsylvania Commission and believes that the ultimate resolution of this issue will not have a material impact on its financial position, results of operations or cash flows.

Capital Expenditures

The Company has made substantial commitments in connection with its capital expenditures program. Those expenditures are estimated to total approximately $1.3 billion, $1.2 billion and $1.2 billion for 2002, 2003 and 2004, respectively. The Company expects that these expenditures will be met through cash flow from operations and through a combination of sales of securities and short-term borrowing.

Fuel Purchase Commitments

The Company enters into long-term purchase commitments for natural gas. Estimated payments under these commitments for the next five years and beyond are as follows: 2002—$74 million; 2003—$41 million; 2004—$31 million; 2005—$28 million; 2006—$26 million; and thereafter—$288 million. These purchase

64

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

commitments include those required for regulated operations. The Company generally recovers the cost of those purchases through regulated rates. The natural gas purchase commitments of the Company’s field services operations are also included, net of related sales commitments. In addition, the Company has committed to purchase certain volumes of natural gas at market index prices determined in the period the natural gas is delivered. These transactions have been designated as normal purchases and sales under SFAS No. 133.

Natural Gas Pipeline and Storage Capacity Commitments

The Company enters into long-term commitments for the purchase of natural gas pipeline and storage. Estimated payments under these commitments for the next five years are as follows: 2002—$43 million; 2003—$38 million; 2004—$23 million; 2005—$6 million; and 2006—$1 million. There were no commitments beyond 2006.

Leases

Lease arrangements of the Company are principally for office space, business machines and equipment, including transportation vehicles and certain equipment used in gas and oil operations. None of these arrangements, individually or in the aggregate, are material capital leases. Rental expense was $40 million, $30 million and $25 million for 2001, 2000 and 1999, respectively.

Future minimum lease payments under the Company’s noncancellable operating leases with initial or remaining lease terms in excess of one year are as follows: 2002—$26 million; 2003—$59 million; 2004—$73 million; 2005—$66 million; 2006—$59 million and thereafter—$110 million.

Guarantees

The Company has guaranteed the performance of its subsidiaries under certain commodity, debt and other contracts. At December 31, 2001, such guarantees totaled $1.1 billion.

Environmental Matters

The Company is subject to rising costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. As certain environmental-related expenditures are expected to be recoverable in future regulatory proceedings, a regulatory asset has been recognized amounting to $5 million at December 31, 2001. Also, uncontested claims amounting to $2 million at December 31, 2001, were recognized for environmental-related costs probable for recovery through joint-interest operating agreements.

In 1990, the Company entered into an agreement with the Commonwealth of Pennsylvania Department of Environmental Protection (DEP) which required the Company to perform sampling, testing and analysis, and remediation at some of its affected Pennsylvania facilities. All actions under the agreement have been substantially completed as of December 31, 2001. Any future costs incurred at these facilities under the agreement are not expected to be material.

The Company has determined that it is associated with 16 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with which the Company is associated is

65

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time it is not known to what degree these sites may contain environmental contamination. Therefore, the Company is not able to estimate the cost, if any, which may be required for the possible remediation of these sites.

Before being acquired by Dominion, Louis Dreyfus was one of numerous defendants in several lawsuits pending in the Texas 93rd Judicial District Court in Hildago County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus and facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits as a result of the plume. Although the results of litigation are inherently unpredictable, the Company does not expect the ultimate outcome of the case to have a material adverse impact on its financial position or results of operations.

Note 22.    Fair Value of Financial Instruments

Substantially all of the Company’s financial instruments, with the exception of the instruments described below, are recorded at fair value. Fair value amounts have been determined using available market information and valuation methodologies considered appropriate in the opinion of management.

The Company reports the following financial instruments based on historical cost rather than fair value. The financial instruments’ carrying amounts and fair values as of December 31, 2001 and 2000 were as follows:

	2001				2000
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(Millions)
Long-term debt(1)	$	3,394	$	3,393	$	1,734	$	1,689
Preferred securities of subsidiary trust(2)		200		200		—		—
Unrecognized financial instruments(3):
Interest rate swaps(4)		—		—		—		18
Swaps, collars and options–hedging(5)		—		—		—		(182	)

⁽¹⁾ Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities are used to estimate fair value. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

⁽²⁾ Fair value is based on market quotations.

⁽³⁾ Upon adoption of SFAS No. 133 on January 1, 2001, all derivatives are reported at fair value. The fair value of unrecognized financial instruments at December 31, 2000 was recognized as a component of the January 1, 2001 SFAS No. 133 transition adjustment. See Note 11 for discussion of the Company’s derivatives and hedge accounting activities.

⁽⁴⁾ Fair value was based upon the present value of all estimated net future cash flows, taking into account current interest rates and the creditworthiness of the swap counterparties.

⁽⁵⁾ Fair value reflected the Company’s best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments.

Note 23.    Related Party Transactions

The Company exchanges certain quantities of natural gas with affiliates at index prices, and electricity at market prices in the ordinary course of business. The Company purchased approximately $229 million and $25 million of natural gas from other Dominion affiliates and sold approximately $119 million and $61 million to affiliates in 2001 and during the period January 28, 2000 through December 31, 2000, respectively. The Company also purchased approximately $4 million and $5 million of electricity from affiliates and sold approximately $12 million and $1 million of electricity to affiliates in 2001 and during the period January 28,

66

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2000 through December 31, 2000, respectively. In addition, the Company provided $16 million and $7 million of gas transportation, storage and other services to affiliates in 2001 and during the period January 28, 2000 through December 31, 2000, respectively.

The Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by the Company to manage commodity price risks associated with purchases and sales of natural gas. The Company designates the majority of these contracts as hedges for accounting purposes (see Note 11). The Company’s Consolidated Balance Sheet includes derivative assets with Dominion affiliates of $56 million and derivative liabilities with Dominion affiliates of $158 million at December 31, 2001. Derivative assets with Dominion affiliates of $154 million and derivative liabilities with Dominion affiliates of $50 million were recorded on the Company’s Consolidated Balance Sheet at January 1, 2001 in connection with the adoption of SFAS No. 133. Net realized losses of $3 million and net realized gains of $19 million associated with commodity derivative contracts with Dominion affiliates were recognized in 2001 and in the period February 1 through December 31, 2000, respectively.

Effective February 1, 2000, Dominion created a subsidiary service company, Dominion Services, which provides certain administrative and technical services to the Company. The cost of services provided by Dominion Services to the Company during 2001 and the period February 1, 2000 through December 31, 2000 was approximately $179 million and $30 million, respectively. In 2001, the Company also billed other Dominion affiliates $2 million for certain costs incurred on their behalf.

Effective January 1, 2001, CNG Services was merged into Dominion Services (see Note 1). Approximately $79 million of assets and $79 million of liabilities were transferred from the Company to Dominion Services.

During 2001, the Company transferred certain corporate-owned life insurance policies to Dominion Services with a cash surrender value of approximately $56 million in exchange for a 50 percent equity interest in Dominion Services.

Effective January 1, 2001, the Company transferred its interest in certain Canadian oil producing properties at a market value of approximately $5 million to another Dominion affiliate.

The Company had net outstanding payables to affiliates of approximately $312 million and $33 million, and net outstanding receivables from affiliates of approximately $95 million and $18 million as of December 31, 2001 and 2000, respectively. Balances due from or payable to affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. In addition, the Company and its subsidiaries participate in a system Money Pool arrangement authorized by the SEC. Effective January 1, 2001, Dominion Services began administering the Money Pool, whereas prior to 2001, the Money Pool was administered by CNG Services, a subsidiary service company. After satisfaction of the borrowing needs of participants and after any possible prepayment of outstanding indebtedness, Dominion Services, as agent for the Pool, invests any excess Money Pool funds on a short-term basis. At December 31, 2001, the Company had a receivable of $60 million related to the investment of excess funds by Dominion Services.

See Notes 2, 19, and 20 for a discussion of the inclusion of the Company in Dominion’s consolidated federal income tax return and the Company’s participation in certain Dominion employee incentive and benefit plans.

67

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 24.    Operating Segments

The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on three primary operating segments:

• The Delivery Segment includes the retail gas distribution subsidiaries, Dominion East Ohio, Dominion Peoples and Dominion Hope;

• The Energy Segment includes the pipeline, storage, and the gas and oil production activities of Dominion Transmission, and the activities of the Company’s gas marketing subsidiaries, Dominion Field Services, Dominion Retail and Dominion Products and Services; and

• The Exploration and Production Segment includes the Company’s exploration and production operations.

In addition, the Company also reports Corporate and Other as an operating segment. The Corporate and Other segment includes the activities of CNG International and other minor subsidiaries, costs of the Company’s corporate operations and certain expenses which are not allocated to the other operating segments, including the following:

• 2001 cumulative effect of adopting SFAS No. 133 of $22 million ($14 million after taxes) (see Note 11);

• 2001 estimated impaired fair value of forward natural gas contracts of $108 million ($69 million after taxes), resulting from the Company’s exposure to Enron (see Note 11);

• 2001, 2000 and 1999 restructuring and other merger-related costs of $45 million ($31 million after taxes), $270 million ($195 million after taxes) and $213 million ($145 million after taxes), respectively (see Note 6);

• 2000 impairment of foreign investments held for sale of $152 million ($99 million after taxes) (see Note 8);

• 2000 gain on sale of subsidiary of $163 million ($98 million after taxes) (see Note 6); and

• 2000 cumulative effect of the change in pension accounting of $42 million ($31 million after taxes) (see Note 3).

Eliminations represent eliminating adjustments for transactions between the operating segments to reconcile the segment information to consolidated amounts.

68

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table presents segment information pertaining to the Company’s operations:

	Year Ended December 31, 2001
	Delivery		Energy		Exploration and Production		Corporate and Other			Eliminations			Total
	(Millions)
Operating revenue:
External customer revenue:
Regulated gas sales	$	1,409	$	—	$	—	$	—		$	—		$	1,409
Nonregulated gas sales		4		987		64		—			—			1,055
Gas transportation and storage		298		420		—		—			—			718
Gas and oil production		—		—		706		—			—			706
Other revenue		34		112		172		31			—			349
Total external customer revenue		1,745		1,519		942		31			—			4,237
Intersegment revenue:
Nonregulated gas sales		—		47		—		—			(47	)		—
Gas transportation and storage		—		84		1		—			(85	)		—
Gas and oil production		—		—		66		—			(66	)		—
Other revenue		2		—		—		18			(20	)		—
Total intersegment revenue		2		131		67		18			(218	)		—
Total operating revenue		1,747		1,650		1,009		49			(218	)		4,237
Income (loss) from operations		263		287		335		(152	)		—			733
Interest and related charges		57		31		45		168			(145	)		156
Depreciation, depletion and amortization		76		66		265		—			—			407
Equity in earnings of equity method investees		—		12		4		2			—			18
Income tax expense (benefit)		63		105		95		(64	)		—			199
Income (loss) before cumulative effect of a change in accounting principle		148		167		202		274			(386	)		405
Investment in equity method investees		1		63		48		68			(68	)		112
Total assets		2,926		2,143		5,839		7,360			(7,241	)		11,027
Capital expenditures		90		351		3,145		21			—			3,607

69

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year Ended December 31, 2000
	Delivery		Energy			Exploration and Production		Corporate and Other			Eliminations			Total
	(Millions)
Operating revenue:
External customer revenue:
Regulated gas sales	$	1,719	$	—		$	—	$	—		$	—		$	1,719
Nonregulated gas sales		—		676			70		—			—			746
Gas transportation and storage		222		328			1		—			—			551
Gas and oil production		—		(12	)		544		—			—			532
Other revenue		40		105			310		12			—			467
Total external customer revenue		1,981		1,097			925		12			—			4,015
Intersegment revenue:
Nonregulated gas sales		—		49			—		—			(49	)		—
Gas transportation and storage		1		103			—		—			(104	)		—
Gas and oil production		—		—			53		—			(53	)		—
Other revenue		3		1			1		138			(143	)		—
Total intersegment revenue		4		153			54		138			(349	)		—
Total operating revenue		1,985		1,250			979		150			(349	)		4,015
Income (loss) from operations		266		256			242		(279	)		(6	)		479
Interest and related charges		58		32			45		131			(104	)		162
Depreciation, depletion and amortization		84		65			286		7			—			442
Loss on net assets held for sale		—		—			—		152			—			152
Gain on sale of subsidiary		—		—			—		163			—			163
Equity in earnings of equity method investees		—		7			4		6			—			17
Income tax expense (benefit)		71		87			66		(74	)		(3	)		147
Income (loss) before cumulative effect of a change in accounting principle		144		147			138		101			(317	)		213
Investment in equity method investees		1		29			49		67			(67	)		79
Total assets		3,131		1,986			2,211		5,174			(5,243	)		7,259
Capital expenditures		126		75			603		9			—			813

	Year Ended December 31, 1999
	Delivery		Energy			Exploration and Production		Corporate and Other			Eliminations			Total
	(Millions)
Operating revenue:
External customer revenue:
Regulated gas sales	$	1,397	$	—		$	—	$	—		$	—		$	1,397
Nonregulated gas sales		—		211			67		—			—			278
Gas transportation and storage		209		357			1		—			—			567
Gas and oil production		—		(1	)		367		—			—			366
Other revenue		32		77			259		2			—			370
Total external customer revenue		1,638		644			694		2			—			2,978
Intersegment revenue:
Regulated gas sales		1		—			—		—			(1	)		—
Nonregulated gas sales		—		9			—		—			(9	)		—
Gas transportation and storage		1		104			—		—			(105	)		—
Gas and oil production		—		—			28		—			(28	)		—
Other revenue		4		1			1		226			(232	)		—
Total intersegment revenue		6		114			29		226			(375	)		—
Total operating revenue		1,644		758			723		228			(375	)		2,978
Income (loss) from operations		202		222			120		(225	)		—			319
Interest and related charges		48		27			29		107			(87	)		124
Depreciation, depletion and amortization		81		63			230		6			—			380
Equity in earnings of equity method investees		—		5			6		10			—			21
Income tax expense (benefit)		48		75			25		(75	)		—			73
Income (loss) before cumulative effect of a change in accounting principle		101		128			73		31			(196	)		137
Investment in equity method investees		1		39			51		259			—			350
Total assets		2,950		1,589			1,714		4,979			(4,696	)		6,536
Capital expenditures		111		49			435		44			—			639

70

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 25.    Gas and Oil Producing Activities (Unaudited)

Following the merger with Dominion, the Company changed its method of presenting gas and oil financial and statistical information from a “net before royalty” basis to a “net revenue” basis to conform to Dominion’s presentation. As a result, amounts previously reported for revenue, royalty expense, and gas and oil reserves and production have been restated. The change to the “net revenue” basis also conforms the Company’s presentation to that widely used by the industry.

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depreciation, depletion and amortization, follow:

	At December 31,
	2001		2000
	(Millions)
Capitalized costs:
Proved properties	$	6,022	$	3,909
Unproved properties		1,614		705
		7,636		4,614
Accumulated depreciation:
Proved properties		2,844		2,612
Unproved properties		294		253
		3,138		2,865
Net capitalized costs	$	4,498	$	1,749

Total Costs Incurred

The following costs were incurred in gas and oil producing activities during the years 1999 through 2001:

	Year Ended December 31,
	2001*				2000						1999
	Total		United States		Total		United States		Canada		Total		United States		Canada
	(Millions)
Property acquisition costs:
Proved properties	$	1,583	$	1,583	$	215	$	215	$	—	$	171	$	171	$	—
Unproved properties		887		887		39		39		—		33		33		—
		2,470		2,470		254		254		—		204		204		—
Exploration costs		305		305		113		113		—		113		113		—
Development costs(1)		345		345		192		189		3		95		94		1
Total	$	3,120	$	3,120	$	559	$	556	$	3	$	412	$	411	$	1

* Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion.

⁽¹⁾ Development costs incurred for proved undeveloped reserves were $130 million, $82 million and $57 million for 2001, 2000 and 1999, respectively.

71

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Results of Operations

The Company cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.

	Year Ended December 31,
	2001*				2000						1999
	Total		United States		Total		United States		Canada		Total		United States		Canada
	(Millions)
Revenue (net of royalties) from:
Sales to nonaffiliated companies	$	706	$	706	$	551	$	545	$	6	$	382	$	377	$	5
Transfers to other operations		114		114		98		98		—		52		52		—
		820		820		649		643		6		434		429		5
Less:
Production (lifting) costs		103		103		93		90		3		81		78		3
Depreciation, depletion and amortization(1)		403		403		276		276		—		224		224		—
Income tax expense(2)		101		101		93		92		1		38		37		1
Results of operations	$	213	$	213	$	187	$	185	$	2	$	91	$	90	$	1

* Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion.

⁽¹⁾ Depreciation, depletion and amortization for 2001 includes a full-cost impairment of $83 million, offset completely by the reclassification of certain deferred gains from AOCI. See Notes 11 and 12.

⁽²⁾ Income tax for 2001 includes $30 million related to the full-cost impairment.

Company-Owned Reserves

Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 1999 through 2001, and changes in the reserves during those years, are shown in the two schedules which follow.

	Year Ended December 31,
	2001*						2000					1999
	Total		United States		Canada		Total		United States		Canada	Total		United States		Canada
	(Billion Cubic Feet)
Proved developed and undeveloped Reserves—Gas
Balance at January 1	1,224		1,223		1		1,205		1,204		1	1,110		1,109		1
Changes in reserves
Extensions, discoveries and other additions	260		260		—		142		142		—	113		113		—
Revisions of previous estimates	(136	)	(136	)	—		(71	)	(71	)	—	(61	)	(61	)	—
Production	(170	)	(170	)	—		(173	)	(173	)	—	(153	)	(153	)	—
Purchases of gas in place	1,573		1,573		—		129		129		—	206		206		—
Sales of gas in place	(9	)	(8	)	(1	)	(8	)	(8	)	—	(10	)	(10	)	—
Balance at December 31	2,742		2,742		—		1,224		1,223		1	1,205		1,204		1
Proved developed reserves—Gas
Balance at January 1	974		973		1		960		959		1	895		894		1
Balance at December 31	2,283		2,283		—		974		973		1	960		959		1

* Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion. Proved reserves associated with the Canadian properties approximated 1 bcf of gas and 6.6 million barrels of oil at December 31, 2000. The property was transferred at a market value of $4.5 million.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year Ended December 31,
	2001*						2000						1999
	Total		United States		Canada		Total		United States		Canada		Total		United States		Canada
	(Thousands of Barrels)
Proved developed and undeveloped Reserves—Oil
Balance at January 1	57,273		50,691		6,582		49,287		42,643		6,644		46,625		41,854		4,771
Changes in reserves
Extensions, discoveries and other additions	37,385		37,385		—		12,814		12,814		—		6,209		6,034		175
Revisions of previous estimates	9,754		9,754		—		(2,028	)	(2,318	)	290		5,352		3,325		2,027
Production	(6,953	)	(6,953	)	—		(7,213	)	(6,861	)	(352	)	(8,545	)	(8,216	)	(329	)
Purchases of oil in place	34,604		34,604		—		6,293		6,293		—		806		806		—
Sales of oil in place	(7,372	)	(790	)	(6,582	)	(1,880	)	(1,880	)	—		(1,160	)	(1,160	)	—
Balance at December 31	124,691		124,691		—		57,273		50,691		6,582		49,287		42,643		6,644
Proved developed reserves—Oil
Balance at January 1	27,910		21,328		6,582		38,934		32,290		6,644		34,960		30,189		4,771
Balance at December 31	55,176		55,176		—		27,910		21,328		6,582		38,934		32,290		6,644

* Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion. Proved reserves associated with the Canadian properties approximated 1 bcf of gas and 6.6 million barrels of oil at December 31, 2000. The property was transferred at a market value of $4.5 million.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities owned by the Company.

	Year Ended December 31,
	2001*				2000						1999
	Total		United States		Total		United States		Canada		Total		United States		Canada
	(Millions)
Future cash inflows	$	9,430	$	9,430	$	13,506	$	13,434	$	72	$	4,008	$	3,890	$	118
Less: Future development cost(1)		756		756		396		347		49		275		273		2
Future production cost		2,422		2,422		756		755		1		632		572		60
Future income tax expense		1,727		1,727		4,072		4,068		4		934		918		16
Future net cash flows		4,525		4,525		8,282		8,264		18		2,167		2,127		40
Less annual discount (10% a year)		2,197		2,197		3,146		3,140		6		796		782		14
Standardized measure of discounted future net cash flows(2)	$	2,328	$	2,328	$	5,136	$	5,124	$	12	$	1,371	$	1,345	$	26

 * Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion.

⁽¹⁾ Estimated future development costs, excluding abandonment, for proven undeveloped reserves are estimated to be $241 million, $272 million and $85 million for 2002, 2003, and 2004, respectively.

⁽²⁾ Amounts exclude the effect of contracts designated as hedges of future sales of production at year-end.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, or permanent differences and tax credits.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10 percent discount rate is arbitrary. In addition, present costs and prices are used in the determinations, and no value may be assigned to probable or possible reserves.

The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.

	Year Ended December 31,
	2001			2000			1999
	(Millions)
Standardized measure of discounted future net cash flows at January 1	$	5,136		$	1,371		$	888
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(718	)		(556	)		(353	)
Prices and production and development costs related to future production		(6,009	)		5,693			810
Extensions, discoveries and other additions, less production and development costs		562			1,108			186
Previously estimated development costs incurred during the year		130			81			57
Revisions of previous quantity estimates		(69	)		(652	)		(213	)
Accretion of discount		675			194			121
Income taxes		1,452			(1,802	)		(263	)
Acquisition of Louis Dreyfus		1,347			—			—
Other purchases and sales of proved reserves in place-net		43			992			265
Other (principally timing of production)		(221	)		(1,293	)		(127	)
Standardized measure of discounted future net cash flows at December 31	$	2,328		$	5,136		$	1,371

Note 26.    Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2001 and 2000 follows. Amounts shown reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods.

Because a major portion of the gas sold or transported by the Company’s distribution and transmission operations is ultimately used for space heating, both revenue and earnings are subject to seasonal fluctuations. Seasonal fluctuations may be further influenced by the timing of price relief granted under regulation to compensate for certain past cost increases.

	2001									2000
	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		First Quarter			Second Quarter		Third Quarter		Fourth Quarter
	(Millions)
Operating revenue	$	1,735		$	745	$	718	$	1,039	$	1,169		$	721	$	730	$	1,395
Income from operations		315			143		142		133		134			86		108		151
Income (loss) before cumulative effect of changes in accounting principle		179			73		76		77		(22	)		20		49		166
Cumulative effect of changes in accounting principle		(14	)		—		—		—		31			—		—		—
Net income		165			73		76		77		9			20		49		166

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The Company’s independent accountant is Deloitte & Touche LLP. PricewaterhouseCoopers LLP was the independent accountant for the Company prior to the acquisition by Dominion.

The Company had no disagreements with its independent accountant, Deloitte & Touche LLP or its former accountant, PricewaterhouseCoopers LLP, as noted in the Company’s Form 8-K, filed on January 28, 2000, which announced the completion of the acquisition of the Company by Dominion.

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

ITEM 11.    EXECUTIVE COMPENSATION

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

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

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PART IV

ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)   The following documents are filed as part of this Form 10-K:

1. Financial Statements

See Index on page    .

2. Financial Statement Schedules

	Page
Independent Auditors’ Report on Financial Statement Schedules	79
Schedule I—Condensed Financial Information of Registrant	80
Schedule II—Valuation and Qualifying Accounts	85

All other schedules are omitted because they are not applicable, or the required information is shown in the financial statements or the related notes.

3. Exhibits

SEC Exhibit Number	Description of Exhibit
2.1	Amended and Restated Agreement and Plan of Merger, dated as of May 11, 1999, by and between Dominion Resources, Inc. and Consolidated Natural Gas Company, (Exhibit 2, Form 8-K, dated May 20, 1999, File No. 1-3196, incorporated by reference).
2.2	Joinder Agreement dated as of January 21, 2000 by and among Dominion Resources, Inc., Consolidated Natural Gas Company, DRI New Sub I, Inc. and DRI New Sub II, Inc. (Exhibit (2A)(i) to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).
3.1	Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).
3.2	Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).
3.2	Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).
4.1	Indenture, dated as of May 1, 1971, between Consolidated Natural Gas Company and JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012, incorporated by reference); Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651, incorporated by reference); Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Eighteenth Supplemental Indenture dated as of December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Twentieth Supplemental Indenture dated as of March 19, 2001 (Exhibit 4(viii), Form 10-K for the fiscal year ended December 31, 2000, File No. 1-8489, incorporated by reference).

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SEC Exhibit Number	Description of Exhibit
4.2	Indenture, dated as of April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to United States Trust Company of New York) (Exhibit (4) to Certificate of Notification at Commission File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4 A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004).
4.3	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.1, Form S-3 File No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K, File dated April 12, 2001, File No. 1-3196 incorporated by reference); Second Supplemental Indenture, dated October 25, 2001 (Exhibit 4.1, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Third Supplemental Indenture, dated October 25, 2001 (Exhibit 4.3, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference).
4.4	Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and Bank One Trust Company, National Association (Exhibit 4.2, Form S-3 Registration No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K, dated October 16, 2001, File No. 1-3196, incorporated by reference).
4.5	Indenture, dated as of June 15, 1994, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration and Production, Inc. and The Bank of New York (as successor trustee to Bank of Montreal Trust Company) (filed herewith); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001(Exhibit 4.7, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).
4.6	Indenture, dated as of December 11, 1997, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration & Production, Inc., and La Salle Bank National Association (formerly, LaSalle National Bank) (filed herewith); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001 (Exhibit 4.9, Form 10-Q for the quarter ended September 30, 2001, incorporated by reference).
23	Consent of Ralph E. Davis Associates, Inc. (filed herewith).

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(b) Reports on Form 8-K:

1.  The Company filed a report on Form 8-K, dated November 14, 2001, relating to the acquisition of Louis Dreyfus.

2.  The Company filed a report on Form 8-K/A, dated January 11, 2002, relating to required financial statement disclosures for the Louis Dreyfus acquisition.

3.  The Company filed a report on Form 8-K, dated January 29, 2002, relating to Dominion’s press release announcing unaudited results of operations for the fiscal year ended December 31, 2001.

78

INDEPENDENT AUDITORS’ REPORT

To Board of Directors of

Consolidated Natural Gas Company

Richmond, Virginia

We have audited the consolidated financial statements of Consolidated Natural Gas Company (a wholly owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the “Company”) as of December 31, 2001 and 2000, and for each of the two years in the period ended December 31, 2001, and have issued our report thereon dated January 22, 2002; such report is included elsewhere in the Form 10-K. Our audits also included the consolidated financial statement schedules of the Company as of December 31, 2001 and 2000 and for each of the two years in the period ended December 31, 2001, listed in Item 14. These consolidated financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Pittsburgh, Pennsylvania

January 22, 2002

79

CONSOLIDATED NATURAL GAS COMPANY

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME

	Year Ended December 31,
	2001			2000			1999
	(Millions)
Operating revenue	$	—		$	—		$	—
Operating expenses		(3	)		62			55
Income from operations		3			(62	)		(55	)
Other income		156			314			118
Interest and related charges		168			174			137
Income (loss) before income taxes		(9	)		78			(74	)
Income taxes		(11	)		46			(21	)
Equity in undistributed earnings of subsidiaries		389			212			190
Net income	$	391		$	244		$	137

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

80