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 June 30, 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 July 31, 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.

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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.

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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 16.

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 June 30, 2003, its results of operations for the three and six months and cash flows for the six months ended June 30, 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.

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.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

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

Asset Retirement Obligations

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.

See Note 12 for additional disclosures regarding asset retirement obligations.

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Consolidation of Variable Interest Entities

As described in Note 4 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, in January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46 addresses consolidation by business enterprises of entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. A description of the Company's involvement with variable interest entities and the expected impact of adopting the provisions of FIN 46 follows:

As previously discussed 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, the Company entered into agreements with another Dominion subsidiary (the lessor) in order to finance and lease a power generation facility. Under existing accounting guidance, neither the project assets nor related debt are reported on the Company's Consolidated Balance Sheets. Under FIN 46, the lessor is considered a variable interest entity and the Company has been determined to be the primary beneficiary of the portion of the lessor that includes the generation facility assets and related debt. The Company will therefore consolidate that portion beginning July 1, 2003, which will result in an additional $227 million in net property, plant and equipment and $234 million of related debt.

As described in Note 17 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, the Company established Dominion CNG Capital Trust I (the Trust) which sold trust preferred securities to third party investors. The Company received the proceeds from the sale of the trust preferred securities in exchange for junior subordinated notes issued by the Company to be held by the Trust. Under existing accounting guidance, the Company consolidates the Trust in the preparation of its Consolidated Financial Statements because it has a majority voting interest in the Trust. Under FIN 46, the Trust is considered a variable interest entity. Based on the Trust structure as of July 1, 2003, the Company is not considered the primary beneficiary of the Trust and thus will cease consolidating the Trust beginning on July 1, 2003. Under these circumstances, the Company's Consolidated Balance Sheets will no longer reflect the trust preferred s ecurities, but instead will report the junior subordinated instruments held by the Trust as long-term debt. The Company is currently evaluating changes to the Trust structure that, if implemented, could possibly result in a determination that the Company is the primary beneficiary of the Trust, thus requiring the Company to resume the consolidation of the Trust in the preparation of its Consolidated Financial Statements. If the Trust were to be consolidated in periods subsequent to July 1, 2003, the trust preferred securities would be presented as liabilities, as described under Liabilities and Equity Classification section below.

The Company will record an after-tax charge to net income of approximately $4 million in the third quarter of 2003 for the initial adoption of FIN 46. This adjustment will be recognized on July 1, 2003 as the cumulative effect of a change in accounting principle.

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In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The standard requires an issuer to classify and measure certain freestanding financial instruments with characteristics of both liabilities and equity as a liability if that financial instrument embodies an obligation requiring the issuer to redeem the financial instruments by transferring its assets. Under this standard, the trust preferred securities would be reported as liabilities. However, as described under the Consolidation of Variable Interest Entities section above, the consolidation of the underlying trust must first be evaluated under FIN 46 before application of this Statement.

On April 30, 2003, the 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, Accounting for Derivative Instruments and Hedging Activities. 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 the potential impact of SFAS No. 149 on its results of operations and financial positio n.

Other SFAS No. 133 Guidance

In connection with the January 2003 Emerging Issues Task Force meeting, 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 a contract's pricing terms that contain 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 subject to this guidance. On June 25, 2003, the FASB issued Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of 'Not Clearly and Closely Related' in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature, to clarify the guidance applicable to these circumstances. Under C20, criteria are established to determine if the price adjustment is not clearly and closely related to the underlying asset being purchased or sold u nder the contract, including whether the price adjustment is extraneous or disproportionate to the fair value of the underlying asset or direct component thereof. Under C20, the assessment should include both qualitative and quantitative considerations and should be performed only at inception of the contract. The provisions of C20 should be applied prospectively for all new and existing contracts beginning the first fiscal quarter after July 10, 2003. For any contracts that do not satisfy the superseded C11 guidance at the time of the adoption of C20, such contract would be recorded at fair value with the change being reported as the cumulative effect of a change in accounting principle. The Company has not completed its assessment of this guidance.

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As described in Note 13 to Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, the Company adopted SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002. SFAS No. 142 provides accounting and reporting requirements for goodwill and other intangible assets, including initial recognition and measurement, amortization and review for and measurement of impairment. In addition, accounting guidance regarding the identification, initial recognition and measurement of goodwill and other intangible assets arising from business combinations is contained in SFAS No. 141, Business Combinations, which generally became effective for the Company on July 1, 2001. These new standards emphasize a more precise evaluation of intangible assets than required under previous accounting rules, with the intended result being more assets classified as intangible assets rather than as goodwill or tangible assets. Upon adoption of these new sta ndards, the Company identified and separately classified on its Consolidated Balance Sheets, intangible assets, other than goodwill, consisting primarily of software and software licenses.

Companies with gas and oil exploration and production operations have become aware that a question has arisen about whether contractual mineral rights should be classified as intangible assets rather than tangible assets on the balance sheet as a result of SFAS Nos. 141 and 142. As 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 prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, including mineral interests, as well as exploration and development costs are capitalized into cost pools, which are amortized on a unit-of-production basis. These cost pools are currently classified as property, plant and equipment on the Consolidated Balance Sheets. If, as a result of the resolution of this issue, reclassification of the costs associated with mineral righ ts is required, the Company's net intangible assets would increase and its net property, plant and equipment would decrease. The Company is in the process of identifying the total cost of its contractual mineral rights currently included in property, plant and equipment and related accumulated amortization. While resolution of this issue may affect the balance sheet classification of these assets, including the reclassification of amounts for previously reported periods, there would be no impact on the Company's results of operations or cash flows.

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 six months ended June 30, 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 8.     Comprehensive Income (Loss)

The following table presents total comprehensive income (loss):

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The following table presents selected information related to cash flow hedges included in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet at June 30, 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 Accumulated Other Comprehensive Income 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.

Note 10.    Ceiling Test

As 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 anticipated 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 June 30, 2003, approximately 17 percent of the anticipated production is hedged. Although the use of hedge-adjusted prices produced a lower valuation at June 30, 2003 than would have resulted from the use of period-en d market prices, there was no impairment under either calculation. Due 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 period-end market prices without the effects of hedging could result in an impairment charge.

Note 11.    Significant Financing Transactions

Dominion, Virginia Electric and Power Company (Virginia Power) and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion. In May 2003, Dominion, Virginia Power and the Company entered into a joint credit facility that allows aggregate borrowings of up to $1.25 billion. This credit facility replaced the $1.25 billion 364-day credit facility that matured during the second quarter of 2003. In May 2002, Dominion, Virginia Power and the Company entered into a $750 million 3-year revolving credit facility that terminates in May 2005. The joint credit facilities will be used for working capital; as support for the combined commercial paper programs of Dominion, Virginia Power and the Company; and other general corporate purposes.

The 3-year facility can also be used to support up to $200 million of letters of credit. At June 30, 2003, total outstanding letters of credit supported by the 3-year facility were $199 million as follows: $128 million issued on behalf of the Company and $71 million issued on behalf of other Dominion subsidiaries.

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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 June 30, 2003, outstanding letters of credit under these facilities totaled $550 million. The Company expects to renew the $500 million 364-day revolving credit facility prior to its maturity in August 2003.

At June 30, 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.

Other Debt-Related Matters

See Note 4 for a discussion of the impact of FIN 46 on reported debt amounts, effective July 1, 2003, related to assets leased from another Dominion subsidiary and preferred securities issued by a subsidiary trust.

The following table describes the changes to the Company's asset retirement obligations during the six months ended June 30, 2003:

Had the provisions of SFAS No. 143 been applied for the following periods in 2003 and 2002, the Company's net income would have been as follows:

Had the provisions of SFAS No. 143 been applied for the following periods, the asset retirement obligations would have been as follows:

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As permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company accrues for future costs of removal for its cost-of-service rate regulated gas utility assets, even if no legal obligation to perform such activities exists. At June 30, 2003 and December 31, 2002, the Company's accumulated depreciation, depletion and amortization included $217 million and $221 million, respectively, representing the estimated future cost of such removal activities.

See Note 3 for further discussion of the adoption of SFAS No. 143.

Note 13.    Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments with regard to commitments and contingencies 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 six months ended June 30, 2003.

Lease Commitments

As discussed 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, the Company entered into agreements with another Dominion subsidiary (the lessor) in order to finance and lease a power generation facility.

Effective July 1, 2003, as described in Note 4, the Company will consolidate the portion of a variable interest lessor entity that includes the generation facility assets and related debt, as the Company has been determined to be the primary beneficiary under FIN 46. As a result, beginning July 1, 2003, future minimum lease commitments as previously 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 will be reduced by the following amounts: 2003-$7 million; 2004-$13 million; 2005-$13 million; 2006-$13 million; and 2007-$13 million. Similar amounts for these periods will be recognized as interest expense associated with the newly consolidated debt obligation.

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 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 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 June 30, 2003, the Company had issued $1.3 billion of guarantees: $988 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 the is suance of standby letters of credit by financial institutions of $678 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. However, to the extent a counterparty has fully prepaid transactions by transferring cash or posting letters of credit, the Company has excluded such amounts from its gross credit exposure. In the calculation of net credit exposure, the Company's gross exposure is reduced by collateral, including letters of credit and cash received by the Company and held as margin deposits, made available by counterparties as a result of exceeding agreed-upon credit limits. At June 30, 2003, the Company held no collateral made available by its counterparties. Presented below is a summary of the Company's net credit exposure as of June 30, 2003. The amounts presented exclude accounts receivable for regulated gas sales and services, regulated gas transmission services, amounts recei vable from affiliated companies 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 June 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $80 million and $55 million and derivative liabilities with Dominion affiliates of $84 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. The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

See Note 9 for a 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 for the three months ended June 30, 2003 and 2002 was approximately $39 million and $43 million, respectively, and was approximately $82 million and $81 million for the six months ended June 30, 2003 and 2002, respectively. The cost of services provided by the Company to Dominion Services and other Dominion affiliates for the three months ended June 30, 2003 and 2002 was approximately $2 million and $3 million, respectively, and was approximately $5 million and $4 million for the six months ended June 30, 2003 and 2002, 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 June 30, 2003, net outstanding borrowings under the Dominion money pool totaled $1.2 billion. At June 30, 2003 and December 31, 2002, net outstanding borrowings under the Demand Note totaled $94 million and $563 million, respectively. During the three and six months ended June 30, 2003, the Company incurred approximately $3 million and $6 million, respectively 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 power generation facility in Armstrong, Pennsylvania. For a 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. Effective July 1, 2003, upon adoption of FIN 46, the Company will consolidate the portion of the variable interest lessor entity that includes the power generation facility assets and related debt, see Notes 4 and 13 for discussion and the impact of FIN 46 on the Company.

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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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 and storage operations, certain gas production 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 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 and six months ended June 30, 2003, including:

• a $40 million impairment loss related to certain CNG International investments classified as assets held for sale (see Note 6);
• a $7 million charge of severance costs related to the Company's workforce reductions; and
• a $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 (see Note 3).

For a 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; governmental regulations; cost of environmental compliance; fluctuations in energy-related commodities prices and the effect these could have on the Company's earnings, liquidity position and the underlying value of its assets; 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 ind ustries that are becoming deregulated; completing the divestiture of investments held by CNG International; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation and deflation). 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 governmental regulation that could adversely affect its operations-The Company's operations are subject to extensive regulation and require numerous permits, approvals and certificates from federal, state and local governmental agencies. The Company must also comply with environmental legislation and 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 contracts involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the 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 in 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 August 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 future changes in accounting standards or practices may have on public companies in general or 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 16 to the Consolidated Financial Statements.

As of June 30, 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.

In addition, see Note 4 to the Consolidated Financial Statements for a discussion of other new accounting standards that will be adopted after June 30, 2003 and their impact on the Company.

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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.

Total operating revenue increased $299 million in the second quarter of 2003, as compared to the same quarter in 2002. Regulated gas sales revenue increased $60 million, primarily reflecting the recovery of higher purchased gas costs. Nonregulated gas sales revenue increased $149 million, primarily reflecting higher average prices in retail sales operations. Nonregulated electric sales revenue increased $29 million, primarily reflecting higher volumes in retail sales operations. Gas and oil production revenue increased $53 million, reflecting comparably higher average realized prices for both gas and oil. Other revenue increased $10 million, primarily reflecting higher revenue from natural gas liquids sales.

Total operating expenses increased $273 million in the second quarter of 2003, when compared to the same quarter in 2002. Purchased gas costs increased $184 million, primarily due to higher average prices. Electric fuel and energy purchases were $25 million higher, primarily resulting from increased volumes associated with the Company's nonregulated retail energy marketing operations. Other operations and maintenance expense increased $39 million, reflecting an impairment loss of $22 million related to CNG International's Kauai investment classified as assets held for sale (see Note 6 to the Consolidated Financial Statements), lower pension credits and higher gas and oil production service industry costs. Depreciation, depletion and amortization increased $15 million, primarily due to a comparably higher rate applied to current year's gas and oil production. Other taxes increased $7 million, primarily due to higher severance taxes, resulting from a generally higher commodity price environment.

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Other income decreased $20 million in the second quarter of 2003, as compared to the same quarter in 2002, reflecting an impairment loss of $18 million related to CNG International's equity investment in Australia classified as assets held for sale (see Note 6 to the Consolidated Financial Statements).

Net income for the six months ended June 30, 2003 increased $45 million, as compared to the same period in 2002. The increase in operating revenue reflected higher regulated gas sales and gas transportation revenue, nonregulated gas and electric sales revenue, gas and oil production revenue and other revenue. The increase in operating revenue was partially offset by the effects of higher operating expenses, including purchased gas costs, electric fuel and energy purchases, liquids, pipeline capacity and other purchases, other operations and maintenance expense, depreciation, depletion and amortization and other taxes, as compared to the same period in 2002. The 2003 six-month results also reflected an after-tax loss of $5 million, representing the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 (see Note 12 to the Consolidated Financial Statements).

Total operating revenue increased $891 million for the six months ended June 30, 2003, as compared to the same period in 2002. Regulated gas sales and gas transportation revenue increased $302 million, reflecting the recovery of higher purchased gas costs and the impact of comparably colder weather in the first quarter of 2003. Nonregulated gas sales revenue increased $359 million, primarily reflecting higher average prices in retail sales operations. Nonregulated electric sales revenue increased $68 million, primarily resulting from higher volumes in retail sales operations. Gas and oil production revenue was $126 million higher in the six months ended June 30, 2003, reflecting comparably higher average realized prices for both gas and oil. Other revenue increased $36 million, reflecting a $19 million increase for extracted products and brokered oil sales and a $10 million increase for natural gas liquids sales.

Total operating expenses increased $774 million in the six months ended June 30, 2003, as compared to the same period in 2002. Purchased gas costs increased $568 million, due to increased volume requirements, primarily attributable to colder weather in the first quarter of 2003 and higher average prices. Electric fuel and energy purchases were $56 million higher, primarily resulting from higher volumes associated with the Company's nonregulated retail energy marketing operations. Liquids, pipeline capacity and other purchases increased $18 million, primarily reflecting comparably higher levels of rate recoveries for certain costs of transmission operations in 2003. Other operations and maintenance expense increased $85 million, including an impairment loss of $22 million related to CNG International's Kauai investment classified as assets held for sale (see Note 6 to the Consolidated Financial Statements), lower pension credits, higher provision for uncollectible accounts related to higher customer receivabl es as a result of colder weather in the first quarter of 2003, higher gas and oil production service industry costs and severance costs related to workforce reductions. Depreciation, depletion and amortization increased $18 million, primarily due to a comparably higher rate applied to current year's gas and oil production. Other taxes increased $29 million, primarily due to higher gross receipts and severance taxes. The higher severance taxes were primarily resulting from a generally higher commodity price environment.

Other income decreased $20 million in the six months ended June 30, 2003, as compared to the same period in 2002, reflecting an impairment loss of $18 million related to CNG International's equity investment in Australia classified as assets held for sale. (see Note 6 to the Consolidated Financial Statements).

Due to 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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Total operating revenue of the Delivery segment increased $56 million in the second quarter of 2003, as compared to the same quarter in 2002. Regulated gas sales revenue increased $60 million, primarily due to the recovery of higher purchased gas costs. Lower sales volumes reflected milder weather in the Company's retail service areas and were offset by higher sales volumes due to increased industrial and wholesale activities. Heating degree-days were 9 percent lower in the franchise service areas in the second quarter of 2003, as compared to the same period in 2002. Average rates for all customer groups increased, reflecting the pass-through of higher purchased gas costs. Gas transportation revenue decreased $6 million, primarily attributable to lower sales volumes, resulting from the milder weather and decreased industrial activities.

Total operating expenses of the Delivery segment in the second quarter of 2003 increased $57 million, as compared to the same quarter in 2002. Purchased gas costs increased $59 million, reflecting higher purchased gas prices of $72 million, primarily due to higher overall market prices, partially offset by lower volume requirements of $13 million, primarily attributable to milder weather.

In the second quarter of 2003, gas sales volumes decreased 0.5 billion cubic feet (bcf), while volumes transported decreased 5 bcf, as compared to the same period in 2002. Both gas sales and transport volumes for residential and commercial customers reflected a decrease in volumes attributable to lower heating degree-days. Total throughput to industrial customers was 22 bcf in the second quarter of 2003, as compared to 26 bcf in the same quarter of 2002.

The Delivery segment contributed $106 million to net income in the six months ended June 30, 2003, as compared to $94 million in the same period in 2002. The 2003 six-month results reflected higher regulated gas sales and gas transportation 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.

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Total operating revenue of the Delivery segment increased $292 million in the six months ended June 30, 2003, as compared to the same period in 2002. Regulated gas sales revenue increased $271 million, reflecting higher purchased gas costs of $177 million and higher sales volumes of $94 million. The higher sales volumes reflected a $107 million increase, primarily attributable to comparably colder weather experienced in the Company's retail service areas in the first quarter of 2003, partially offset by a $13 million decrease for the migration of customers opting for alternate suppliers from regulated gas sales to transportation service. Heating degree-days were 17 percent higher in the franchise service areas in the six months ended June 30, 2003, as compared to the same period in 2002. Average rates for all customer groups increased, reflecting the pass-through of higher purchased gas costs. Gas transportation revenue increased $14 million, primarily attributable to higher transport volumes for residential customers, as a result of comparably colder weather in the first quarter of 2003.

Total operating expenses of the Delivery segment in the six months ended June 30, 2003 increased $262 million, as compared to the same period in 2002. Purchased gas costs increased $241 million, reflecting higher purchased gas prices of $286 million, primarily due to increases in gas cost recovery rates and higher overall market prices, and higher volume requirements of $40 million which were primarily attributed to colder weather in the first quarter of 2003. The increase in market prices was largely offset by gas cost deferrals of $85 million, pending recovery through future rates. Other operations and maintenance expense increased $10 million, primarily due to lower pension credits and higher general and administrative expenses. Other taxes increased $9 million, primarily from higher gross receipts taxes.

In the six months ended June 30, 2003, gas sales volumes increased 15 billion cubic feet (bcf), while volumes transported increased 9 bcf, as compared to the same period in 2002. The higher volumes in both sales and transport for residential and commercial customers reflected a higher number of heating degree-days as a result of comparably colder weather in the first quarter of 2003. Total throughput to industrial customers was 54 bcf in the six months ended June 30, 2003, as compared to 55 bcf in the same period in 2002.

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Total operating revenue of the Energy segment increased $199 million in the second quarter of 2003, as compared to the same period in 2002. Nonregulated gas sales revenue increased $158 million from field services and retail energy marketing operations, reflecting higher prices of $103 million and higher volumes of $55 million. Nonregulated electric sales revenue increased $25 million, reflecting $21 million of retail energy sales, primarily resulting from customer growth and $4 million of revenue associated with the Company's power generation facility. Gas transportation and storage revenue increased $5 million, primarily reflecting higher transportation rates, partially offset by lower volumes. Other revenue increased $11 million, reflecting higher revenue from natural gas liquids sales of $8 million, attributable to higher average prices and higher volumes.

Total operating expenses of the Energy segment in the second quarter of 2003 increased $185 million from the comparable quarter in 2002. Purchased gas costs increased $145 million, reflecting the impact of higher prices associated with field services, retail energy marketing and gas transmission operations, partially offset by lower volumes sold in retail gas marketing activities as a result of customer attrition. Electric fuel and energy purchases increased $21 million, primarily resulting from higher volumes purchased for nonregulated retail energy marketing sales. Other operations and maintenance expense increased $14 million, primarily reflecting higher overall operating costs, including the operations of Cove Point , acquired in September 2002, and lower pension credits.

Energy Segment Results-Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

The Energy segment contributed $120 million to net income in the six months ended June 30, 2003, as compared to $105 million in the same period in 2002. The 2003 six-month results reflected higher nonregulated gas and electric sales revenue, gas transportation and storage revenue and other revenue, partially offset by the effects of higher operating costs, including purchased gas costs, electric fuel and energy purchases, liquids, pipeline capacity and other purchases and other operations and maintenance expense, as compared to the same period in 2002.

Total operating revenue of the Energy segment increased $448 million in the six months ended June 30, 2003, as compared to the same period in 2002. Nonregulated gas sales revenue increased $357 million from field services and retail energy marketing operations, reflecting $292 million in higher prices and $65 million in higher volumes. Nonregulated electric sales revenue increased $58 million, reflecting $48 million of retail energy sales primarily resulting from customer growth and $10 million of revenue associated with the Company's power generation facility. Gas transportation and storage revenue increased $18 million, primarily reflecting higher gas transportation rates and the liquefied natural gas operations of Cove Point, acquired in September 2002. Other revenue increased $14 million, reflecting higher revenue from natural gas liquids sales of $10 million, attributable to higher average prices, partially offset by lower volumes.

Total operating expenses of the Energy segment in the six months ended June 30, 2003 increased $417 million from the comparable period in 2002. Purchased gas costs increased $349 million, reflecting the impact of higher prices associated with field services, retail energy marketing and gas transmission operations, partially offset by lower volumes sold in retail gas marketing activities as a resulting of customer attrition. Electric fuel and energy purchases increased $49 million, primarily resulting from higher volumes purchased for nonregulated retail energy marketing sales. Liquids, pipeline capacity and other purchases increased $10 million, primarily reflecting comparably higher levels of rate recoveries for certain costs of transmission operations in 2003. The difference between actual expenses and amounts recovered in the period is deferred, pending future rate adjustments. Other operations and maintenance expense increased $10 million, primarily reflecting higher overall operating costs, including th e gas operations of Cove Point and lower pension credits.

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________________

bbl = barrel
bcf = billion cubic feet
mcf = thousand cubic feet

Total operating revenue of the Exploration & Production segment increased $61 million in the second quarter of 2003, as compared to the same quarter in 2002. Gas and oil production revenue increased $68 million, primarily due to higher average realized prices for both gas and oil, as well as higher gas production volumes. The 2003 revenue from gas and oil brokering activities reflected higher prices realized, offset by lower transaction volumes.

Total operating expenses for the second quarter of 2003 increased $32 million over the comparable quarter of 2002. Higher commodity prices in 2003 have resulted in upward pressure on service industry costs due to increased demand for equipment, labor and services. Such increases were reflected in higher other operations and maintenance expense of $8 million. Depreciation, depletion and amortization increased $14 million, due to a comparably higher rate applied to current year production, reflecting higher finding and development costs. Other taxes increased $11 million, primarily due to higher severance taxes, resulting from a generally higher commodity price environment.

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The Exploration & Production segment contributed $159 million to net income in the six months ended June 30, 2003, as compared to $111 million in the same period in 2002. The 2003 six-month results reflected higher gas and oil production revenue and other revenue, partially offset by the effects of higher purchased gas costs, liquids, pipeline capacity and other purchases, other operations and maintenance expense, depreciation, depletion and amortization and other taxes, as compared to the same period in 2002.

Total operating revenue of the Exploration & Production segment increased $190 million in the six months ended June 30, 2003, as compared to the same period in 2002. Gas and oil production revenue increased $167 million, primarily due to higher average realized prices for both gas and oil, as well as higher gas production volumes. Other revenue increased $19 million, primarily due to higher realized prices for extracted by-products and brokered oil sales.

Total operating expenses for the six months ended June 30, 2003 increased $109 million over the comparable period in 2002. The cost of gas and oil purchased in connection with brokering activities increased $34 million, primarily reflecting higher commodity prices. Higher commodity prices in 2003 have resulted in upward pressure on service industry costs due to increased demand for equipment, labor and services. Such increases were reflected in higher other operations and maintenance expense of $39 million. Depreciation, depletion and amortization increased $18 million, due to a comparably higher rate applied to current year production, reflecting higher finding and development costs. Other taxes increased $19 million, primarily due to higher severance taxes, resulting from a generally higher commodity price environment.

Corporate and Other Segment Results Overview-Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

Net loss for the Corporate and Other segment was $35 million in the six months ended June 30, 2003, as compared to net loss of $5 million for the same period in 2002. The increase in net loss reflected:

• a $40 million ($25 million after-tax) impairment loss related to certain CNG International investments classified as assets held for sale (see Note 6 to the Consolidated Financial Statements);
• a $7 million ($4 million after-tax) charge of severance costs related to workforce reductions, including $4 million, $2 million and $1 million attributable to the segments of Energy, Delivery and Exploration & Production, respectively; and
• a $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 (see Note 3 to the Consolidated Financial Statements) which was attributed to the Energy segment.

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As of June 30, 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.

Future Issues

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

Rate matters

West Virginia-In August 2003, the Company filed an application with the West Virginia Public Service Commission (the West Virginia Commission) to increase its purchased gas cost rate by approximately $31 million on an annualized basis, effective for the period January 1, 2004 through October 31, 2004. The increase is in anticipation of higher purchased gas costs expected for that period. Because the Company's existing rate moratorium will expire at the end of 2003, the application reflects the traditional purchase gas adjustment treatment for the Company's purchased gas costs. The West Virginia Commission will hold hearings this fall and is expected to issue an order in the fourth quarter of 2003.

Pipeline Operations

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 Company owning the remaining 33 percent.

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Pipeline Safety Act

In December 2002, Congress enacted the Pipeline Safety Act of 2002 which includes new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Natural gas transmission operators are required to complete a baseline integrity assessment of all applicable property located in those areas within 10 years after enactment. The baseline integrity assessment of at least half of the pipeline assets must be completed by December 2007, with the highest risk pipeline segments included in this first phase, and the other half by December 2012. Subsequent to the 10-year baseline assessment, applicable property must be reassessed every seven years. The U.S. Department of Transportation is expected to issue final rules on the integrity management program in December 2003. The Company is currently evaluating its natural gas tr ansmission property under this legislation and has not determined the nature or costs of inspection and potential remediation activities at this time.

Other

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.

See Note 4 to the Consolidated Financial Statements for a description of the following new accounting standards which were issued during 2003 and generally become effective after June 30, 2003:

• FASB Interpretation No. 46, Consolidation of Variable Interest Entities;
• SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities;
• SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity; and
• SFAS No. 133 Implementation Issue No. C20, Interpretation of the Meaning of 'Not Clearly and Closely Related' in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.

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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 as of the end of the period covered by this report. 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 and that there have been no changes in the Company's internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. 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.

ITEM 5. OTHER INFORMATION

In August 2003, the Company filed an application with the West Virginia Commission to increase its purchased gas cost rate. See Rate Matters in MD&A of this Form 10-Q for further information on this matter.