(1) Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion     subsidiaries.

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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 operating segments:

Energy includes the Company's gas transmission pipeline and storage system, certain gas production operations, a liquefied natural gas import and storage facility and producer services operations that includes aggregation of gas supply and related wholesale activities.

Delivery includes the Company's regulated gas distribution systems and customer service operations and the Company's nonregulated retail energy marketing activities.

Exploration & Production includes 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 deepwater areas of the Gulf of Mexico.

In addition, the Company reports corporate and other functions as a segment, including activities of CNGI and other minor subsidiaries. The contribution to net income by the Company's primary operating segments is determined based on a measure of profit that executive management believes represents the segments' core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment's performance or allocating resources among the segments. These specific items are instead reported in the Corporate and Other segment.

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

The MD&A consists of the following information:

• Forward-Looking Statements
• Accounting Matters
• Results of Operations
• Segment Results of Operations
• Credit Risk
• 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 predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

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

Critical Accounting Policies and Estimates

As of March 31, 2004, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2003. The policies disclosed included the accounting for: derivative contracts at fair value; goodwill and long-lived asset impairment testing; employee benefit plans; regulated operations; and gas and oil operations.

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The Company adopted FIN 46R for its interests in variable interest entities (VIEs) that are not considered special purpose entities on March 31, 2004. FIN 46R addresses the identification and consolidation of VIEs, which are entities that are not controllable through voting interests or in which the VIEs' equity investors do not bear the residual economic risks and rewards. There was no impact on the Company's results of operations or financial position relating to this adoption.

Following is a summary of contributions by its operating segments to net income for the quarter ended March 31, 2004 and 2003:

The increase in net income was also impacted by specific items recognized by the Company during the quarters ended March 31, 2004 and 2003 and reported in the Corporate and Other segment, including:

• $18 million benefit in 2004 resulting from a favorable adjustment to the carrying amount of CNGI's investment in an Australian pipeline business based on an agreement, whereby a portion of the pipeline assets is to be sold;
• $5 million after-tax loss from adopting SFAS No. 143 in 2003; and
• $4 million of after-tax severance costs for workforce reductions in 2003.

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

An analysis of the Company's results of operations for the first quarter of 2004 compared to the first quarter of 2003 follows:

Regulated gas sales revenue increased 20% to $660 million, primarily reflecting the combined effects of:

• A $132 million increase due to increased rates for regulated gas distribution operations primarily related to the recovery of higher gas prices, partially offset by a $38 million decrease associated with milder weather. The effect of this increase in regulated gas sales revenue on net income was largely offset by a comparable increase in Purchased gas expense; and
• A $19 million increase in sales by gas transmission operations.

Nonregulated gas sales revenue increased 42% to $656 million primarily reflecting:

• A $101 million increase in revenue from retail energy marketing operations, reflecting higher prices ($26 million) and higher volumes ($75 million); and
• A $98 million increase in revenue from producer services operations, reflecting lower prices ($55 million) and higher volumes ($153 million).

The increase also includes $194 million of higher gas sales to another Dominion affiliate, as part of Dominion's enterprise-wide price risk management. See Note 13 to the Consolidated Financial Statements.

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Gas transportation and storage increased 2% to $272 million primarily reflecting higher storage revenues related to the reactivation of the Company's liquefied natural gas import facility and higher gas transmission revenue, partially offset by lower volumes of gas delivered by the regulated operations due to comparably milder weather in the first quarter of 2004.

Gas and oil production revenue decreased less than 1% to $296 million primarily due to lower average realized prices for gas and oil largely offset by the recognition of previously deferred revenue for gas volumes delivered under a volumetric production payment (VPP) agreement ($29 million).

Other revenue increased 31% to $194 million, primarily reflecting:

• A $35 million increase in nonregulated electric revenue, resulting primarily from customer growth in retail energy sales;
• A $6 million increase in sales of extracted products; and
• A $4 million increase in gathering service revenue associated with the distribution operations.

Purchased gas expense increased 35% to $1.1 billion, primarily reflecting:

• An $81 million increase associated with retail energy marketing, reflecting higher volumes;
• An $86 million increase associated with producer services operations, reflecting lower prices ($68 million) and higher volumes ($154 million); and
• An $89 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue.

The increase includes $25 million of higher gas purchases from another Dominion subsidiary. See Note 13 to the Consolidated Financial Statements.

Electric fuel and energy purchases expense increased 78% to $80 million associated with nonregulated retail energy marketing operations, related primarily to higher volumes, including $28 million of additional energy purchases from another Dominion subsidiary. See Note 13 to the Consolidated Financial Statements.

Liquids, pipeline capacity and other purchases expense decreased 4% to $51 million, reflecting primarily lower levels of rate recoveries for certain costs of transmission operations in the first quarter of 2004, partially offset by the increase in the cost of liquids purchased for resale.

Other operations and maintenance expense decreased 18% to $152 million, primarily reflecting the following:

• A $35 million benefit primarily due to favorable mark-to-market changes in fair value attributable to the time value of options that are designated as hedges of future sales from oil production; and
• A $7 million charge recognized in 2003 related to severance costs for workforce reductions. No comparable charge was recognized during 2004.

These decreases were partially offset by lower net pension credits and higher other postretirement benefit (OPEB) costs ($7 million).

Depreciation, depletion and amortization expense increased 10% to $154 million, primarily reflecting higher finding and development costs and higher depreciation expense, resulting from property additions, including the consolidation of certain VIEs as a result of adopting FIN 46R at December 31, 2003.

Other income increased $28 million, primarily reflecting an $18 million benefit resulting from a favorable adjustment to the carrying amount of CNGI's investment in an Australian pipeline business based on an agreement, whereby a portion of the pipeline assets is to be sold. In addition, this increase includes $10 million of higher investment income.

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Cumulative effect of a change in accounting principle-During the first quarter of 2003, the Company adopted SFAS No. 143, resulting in a net after-tax loss of $5 million.

Presented below are the key factors that impacted the Energy segment's operating results:

 

The Energy segment had an increase of $2 million in net income, as compared to the first quarter of 2003, reflecting:

• Higher gas prices on producer services operations;
• Higher contribution from the Cove Point LNG facility due to a full quarter of operations after the reactivation of the import facility in third quarter of 2003; and
• Higher operations and maintenance expense due to increased pension and OPEB costs and higher contractor services expense.

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Presented below are the key factors that impacted the Delivery segment's operating results:

The Delivery segment had an increase of $7 million in net income, as compared to the first quarter of 2003, reflecting:

• Lower gas sales and transport volumes attributable to comparably warmer weather (heating degree-days were 7% lower in the franchise service areas);
• Higher contribution from nonregulated electric and gas operations primarily reflecting an increase in customer accounts and decreased purchased gas prices;
• A decrease in net pension credits and an increase in OPEB costs; and
• Bad debt expenses were lower in 2004 primarily due to increased reserves required in the first quarter of 2003 due to colder than normal weather. The reduction also reflects the effect of the bad debt rider for Ohio customers that allows for the deferral and subsequent recovery of incremental bad debt expense over the level that is included in base rates.

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Exploration & Production Segment

The Exploration & Production segment includes the Company's gas and oil exploration, development and production business.

                                  mcf = thousand cubic feet

                                  mcfe = thousand cubic feet equivalent

Presented below are the key factors that impacted the Exploration & Production segment's operating results:

The Exploration & Production segment had an increase of $25 million in net income, as compared to the first quarter of 2003, reflecting:

• Recognition of previously deferred revenue in connection with deliveries under a VPP agreement;
• Lower gas production reflecting the sale of mineral rights under the VPP agreement, which was largely offset by increased Gulf of Mexico gas production;
• Lower operations and maintenance expenses, which decreased primarily due to favorable mark-to-market changes in fair value attributable to the time value of options that are designated as hedges of future sales from oil production;
• A higher rate for depreciation, depletion and amortization (DD&A), reflecting acquisitions, dispositions and increased finding and development costs;
• Lower average realized prices for gas and oil; and
• Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production.

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Corporate and Other also includes CNGI and other minor subsidiaries.

Presented below are Corporate and Other's operating results for the three months ended March 31, 2004 and 2003:

The net income for Corporate and Other was $20 million for 2004, compared to net loss of $10 million in 2003. The 2004 net income reflects an $18 million benefit for an adjustment to the carrying amount of CNGI's investment in an Australian pipeline business based on an agreement, whereby a portion of the pipeline assets will be sold for an amount in excess of what the Company had previously estimated.

The 2003 net loss primarily reflected:

• 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 on January 1, 2003 attributable to the Energy segment and
• A $6 million ($4 million after-tax) charge for severance costs related to workforce reductions in Other operations and maintenance expense, including $3 million, $2 million and $1 million attributable to the Energy, Delivery and Exploration & Production segments, respectively.

________________

(2)   The five largest counterparty exposures, combined, for this category represented approximately 4% of the total gross credit exposure.

(3)   The five largest counterparty exposures, combined, for this category represented approximately 6% of the total gross credit exposure.

(4)   The five largest counterparty exposures, combined, for this category represented approximately 12% of the total gross credit exposure.

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Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; fluctuations in energy-related commodities prices and the effect these could have on the Company's earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; political and economic conditions (including inflation and deflation) and completing the divestiture of investments held by CNG International Corporation. Other more specific risk factors are as follows:

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

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

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

The use of derivative instruments could result in financial losses. The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

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The Company's exploration and production business is dependent on factors that cannot be predicted or controlled. Factors that may affect the Company's financial results 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 as well as inherent operational risks that could disrupt production. The Company's liquidity may also be impacted by margin requirements that result from financial derivatives used to hedge future sales of gas and oil production and require the deposit of funds or other collateral with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Short-term market declines in natural gas and oil prices may also result in the permanent write-down of the Company's gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquis ition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test), in a given country, 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 and its subsidiaries will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company's control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to the Company's credit ratings. Restrictions on the Company's ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing rating agency requirements could negatively affect the Company's growth and business strategy. As of March 31, 2004, the Company's senior unsecured debt was rated BBB+, negative 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 modify its business plans in ways that may adversely affect its growth and earnings per share. 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 its operations specifically. New accounting standards could be issued 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.

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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. There were 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.

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CONSOLIDATED NATURAL GAS COMPANY
PART II. - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In April 2004, FERC granted Greenbrier Pipeline Company, LLC's (Greenbrier)filed a request with FERC for a two-year extension of the time within which Greenbrier may construct and operate the Greenbrier Pipeline. Greenbrier had received final FERC approval for the pipeline in April 2003. The Greenbrier Pipeline is proposed to originate in Kanawha County, West Virginia and extend through southwest Virginia to Granville County, North Carolina.

There were no reports on Form 8-K filed during the quarter ended March 31, 2004.