SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q
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X    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003

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 whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act). Yes        No   X    

At April 30, 2003, the latest practicable date for determination, 100 shares of common stock, without par value, of the registrant were outstanding.

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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, 2002 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, 2002 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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The Company manages its daily operations through three primary operating segments: Delivery, Energy and Exploration & Production. In addition, the Company reports its corporate and other functions as a segment. Assets remain wholly-owned by the Company's legal subsidiaries. See Note 15.

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

Note 2.     Significant Accounting Policies

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, 2002.

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 March 31, 2003, and its results of operations and cash flows for the three-month periods ended March 31, 2003 and 2002.

The Consolidated Financial Statements represent the accounts of the Company and its subsidiaries, with intercompany transactions eliminated in consolidation. The Company follows the equity method of accounting for investments with less than or equal to a 50 percent interest in partnerships and corporate joint ventures when the Company is able to significantly influence the financial and operating policies of the investee.

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 Consolidated 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, 2002 for a 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 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

Note 3.     Accounting Change

Effective January 1, 2003, the Company adopted 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.

The Company has identified certain asset retirement obligations that are subject to the standard. These obligations are primarily associated with the abandonment of certain natural gas pipelines and the dismantlement and restoration activities for its gas and oil wells and platforms. In addition, the Company has identified asset retirement obligations related to the removal of equipment at and the closure of approximately 2,300 gas storage wells associated with the Company's underground natural gas storage network. However, due to the indeterminate timing for future asset retirement activities related to these gas storage wells, the fair value of such asset retirement obligations cannot be reasonably estimated and thus is not reflected in the Company's Consolidated Financial Statements.

Under SFAS No. 143, asset retirement obligations will be recognized at fair value, as incurred, and capitalized as part of the cost of the related tangible long-lived assets. Under the present value approach used to estimate the fair value of asset retirement obligations, accretion of the liabilities due to the passage of time will be recognized as an operating expense. Prior to the adoption of SFAS No. 143, the Company's accounting and reporting practices for future dismantlement and restoration activities for its gas and oil wells and platforms recognized such costs as a component of depletion, with recognized amounts included in accumulated depreciation.

On January 1, 2003, the Company implemented SFAS No. 143 and recognized an after-tax loss of $5 million, representing the cumulative effect of a change in accounting principle. The impact of adopting SFAS No. 143, other than the cumulative effect of a change in accounting principle, for the three months ended March 31, 2003 was not material. Under the Company's accounting policy prior to the adoption of SFAS No. 143, $84 million had previously been accrued for future asset removal costs, primarily related to future dismantlement and restoration activities associated with the Company's gas and oil wells and platforms. Such amounts are included in the accumulated provision for depreciation, depletion and amortization as of December 31, 2002. With the adoption of SFAS No. 143, the Company calculated its asset retirement obligations to be $198 million. In recording the cumulative effect of the accounting change, the Company recognized the increase attributable to the re-measurement of asset retirement obligation s and reclassified the previously recorded amount from the accumulated provision for depreciation, depletion and amortization to other noncurrent liabilities. The cumulative effect of the accounting change also reflected a $109 million increase in property, plant and equipment for capitalized asset retirement costs and a $3 million increase in the accumulated provision for depreciation, depletion and amortization, representing the depreciation of such costs through December 31, 2002.

See Note 11 for additional disclosures regarding asset retirement obligations.

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Amendment of SFAS No. 133

On April 30, 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is evaluating SFAS No. 149 and has not yet determined the impact of adopting its provisions.

Other SFAS No. 133 Guidance

In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the DIG's C11 guidance, relates to contracts with pricing terms that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has one power sales contract that is subject to the guidance addressed in the request for reconsideration. On April 25, 2003, the FASB issued a proposal, Statement 133 Implementation Issue No. C20, Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Scope Exception, to clarify the guidance applicable to these circumstances. The proposal is subject to public comment until May 30, 2003. Pending evaluation of the proposal and the final guidanc e ultimately issued by the FASB, the Company has not determined the impact of this clarification on its results of operations or financial position.

Note 5.    Operating Revenue

The Company's operating revenue consists of the following:

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The Company recognized costs and related liabilities associated with employee severances and the abandonment of leased office space no longer needed in 2001. The change in these liabilities during the three-month period ended March 31, 2003 is presented below:

For additional information, see Note 7 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Note 7.     Comprehensive Income

For the three months ended March 31, 2003 and 2002, the Company recognized total comprehensive income (loss) of $109 million and $(22) million, respectively. Other comprehensive income for the three-month periods ended March 31, 2003 and 2002 related primarily to the effective portion of the changes in fair value of derivatives designated as hedging instruments in cash flow hedges (see Note 8).

Note 8.     Derivative Instruments and Hedge Accounting

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The following table presents selected information related to cash flow hedges included in Accumulated Other Comprehensive Income (AOCI) in the Consolidated Balance Sheet at March 31, 2003:

The actual amounts that will be reclassified to earnings during the next 12 months will vary from the expected amounts presented above as a result of changes in market prices and interest rates. The effect of 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 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, 2002, 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. 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 March 31, 2003, 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. Due to the volatility of gas and oi l prices, it is reasonably possible that for some quarters, the Company may satisfy the ceiling test using hedge-adjusted prices, whereas the use of period-end market prices without the effects of hedging could result in an impairment charge.

In March 2003, the Company added a $50 million 6-month revolving credit facility that terminates in September 2003. This credit facility and the Company's existing $500 million 364-day revolving credit facility that terminates in August 2003 are used to support the issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by the Company in its risk management strategies for its gas and oil production. At March 31, 2003, outstanding letters of credit under these facilities totaled $536 million. The Company expects to renew the $500 million 364-day revolving credit facility prior to its maturity in August 2003.

Shelf Registration

At March 31, 2003, 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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Note 11.    Asset Retirement Obligations

The following table describes the changes to the Company's asset retirement obligations during the three months ended March 31, 2003:

Had the provisions of SFAS No. 143 been adopted on January 1, 2000, the Company's net income would have been as follows:

Had the provisions of SFAS No. 143 been adopted as of January 1, 2000, the asset retirement obligations would have been as follows:

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In accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company will continue its practice of accruing for future costs of removal for its cost-of-service rate regulated gas and utility assets, even if no legal obligation to perform such activities exists. At March 31, 2003 and December 31, 2002, the Company's accumulated depreciation, depletion and amortization included $214 million and $221 million, respectively, representing the estimated future cost of such removal activities.

Note 12.    Commitments and Contingencies

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, 2002, nor have any significant new matters arisen during the three-month period ended March 31, 2003.

Guarantees, Letters of Credit and Surety Bonds

FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others-An Interpretation of FASB Statements No. 5, 57 and 107 (FIN No. 45), requires disclosures related to the issuance of certain types of guarantees. It also requires the recognition of liabilities for the fair value of guarantees issued or modified after December 31, 2002.

For purposes of consolidated financial statements, guarantees issued by a parent on behalf of its consolidated subsidiary, guarantees issued by a consolidated subsidiary on behalf of its parent or guarantees issued by a consolidated subsidiary on behalf of a sister consolidated subsidiary are not subject to the FIN No. 45 disclosure and recognition requirements. Nevertheless, the Company is providing the following information about the guarantees that it and certain of its subsidiaries may issue in the ordinary course of business to provide financial or performance assurance to third parties on behalf of certain subsidiaries. On behalf of consolidated subsidiaries, as of March 31, 2003, the Company had issued $1.3 billion of guarantees: $952 million of guarantees to support commodity transactions of subsidiaries, $288 million of guarantees for subsidiary debt and $36 million for guarantees supporting other agreements of subsidiaries. The Company had also purchased $42 million of surety bonds and authorized t he issuance of standby letters of credit by financial institutions of $536 million. The Company enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. To the extent a liability, subject to a guarantee, has been incurred by a consolidated subsidiary, that liability is included in the Company's Consolidated Financial Statements. The Company believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries' obligations.

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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. At March 31, 2003, the Company held no collateral made available by its counterparties. Presented below is a summary of the Company's gross credit exposure as of March 31, 2003. The amounts presented exclude accounts receivable for gas sales and services, regulated gas transmission services and the Company's provision for credit losses. See Note 23 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a discussion of the nature of the Company's credit risk exposures.

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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 March 31, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $76 million and $55 million and derivative liabilities with Dominion affiliates of $60 million and $48 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of these affiliate derivative contracts, are included in the balance of AOCI in the Company's Consolidated Balance Sheets. Net realized gains of $5 million and net realized losses of $20 million associated with commodity derivative contracts with Dominion affiliates were recognized in the Company's income from operations during the first quarter of 2003 and 2002, respectively. See Note 8 for further discussion of the Company's hedging activities.

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 first quarter of 2003 and 2002 was approximately $43 million and $39 million, respectively. The cost of services provided by the Company to Dominion Services and other Dominion affiliates in the first quarter of 2003 and 2002 was approximately $3 million and $1 million, respectively.

Effective March 1, 2003, a consolidated Dominion money pool was formed and the existing CNG money pool was terminated pursuant to a SEC order. Outstanding balances under the CNG money pool and certain borrowings from Dominion pursuant to a short-term demand note (Demand Note) were converted to Dominion money pool borrowings on March 1, 2003. At March 31, 2003, net outstanding borrowings under the Dominion money pool totaled $542 million. At March 31, 2003 and December 31, 2002, net outstanding borrowings under the Demand Note totaled $59 million and $563 million, respectively. During the first quarter of 2003, the Company incurred approximately $3 million in interest charges related to these borrowings.

The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.

The Company had entered into an agreement with a Dominion subsidiary, Dominion Equipment, Inc., in order to develop, construct, finance and lease a new power generation facility in Armstrong, Pennsylvania. For a detailed discussion about this power generation facility lease commitment, see Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The cost of management and engineering services provided by another Dominion affiliate related to the Armstrong power station was not material during the first quarter of 2003.

For additional information on related party transactions, see Note 24 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

Note 15.    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 business lines:

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

The Energy segment manages the Company's retail marketing of energy services in nonregulated markets, gas transmission pipeline operations, certain gas production and storage operations and the Company's nonregulated sales of electricity.

The Exploration & Production segment manages the Company's onshore and offshore gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deep-water areas of the Gulf of Mexico.

In addition, the Company reports its corporate and other functions as a segment. The Corporate and Other segment includes activities of CNG International Corporation (CNG International) and other minor subsidiaries, costs of the Company's corporate and other functions and other expenses not allocated to the operating segments for the three months ended March 31, 2003, including:

• Severance costs of $7 million related to the Company's workforce reductions in the first quarter of 2003; and
• A $5 million loss, net of income taxes, associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 in the first quarter of 2003 (see Note 3).

For a detailed description of the Company's operating segments, see Notes 1 and 25 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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Introduction

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

Risk Factors and Cautionary Statements That May Affect Future Results

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

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

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

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

The Company is subject to complex government regulation that could adversely affect its operations-The Company's operations are subject to extensive regulation and require numerous permits, approvals and certificates from federal, state and local governmental agencies. The Company must also comply with environmental legislation and other regulations. Management believes the necessary approvals have been obtained for the Company's existing operations and that its business is conducted in accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, may require the Company to incur additional expenses.

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Costs of environmental compliance, liabilities and litigation could exceed the Company's estimates-Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment and monitoring obligations. In addition, the Company may be a responsible party for environmental clean up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

The use of derivative instruments could result in financial losses-The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. For additional information concerning derivatives, see Management's Discussion and Analysis of Results of Operations-Market Rate Sensitive Instruments and Risk Management and Notes 2 and 11 to the Consolidated Financial Statements i n the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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

An inability to access financial markets could affect the execution of the Company's business plan-The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows from its operations. Management believes that the Company will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company's control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to the Company's credit ratings. Restrictions on the Company's ability to access financial markets may affect its ability to execute its business plan as scheduled.

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Changing rating agency requirements could negatively affect the Company's growth and business strategy-As of May 1, 2003, the Company's senior unsecured debt is rated BBB+, stable outlook, by Standard & Poor's, and A3, negative outlook, by Moody's. Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company's credit ratings by either Standard & Poor's or Moody's could increase its borrowing costs and adversely affect operating results.

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

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

As of March 31, 2003, there have been no significant changes with regard to critical accounting policies as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The policies disclosed included the accounting for: risk management contracts at fair value; gas and oil operations; impairment testing; and regulated operations.

Results of Operations

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

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Net income for the first quarter of 2003 increased $46 million, as compared with net income in the same quarter of 2002. The increase reflected higher regulated gas sales and distribution service revenue, nonregulated gas and electric sales revenue and gas and oil production revenue. The higher operating revenue was partially offset by the effects of higher operating expenses, principally in purchased gas costs, electric fuel and energy purchases, other operations and maintenance expense and other taxes, as compared to the same period in 2002. The 2003 quarterly results also reflected an after-tax loss of $5 million due to the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations (see Note 11 to the Consolidated Financial Statements).

Total operating revenue increased $592 million in the first quarter of 2003, as compared to the same quarter in 2002. Regulated gas sales and distribution service revenue increased $244 million, reflecting the impact of the pass-through of higher purchased gas costs and comparably colder weather. Nonregulated gas and electric sales revenue increased $210 million and $39 million, reflecting primarily higher average sales prices and higher retail energy sales, respectively. Gas and oil production revenue was $73 million higher in the first quarter of 2003, resulting primarily from higher average realized prices, partially offset by the effect of natural production declines.

Total operating expenses increased $501 million in the first quarter of 2003, when compared to the same quarter in 2002. Purchased gas costs increased $384 million, due primarily to higher average prices. Electric fuel and energy purchases were $31 million higher, resulting primarily from higher volumes associated with the Company's nonregulated energy marketing operations. Other operations and maintenance expense increased $46 million, reflecting lower pension credits, higher provision for uncollectible accounts related to higher customer receivables as a result of colder weather, higher operating and increased production costs associated with the Company's successful ongoing drilling and well-maintenance programs and severance costs related to workforce reductions. Other taxes, due primarily to gross receipts and severance taxes, increased $22 million.

Segment Results

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

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The Company's Delivery segment contributed $101 million to net income in the first quarter of 2003, as compared to $85 million in the same quarter of 2002. The quarterly results for the Delivery segment reflected higher regulated gas sales and distribution service revenue, partially offset by the effects of higher purchased gas costs, other operations and maintenance expense and other taxes, as compared to the same period in 2002.

Total operating revenue of the Delivery segment increased $236 million in the first quarter of 2003, as compared to the same quarter in 2002. Regulated gas sales revenue increased $211 million, reflecting a $117 million increase due primarily to the pass-through of higher purchased gas costs and a $94 million increase due to higher sales volumes. The higher sales volumes reflected a $105 million increase for the comparably colder weather experienced in the Company's retail service areas, partially offset by a $11 million decrease for the migration of customers, opting for alternate suppliers, from regulated gas sales to transportation service. The heating degree-days were 25 percent higher in the franchise service areas in the first quarter of 2003, as compared to the same period in 2002. Average sales rates for all customer groups increased, reflecting the pass-through of higher purchased gas costs. Gas transportation revenue increased $19 million, attributable primarily to higher sales volumes, resulting l argely from the colder weather.

Total operating expenses of the Delivery segment in the first quarter of 2003 increased $205 million, as compared to the same quarter in 2002. Purchased gas costs increased $182 million, reflecting higher purchased gas prices of $118 million, due primarily to higher overall market prices, and higher volume requirements of $64 million, attributable primarily to colder weather. Other operations and maintenance expense increased $10 million, including lower pension credits of $5 million and a $4 million increase in the provision for uncollectible accounts in connection with higher customer receivables as a result of colder weather. Other taxes increased $12 million, resulting primarily from higher gross receipts tax.

In the first quarter of 2003, gas sales volumes increased 15 billion cubic feet (bcf), while volumes transported increased 14 bcf, as compared to the same period in 2002. The higher volumes in both sales and transport for residential and commercial customers reflected higher heating degree-days. Total throughput to industrial customers was 32 bcf in the first quarter of 2003, as compared to 29 bcf in the same quarter of 2002.

Energy Segment

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The Company's Energy segment contributed $74 million to net income in the first quarter of 2003, as compared to $65 million in the same period of 2002. The quarterly results for the Energy segment reflected higher nonregulated gas and electric sales revenue and gas transportation and storage revenue, offset by the effects of higher operating costs, principally in purchased gas costs and electric fuel and energy purchases, as compared to the same period in 2002.

Total operating revenue of the Energy segment increased $249 million in the first quarter of 2003, as compared to the same period of 2002. Nonregulated gas sales revenue increased $201 million from field services and retail energy marketing operations, reflecting higher sales prices of $189 million and higher sales volumes of $12 million. Nonregulated electric sales revenue increased $34 million, reflecting $27 million of retail energy sales resulting primarily from customer growth and $7 million of revenue generated from the Company's power generation facility in Armstrong, Pennsylvania. Gas transportation and storage revenue increased $13 million, primarily reflecting higher gas transportation revenue resulting from higher throughput volumes and the liquefied natural gas operations of Cove Point, acquired in September 2002, partially offset by the effect of lower rates. Revenue from natural gas by-products sales reflected higher average sales prices for all by-products, partially offset by the effect of lo wer sales volumes.

Total operating expenses of the Energy segment in the first quarter of 2003 increased $232 million from the comparable quarter in 2002. The increase in operating expenses was due primarily to purchased gas costs and electric fuel and energy purchases, partially offset by lower overall other operations and maintenance expense. Purchased gas costs increased $205 million, reflecting the impact of higher prices associated with field services, retail energy marketing and gas transmission operations, partially offset by lower volumes as part of retail gas marketing activities resulting from customer attrition. Electric fuel and energy purchases increased $28 million, resulting primarily from higher volumes purchased associated with the Company's nonregulated energy marketing operations.

________________

bbl = barrel

bcf = billion cubic feet

mcf = thousand cubic feet

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The Company's Exploration & Production segment contributed $84 million to net income in the first quarter of 2003, as compared to $52 million in the same quarter of 2002. The quarterly results for the Exploration & Production segment reflected higher gas and oil production revenue, partially offset by the effects of higher purchased gas costs, liquids, pipeline capacity and other purchases, other operations and maintenance expense and other taxes, as compared to the same quarter in 2002.

Total operating revenue of the Exploration & Production segment increased $129 million in the first quarter of 2003, as compared to the same quarter in 2002. Gas and oil production revenue increased $99 million, including higher gas production revenue of $95 million, reflecting higher average realized prices of $80 million and higher sales volumes of $15 million, and higher oil production revenue of $4 million, attributable to higher average realized prices of $8 million, partially offset by the effect of lower sales volumes of $4 million. The higher gas and oil production levels were primarily attributed to the Company's successful ongoing drilling programs, partially offset by the effect of natural production declines. Revenue from gas and oil brokering activities increased $6 million, reflecting higher prices realized from brokering activities, partially offset by the effect of lower transaction volumes.

Total operating expenses for the first quarter of 2003 increased $77 million over the comparable quarter of 2002. Higher operating costs included higher commodity prices of $24 million and $11 million in purchased gas costs and purchased oil costs (reported in liquids, pipeline capacity and other purchases), respectively, in connection with brokering activities, $30 million in other operations and maintenance expense, reflecting higher overall operating and production costs as a result of the Company's successful ongoing drilling and well-maintenance programs, and $9 million in other taxes, primarily due to higher severance taxes resulting from increased production and higher commodity prices for gas and oil.

Corporate and Other Segment

Overview of Corporate and Other Segment Results-First Quarter 2003 vs. First Quarter 2002

The net loss for the Corporate and Other segment was $12 million in the first quarter of 2003, as compared to a net loss of $1 million for the same quarter in 2002. The increase in net loss reflected $7 million ($4 million after taxes) of severance costs related to workforce reductions as well as lower equity investment earnings. In addition, the net loss included a $5 million after-tax loss due to the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143.

As of March 31, 2003, there have been no significant changes with regard to contractual obligations as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to the Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Outlook in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Regulated Gas Distribution Operations

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

Greenbrier Pipeline

In April 2003, Greenbrier Pipeline Company, LLC received final FERC approval to construct and operate the Greenbrier Pipeline. The Greenbrier Pipeline will originate in Kanawha County, West Virginia and extend through southwest Virginia to Granville County, North Carolina. The Company owns 67 percent of Greenbrier Pipeline Company, LLC, with Piedmont Natural Gas owning the remaining 33 percent.

For a discussion of matters that may affect the Company and its future operations, see Future Issues and Outlook in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

On April 30, 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which, in general, will be applied prospectively to new contracts, contract modifications and hedging relationships designated after June 30, 2003. See Note 4 to the Consolidated Financial Statements for a discussion of the impact of adopting SFAS No. 149 as well as information regarding certain other standard-setting activities.

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Senior management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures during the month of April and early May of 2003. Based on this evaluation process, the Chief Executive Officer and Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective. Since that evaluation process was completed, there have been no significant changes in internal controls or in other factors that could significantly affect these controls.

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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 Dominion and its subsidiaries, 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. See Future Issues in Management's Discussion and Analysis and Results of Operations for discussion on various regulatory proceedings to which the Company and its subsidiaries are a party.

In March 2003, Triad Energy Resources Corporation and other parties filed a class action antitrust suit against a number of defendants, including Cove Point Limited Partnership, an affiliate of the Company, and Virginia Electric and Power Company, a subsidiary of Dominion, in the United States District Court for the District of Columbia. The complaint seeks compensatory damages for alleged violations of the Sherman Act and tortious interference with contractual and business relationships as a result of activities involving the storage and transportation of natural gas. No trial date has been set. The outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

In l999, a class action was filed by Quinque Operating Co. and other parties against approximately 300 defendants, including the Company and three 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. Quinque Operating Co. dropped out of the case and Will Price, a gas royalty owner based in Kansas, assumed the lead plaintiff's role. The defendants' motion to deny class certification was granted in April 2003. Plaintiffs have until June 2003 to decide whether to proceed without class certification or re-file individual complaints against a smaller number of defendants.

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There were no reports on Form 8-K filed during the quarter ended March 31, 2003.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

I, Thos. E. Capps, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

I, Thomas N. Chewning, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and