___________________

Commission File Number 1-3196

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 __

As of July 31, 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.

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

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________________

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

*   The Consolidated Balance Sheet at December 31, 2001 has been derived from the audited Consolidated
     Financial Statements at that date.

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________________

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

*   The Consolidated Balance Sheet at December 31, 2001 has been derived from the audited Consolidated
     Financial Statements at that date.

** Debt securities issued by Consolidated Natural Gas Company constitute 100 percent of the Trust's assets.

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________________

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

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Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. 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, the 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 o f energy marketing services and holds an equity investment in energy-related activities in Australia that is classified as held for sale. See Note 8 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for additional information.

The Company manages its daily operations through three primary operating segments: Delivery, Energy, and Exploration and Production. In addition, the Company also reports its corporate and other operations as an operating segment. Assets remain wholly owned by its legal subsidiaries. For a detailed description of the Company's operating segments, see Note 15.

Within this document, "the Company" is used and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of the Consolidated Natural Gas Company's consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries.

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited consolidated financial statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited consolidated financial statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of June 30, 2002, and its results of operations for the three and six-month periods and cash flows for the six-month periods ended June 30, 2002 and 2001.

The consolidated financial statements represent the accounts of the Company and its subsidiaries, with all significant intercompany transactions eliminated in consolidation. 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.

The accompanying unaudited consolidated financial statements reflect certain estimates and assumptions made by management 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 revenue and expenses for the periods presented. Actual results may differ from those estimates.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for a more detailed discussion of the Company's estimation techniques.

The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of purchased gas expense recovery and other factors.

Certain amounts in the 2001 consolidated financial statements have been reclassified to conform to the 2002 presentation.

In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 certain retirement obligations that will be subject to the standard. These obligations are associated with the removal of certain storage tanks, the abandonment of certain natural gas pipelines and dismantlement and restoration activities for its gas and oil wells and platforms. The standard requires that any transition adjustments measured at adoption w ill be recognized as a cumulative effect of a change in accounting principle. The Company has not yet determined the financial impact of adopting this new standard. For more information, see Note 4 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

Note 4.     Goodwill and Intangible Assets

In 2001, FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 prohibits the amortization of goodwill and intangible assets with indefinite useful lives. SFAS No. 142 also 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 adopted SFAS No. 142 on January 1, 2002. The Company is required to test its goodwill for impairment using a two-step process described in SFAS No. 142 on an annual basis or whenever events or circumstances might indicate that the fair value of the Company's reporting units may have been affected. The first step is a screen for potential impairment, while the second step measures the amount of the impairment, if any. The Company completed the transitional goodwill impairment test during the second quarter of 2002 and found no instances of impairment.

Other than the $24 million adjustment made during the first quarter of 2002 to the carrying amount of goodwill recognized as part of the purchase of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), there were no significant changes in the carrying amount of goodwill during the first half of 2002. See Note 5. In addition, all of the goodwill arising from the Louis Dreyfus acquisition has been allocated to the Exploration and Production segment for purposes of impairment testing under SFAS No. 142.

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All of the Company's intangible assets other than goodwill are subject to amortization. Intangible assets amortization expense was $4 million and $9 million for the quarter and six months ended June 30, 2002, respectively, and $4 million and $8 million for the quarter and six months ended June 30, 2001, respectively. There were no material acquisitions of intangible assets during the first half of 2002. The components of intangible assets at June 30, 2002 were as follows:

Amortization expense for intangible assets is estimated to be $19 million for 2002, $17 million for 2003, $16 million for 2004, $15 million for 2005 and $14 million for 2006.

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, for $1.8 billion in Dominion common stock and cash. Dominion acquired Louis Dreyfus by merging it into a newly formed wholly owned subsidiary, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. The purchase price allocation was completed during the first quarter of 2002 upon receipt of information from outside specialists, increasing liabilities and goodwill each by $24 million.

In the fourth quarter of 2001, after fully integrating the Company into Dominion's existing organization and operations, management initiated a focused review of Dominion's combined operations. As a result, the Company recognized restructuring costs which included employee severance and related benefits and the abandonment of leased office space no longer needed.

Under the 2001 restructuring plan, the Company identified approximately 141 salaried positions to be eliminated and recorded $13 million in employee severance-related costs. Through June 30, 2002, the Company had eliminated 95 positions.

The change in the liabilities for severance and related costs and lease abandonment costs during the first six months of 2002 is presented below:

For additional information on restructuring activities, see Note 6 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

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For the three months ended June 30, 2002 and 2001, the Company recognized total comprehensive income of $22 million and $170 million, respectively. For the six months ended June 30, 2002 and 2001, the Company recognized total comprehensive income of $0.2 million and $306 million, respectively. Other comprehensive income for the three and six-month periods ended June 30, 2002 and 2001 relates primarily to the effective portion of the changes in fair values of derivatives designated as hedging instruments in cash flow hedges as described in more detail in Note 8.

Note 8.    Derivatives and Hedge Accounting

The Company recorded an after-tax charge to accumulated other comprehensive income (AOCI) of $105 million, net of taxes of $57 million, in the first quarter of 2001 in connection with the January 1, 2001 adoption of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

Changes in the Company's accumulated other comprehensive income (loss) associated with the effective portion of the change in fair value of derivatives designated as hedging instruments in cash flow hedges, net of taxes and related amounts reclassified to earnings follow:

Based on balances at June 30, 2002, the Company expects to reclassify approximately $41 million of net losses from AOCI to earnings during the next twelve-month period. The actual amounts that will be reclassified to earnings over the next twelve months will vary from this amount as a result of changes in market prices. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (for example, anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies. As of June 30, 2002, the Company hedged its exposure to the variability in future cash flows for forecasted transactions over periods of one to six years.

The Company recorded an after-tax loss of $14 million (net of income taxes of $8 million) in the first quarter of 2001, representing the cumulative effect of adopting SFAS No. 133 in its Consolidated Statements of Income. The Company recognized pre-tax increases (decreases) in earnings for hedge ineffectiveness as follows:

For options designated as hedging instruments, the Company excludes the changes in the options' fair value attributable to time value from the measurement of hedge effectiveness. Such amounts were included in earnings but did not exceed $1 million in any of the reported periods.

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Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from credit exposures exceeding agreed-upon credit limits. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from credit exposures for various trading counterparties exceeding agreed-upon credit limits. These credit limits and the mechanism for calculating the amounts to be held on deposit are determined in the International Swap Dealers Association (ISDA) master agreements in place between the Company and its counterparties. As of June 30, 2002 and December 31, 2001, the Company had margin assets (funds paid by the Company and held by counterparties) of $258 million and $20 million, respectively. Margin deposit liabilities (funds paid by counterparties and held by the Company) were $88 million at December 31, 2001, and there were no margin deposit liabilities at June 30, 2002.

Note 9.    Ceiling Test

As more fully described in Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, the Company follows the full cost method of accounting for gas and oil exploration and production activities, as prescribed by the SEC. Under this method, capitalized costs are subject to a quarterly "ceiling test". Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves. As currently permitted by the SEC, the Company uses hedge adjusted period-end prices to calculate the present value of estimated future net revenues. Such prices are used for the portion of anticipated production from proved reserves that is hedged by qualifying cash flow hedges. As of June 30, 2002, the use of period-end market prices rather than hedge-adjusted prices, as otherwise required by the full cost method, would not have resulted in an impairment charge. D ue to the volatility of gas and oil prices, it is reasonably possible that for some quarters, the Company may satisfy the ceiling test using hedge-adjusted prices, whereas the use of market prices could have resulted in an impairment charge.

Long-Term Debt

In January 2002, the Company redeemed $6 million of its 9.25 percent senior notes due June 15, 2004 at a repurchase price of 101 percent of principal plus accrued interest. The redemption was required as a result of the exercise of options by holders of the notes under terms of the applicable indenture.

At June 30, 2002, the Company had $1.5 billion of available capacity under a shelf registration with the SEC that would permit the Company to issue debt and trust preferred securities to meet future capital requirements.

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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 January 2002, the Company filed an application with the SEC for relief from the restriction on paying dividends out of the 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. As of June 30, 2002, the application was still pending with the SEC.

Other than the fuel purchase commitments and lease commitment discussed below, there have been no significant developments with regard to commitments and contingencies, including environmental matters, as disclosed in Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, nor have any significant new matters arisen during the six months ended June 30, 2002.

The Company enters into long-term purchase commitments for natural gas primarily to supply its gas marketing and regulated distribution operations. At June 30, 2002, estimated payments under these commitments for the next five years and beyond are as follows: 2002-$84 million; 2003-$83 million; 2004-$31 million; 2005-$28 million; 2006-$26 million; and thereafter-$288 million.

Lease Commitment

A subsidiary of the Company has attained Exempt Wholesale Generator (EWG) status from the Federal Energy Regulatory Commission and has entered into an operating lease agreement with another Dominion subsidiary, Dominion Equipment, Inc., to lease a power generation facility in Armstrong, Pennsylvania. The future minimum lease payments under this agreement as of June 30, 2002 are as follows: 2002-$6 million; 2003-$8 million; 2004-$12 million; 2005-$13 million; and 2006-$12 million. The facility became available for commercial operations during the second quarter of 2002. The facility's operations, included in the Company's Energy segment, had no material impact on the Company's revenue, net income or cash flows for the three and six months ended June 30, 2002.

Guarantees and Letter of Credit

As part of normal business, the Company is a party to various financial guarantees, performance guarantees and other guarantees for certain subsidiaries. The amounts subject to certain of these guarantees will vary depending on the covered contracts actually outstanding at any particular point in time. Guarantees and standby letters of credit are used, when necessary, to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis. Accordingly, the Company provides guarantees to third parties on behalf of subsidiaries so the third parties will be willing to enter into contracts with the subsidiaries and to extend sufficient credit to facilitate the subsidiaries' accomplishment of intended commercial purposes. In such instances, guarantees may be used to limit exposures resulting from subsidiary business activities to pre-defined amounts. To the extent a liability, subject to a guarantee, has been incurred by a consolidated subsidiary, such liability is included in the C ompany's consolidated financial statements. Only in those limited instances where the Company issues a guarantee on behalf of a related party that is not consolidated in the preparation of the Company's consolidated financial statements would performance under the guarantee result in the recognition of additional liabilities in the Company's consolidated financial statements.

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At June 30, 2002 and December 31, 2001, outstanding guarantees totaled $1.4 billion and $1.1 billion, respectively. The Company believes it unlikely that it would be required to perform or otherwise incur any losses associated with guarantees.

As of June 30, 2002, the outstanding guarantees of $1.4 billion represented the following types of guarantees:

Guarantee of Consolidated Subsidiary Debt-The Company has guaranteed the payment of interest and principal on the $288 million of DOTEPI's debt. The debt is included in the Company's consolidated balance sheet at June 30, 2002. In the event of default by DOTEPI, the Company would be obligated to repay such amounts.

Guarantees Supporting Commodity Transactions of Consolidated Subsidiaries-The Company has also guaranteed amounts up to approximately $1.1 billion of commodity-related payments primarily for certain of its subsidiaries involved in natural gas and oil production and energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. To the extent liabilities exist under the commodity-related contracts subject to these guarantees, such liabilities are included in the Company's consolidated balance sheet at June 30, 2002. If any one of these subsidiaries fails to perform or pay under the contracts and the counterparties seek performance or payment, the Company would be obligated to satisfy such obligation. The Company receives similar guarantees as collateral for credit extended by the Company.

Standby Letter of Credit

At June 30, 2002, the Company had authorized the issuance of a standby letter of credit by a financial institution in the amount of $175 million, for the benefit of a counterparty that had extended credit to the Company. In the unlikely event that the Company does not pay amounts when due under the covered contracts, the counterparty may present its claim for payment to the financial institution, which would then request payment from the Company. The letter of credit is backed by the 3-year revolving credit facility that matures in May 2005. See Note 10. As of June 30, 2002, no amounts had been presented for payment under this letter of credit.

The Company exchanges certain quantities of natural gas with Dominion affiliates at index prices in the ordinary course of business. The affiliated commodity transactions are presented below:

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The Company enters into certain commodity derivative contracts with 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. At June 30, 2002 and December 31, 2001, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $34 million and $56 million and derivative liabilities with Dominion affiliates of $59 million and $158 million, respectively. The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

Dominion Resources Services, Inc. (Dominion Services) provides certain administrative and technical services to the Company. The cost of services provided by Dominion Services to the Company in the second quarter of 2002 and 2001 was approximately $43 million and $40 million, respectively, and in the first six months of 2002 and 2001 was approximately $81 million and $76 million, respectively.

During the six months ended June 30, 2002, Dominion advanced $816 million, net of repayments, to the Company pursuant to a zero percent interest, short-term demand note (Demand Note); Dominion subsequently declared $400 million of the amounts borrowed by the Company to be an equity contribution. At June 30, 2002, the net outstanding borrowings under the Demand Note totaled $416 million.

For information about the leasing of a power generation facility in Armstrong, Pennsylvania by a subsidiary of the Company from another Dominion subsidiary, Dominion Equipment, Inc., see Note 12.

For additional information on related party transactions, see Note 23 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. 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. Management does not believe that this geographic concentration contributes significantly to the Company's overall exposure to credit risk.

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 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 June 30, 2002 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

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The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. In the calculation of net credit exposure, the Company's gross exposure is reduced by collateral made available by counterparties, including letters of credit and cash received by the Company and held as margin deposits. Presented below is a summary of the Company's gross and net credit exposure as of June 30, 2002. The amounts presented exclude accounts receivable for gas sales and services and regulated gas transmission services and the Company's provision for credit losses.

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The Delivery segment manages the Company's retail gas distribution systems and customer service operations.

The Energy segment manages the Company's pipeline, storage and by-product operations, gas and oil production activities, and the activities of the Company's gas marketing subsidiaries.

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

The Company also reports its corporate and other operations as an operating segment. The Corporate and Other segment includes:

• costs of the Company's corporate operations;
• costs associated with cumulative effect of adopting SFAS No. 133 of $22 million ($14 million after taxes) in 2001; and
• activities of CNG International, Inc. and other minor subsidiaries.

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The Company is organized primarily on the basis of products and services sold in the United States. For a detailed description of the Company's operating segments, reference is made to Notes 1 and 24 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

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Management's Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. "The Company" is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of the Consolidated Natural Gas Company's consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. The Company is a wholly owned subsidiary of Dominion 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 issued 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;
• 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;
• Completing the divestiture of CNG International Corporation;
• 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 energy 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;
• Changing rating agency requirements;
• 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;
• Unanticipated changes in operating expenses and capital expenditures;
• Employee workforce factors, including collective bargaining agreements and labor negotiations 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.

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CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

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 SEC.

In general, management's discussion of the Company's results of operations focuses on the contributions of its operating segments. The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on the three primary operating segments: Delivery, Energy and Exploration and Production. For additional information on the Company's operating segments, see Note 15 to the Consolidated Financial Statements.

See MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for a detailed discussion of the Company's critical accounting policies. These policies include the accounting for risk management contracts at fair value, accounting for gas and oil operations and accounting for regulated operations.

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.

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS
(Continued)

Net income in the second quarter of 2002 was $104 million, an increase of $31 million, as compared with net income of $73 million in the same quarter of 2001. Net income was $305 million for the six months ended June 30, 2002, representing an increase of $67 million, as compared to $238 million in the comparable period of 2001. The quarterly and six-month results of 2002 reflected higher gas and oil production, attributable primarily to the addition of DOTEPI, and lower regulated service revenue, as compared to the same periods in 2001.

Segment Results

Due to the regulated nature of the Delivery segment and the transmission business of the Energy segment, 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.

Operating Results-Second Quarter and Six Months Ended June 30, 2002

The Company's Delivery segment contributed $9 million to net income in the second quarter of 2002, as compared to $2 million in the same quarter of 2001. The Delivery segment contributed $94 million to net income for the six months ended June 30, 2002, as compared to $98 million for the same period in 2001. For the combined regulated gas sales and gas transport service activities, revenue decreased by $73 million and $525 million for the second quarter and six months ended June 30, 2002, as compared to 2001. The decrease in revenue was substantially offset by decreases of $57 million and $483 million in purchased gas costs for the respective periods. As compared to the second quarter of 2001, the lower regulated gas sales revenue and purchased gas costs in the second quarter of 2002 reflected lower natural gas prices, partially offset by higher volumes due to comparably cooler weather early in the quarter. The heating degree-days in the second quarter of 2002 were 24 percent higher than in the comparable qua rter of 2001. For the six months ended June 30, 2002, the lower regulated gas sales revenue reflected both lower natural gas prices and lower volumes, as compared to the six-month period in 2001. The lower regulated gas sales volumes reflect customers opting for alternate suppliers under customer choice programs and the comparably milder weather experienced in the first quarter of 2002 in Delivery's service territories. The heating degree-days were 6 percent lower in the six-month period ended June 30, 2002, as compared to the same period in 2001. The change in status of regulated customers from sales to transport under the customer choice programs resulted in $6 million and $22 million increases in gas transportation revenue in the second quarter and six months ended June 30, 2002, as compared to 2001. Approximately 62,000, or 6 percent of the sales customers migrated to the transport service from the comparable period in 2001.

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Total throughput for the Delivery segment was higher in the second quarter of 2002 and lower for the six months ended June 30, 2002, as compared to the same periods in 2001. The quarterly results reflected higher volumes in both sales and transport for residential and commercial customers, as compared to the quarter ended June 30, 2001. The higher sales volumes reflected cooler weather in the second quarter of 2002. The six-month results reflected lower sales volumes, but higher volumes transported, for residential and commercial customers, as in the comparable six-month period in 2001. The lower sales volumes for the first six months of 2002, as compared to the six-month period in 2001 reflected milder weather experienced in the first quarter of 2002. Higher transport volumes in both quarterly and six-month periods of 2002 were due primarily to the migration of residential and commercial customers from sales to transport service under customer choice programs. Total deliveries to indu strial customers were 25 billion cubic feet (bcf) and 54 bcf in the second quarter and six months ended June 30, 2002, respectively, as compared to 23 bcf and 55 bcf in the same periods of 2001. The decrease in the six-month period of 2002, as compared to 2001, was due primarily to lower levels of industrial activity in the first quarter of 2002 and the bankruptcy reorganization by a major steel-producing customer.

Energy Segment

Although nonregulated gas sales volumes were higher in the second quarter of 2002, the average realized price per thousand cubic feet (mcf) was $3.80, a decrease of $0.19 per mcf, as compared to the comparable quarter in 2001, resulting in a $12 million decrease in revenue. The higher sales volumes in 2002 reflected an increase in heating degree-days, as compared to the same period in 2001. Nonregulated gas sales volumes were lower in the six months ended June 30, 2002, reflecting milder weather in the first quarter of the comparable periods. Furthermore, the average sales price realized was $3.72 per mcf, reflecting a $2.09 decrease from the comparable period in 2001. As a result, nonregulated gas sales revenue decreased by $250 million in the six months ended June 30, 2002, as compared to the same period in 2001. Purchased gas costs decreased $17 million and $255 million for the quarter and six months ended June 30, 2002, as compared to 2001. The decrease in nonregulated gas sales revenue in the quarter-to - -quarter and year-to-year comparisons reflected the effect of significantly higher sales prices in the comparable periods of 2001.

PAGE 21

The Company's Exploration and Production segment contributed $59 million and $111 million to net income for the quarter and six months ended June 30, 2002, as compared to $46 million and $75 million in the same periods of 2001. The quarterly and six-month results of 2002 reflected higher gas and oil production as compared to the same periods in 2001, attributable primarily to the additional production provided by DOTEPI. For a discussion of the Company's acquisition of DOTEPI, see Note 5 to the Consolidated Financial Statements. The increased gas and oil production revenue for the quarter and six months ended June 30, 2002 was partially offset by higher operating costs, reflecting the additional production costs of DOTEPI. The higher operating costs included increases of $40 million and $78 million in depreciation, depletion and amortization and $26 million and $40 million in operation and maintenance expenses for the quarter and six months ended June 30, 2002, respectively.

Corporate and Other Segment

Net loss for the Corporate and Other segment was $4 million and $5 million for the quarter and six months ended June 30, 2002, respectively, as compared to $7 million and $30 million, respectively, for the comparable periods in 2001. The decrease in net loss in the quarter ended June 30, 2002 resulted from lower interest expense. The decrease in net loss in the six months ended June 30, 2002 resulted from higher equity earnings ($4 million), lower interest expense ($7 million) and the $14 million cumulative effect of adopting SFAS No. 133 in 2001.

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For a discussion of matters that may affect the Company and its future operations, see Future Issues and Outlook in Management's Discussion & Analysis in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

In 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. See Notes 3 and 4 to the Consolidated Financial Statements for discussion of the impact of adopting these new standards.

Pending Acquisition

In July 2002, a subsidiary of the Company reached an agreement to purchase Cove Point LNG Limited Partnership (Cove Point) from The Williams Companies. Cove Point's assets include a liquefied natural gas import facility located near Baltimore, Maryland. Under the terms of the agreement, the Company will acquire Cove Point for approximately $217 million, plus an estimated $18 million to $28 million for additional capital expenditures expected to be incurred before closing. The Company expects to incur additonal capital expenditures of approximately $70 million to $80 million through 2003. The transaction is expected to close in September 2002, subject to approval under United States anti-trust laws. No other regulatory approvals are needed.

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CONSOLIDATED NATURAL GAS COMPANY

PART II - OTHER INFORMATION

ITEM 1. 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 imposed upon or agreed to by the Company, or permits issued by various local, state and federal agencies for the construction or operation of facilities. From time to time, there also may be administrative proceedings on these matters pending. 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.

The matters discussed in this item may contain "forward looking statements" as described in the introductory paragraphs of Part I, Item 2 of this Form 10-Q. See Cautionary Statements Regarding Forward-Looking Information in Part I, Item 2 for discussion of various risk factors and uncertainties that may affect the future of the Company.

In July 2002, Greenbrier Pipeline Company, LLC submitted its application for a FERC certificate to construct and operate its proposed Greenbrier Pipeline. The 280-mile Greenbrier Pipeline is planned to originate in Kanawha County, West Virginia and extend to Granville County, North Carolina. The Company owns 67 percent of Greenbrier Pipeline Company, LLC, with Piedmont Natural Gas owning the remaining 33 percent. The FERC certificate is expected to be granted by the third quarter of 2003.

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