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 September 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 October 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.

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 as well as the quarterly reports for previous interim periods of 2003 filed on Form 10-Q.

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 September 30, 2003, its results of operations for the three and nine months and cash flows for the nine months ended September 30, 2003 and 2002.

The accompanying unaudited Consolidated Financial Statements represent the accounts of the Company, 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 or corporate joint ventures when the Company is able to exercise significant influence over the financial and operating policies of the investee. For all other investments, the cost method is applied.

The accompanying unaudited Consolidated Financial Statements reflect certain estimates and assumptions made by management in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a discussion of the Company's estimation techniques.

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

Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

Accounting for Asset Retirement Obligations

Effective January 1, 2003, the Company adopted Statements 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 its natural gas gathering, storage, transmission and distribution systems, including approximately 2,300 gas storage wells in the Company's underground natural gas storage network. These obligations result from certain safety requirements to be performed at the time any pipeline or storage well is abandoned. However, the Company expects to operate its natural gas gathering, storage, transmission and distribution systems in perpetuity. Thus, such asset retirement obligations will not be reflected in the Company's Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur based on expected retirement or abandonment of individual pipelines or storage wells based on the Company's operational planning.

The adoption of SFAS No. 143 resulted in an after-tax loss of $5 million, representing the cumulative effect of a change in accounting principle. The impact of adopting SFAS No. 143, other than the cumulative effect of a change in accounting principle, for the three and nine months ended September 30, 2003 was not material.

Effective July 1, 2003, the Company adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. The standard requires an issuer to classify certain financial instruments with characteristics of both liabilities and equity as a liability if the issuer is obligated to redeem such instruments. As a result, beginning July 1, 2003, the Company presents the mandatorily redeemable preferred securities issued by a subsidiary trust as long-term debt and related distributions as interest expense. These securities are 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.

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During the second quarter of 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 reflects decisions made by the FASB and its Derivatives Implementation Group in connection with issues raised about the application of SFAS No. 133. Generally, changes resulting from SFAS No. 149 apply to contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although industry efforts to interpret SFAS No. 149 are ongoing, the Company believes that SFAS 149 will not have a material impact on its results of operations and financial position based on an assessment of currently available information.

Consolidation of Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, (FIN 46) which addresses the consolidation of "variable interest entities" (VIEs). VIEs are entities that are not controllable through voting interests or in which the equity investors do not bear the residual economic risks and rewards. In October 2003, the FASB decided to permit more time for the implementation of FIN 46 and now requires adoption as of December 31, 2003.

The Company entered into an agreement with another Dominion subsidiary (lessor) in order to finance and lease a power generation facility. Under existing accounting guidance, neither the project assets nor the related obligations are currently reported on the Company's Consolidated Balance Sheets. Under FIN 46, the lessor is considered a VIE and the Company has been determined to be the primary beneficiary and will therefore consolidate the VIE in the preparation of its Consolidated Balance Sheets.

The Company estimates that consolidating this VIE, effective December 31, 2003, will result in an additional $224 million in net property, plant and equipment and $234 million of related debt. The cumulative effect of adopting FIN 46 is estimated to result in an after-tax charge of $7 million, representing depreciation expense associated with the consolidated assets.

At September 30, 2003, the Company's maximum exposure to loss resulting from its interests in the VIE was $192 million based upon total project costs through September 30, 2003. The exposure assumes that the property, plant and equipment will have no value at the end of the lease terms, which the Company believes is highly unlikely.

The Company established Dominion CNG Capital Trust I that 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. Under FIN 46, the Company will cease consolidating the trust beginning on December 31, 2003. Upon adoption, the Company's Consolidated Balance Sheets will report the junior subordinated instruments held by the trust as long-term debt, rather than trust preferred securities.

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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, Business Combinations, and 142, Goodwill and Other Intangible Assets. If, as a result of the resolution of this issue, reclassification of the costs associated with mineral rights is required, the Company's net intangible assets would increase and its net property, plant and equipment would decrease. As of September 30, 2003, the amount subject to reclassification was approximately $3.5 billion. While resolution of this issue may affect the balance sheet classification of these assets, there would be no impact on the Company's results of operations or cash flows.

The Company adopted SFAS No. 143 on January 1, 2003. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.

In accordance with applicable regulatory uniform system of accounts and as permitted by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company's gas utility operations recognize a provision for the cost of future asset removal activities subject to cost-of-service rate regulation, even if no legal obligation to perform such activities exists. The periodic provision is recorded as a component of depreciation expense on the Consolidated Statement of Income, resulting in a credit being recorded in accumulated depreciation, depletion and amortization on the Consolidated Balance Sheet. At September 30, 2003 and December 31, 2002, the Company's accumulated depreciation, depletion and amortization included $206 million and $221 million, respectively, representing regulatory liabilities for the estimated amounts collected from customers for the future cost of such asset removal activities.

A question has recently arisen about whether these regulatory liabilities should continue to be classified in accumulated depreciation, depletion and amortization or be reported as liabilities on the balance sheet. If, as a result of the resolution of this issue, reclassification of this accumulated provision for future removal costs is required, the Company's accumulated depreciation would decrease and its regulatory liabilities would increase. While resolution of this issue may affect the balance sheet classification of these items, there would be no impact on the Company's results of operations or cash flows.

The Company's operating revenue consists of the following:

The following table presents total comprehensive income:

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Note 8.     Derivative Instruments and Hedge Accounting

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The following table presents selected information related to cash flow hedges included in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet at September 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 9.    Ceiling Test

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 revenue to be derived from the anticipated production of proved gas and oil reserves, assuming period-end market prices. Approximately 17 percent of the Company's anticipated production that is hedged by qualifying cash flow hedges for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of September 30, 2003.

Dominion, Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion, and the Company are parties to two joint credit facilities that allow aggregate borrowings of up to $2 billion: a $1.25 billion 364-day revolving credit facility executed in May 2003 and terminates in May 2004; and a $750 million 3-year revolving credit facility executed in May 2002 and terminates in May 2005. The 3-year facility can also be used to support up to $200 million of letters of credit. The remaining 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 for other general corporate purposes.

At September 30, 2003, outstanding commercial paper under the companies' combined commercial paper programs was $875 million and total outstanding letters of credit supported by the 3-year facility were $88 million issued on behalf of other Dominion subsidiaries. At September 30, 2003, capacity available under the two credit facilities was $1.0 billion.

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In August 2003, the Company entered into a $1 billion credit facility. This 364-day revolving credit facility, which terminates in August 2004, will be 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 September 30, 2003, outstanding letters of credit under these facilities totaled $586 million.

In August 2003, the Company repaid $150 million of 5.75 percent senior notes.

At September 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.

The following table describes the changes to the Company's asset retirement obligations during the nine months ended September 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:

Note 12.    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 nine months ended September 30, 2003.

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The Company enters into long-term purchase commitments for natural gas. As of September 30, 2003, estimated payments under these commitments are as follows: 2004-$160 million; 2005-$100 million; 2006-$20 million; 2007-$20 million; and years beyond 2007-$215 million. These purchase commitments include those required for regulated operations. The Company generally recovers the costs of those purchases through regulated rates. The natural gas purchase commitments of the Company's field services operations are also included, net of related sales commitments.

The Company entered into agreements with a Dominion subsidiary (lessor) in order to finance and lease a power generation facility. On December 31, 2003, the Company will consolidate the VIE 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, previously disclosed future minimum lease payments will be reduced by the following amounts: 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.

On behalf of consolidated subsidiaries, as of September 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 $39 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $587 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.

In October 2003, the Company made an equity contribution of $100 million in connection with CNG International's equity investment in Australian natural gas pipelines under an agreement associated with a debt financing. The Company was contractually obligated to make such equity contribution to ensure repayment of the debt that matured in October 2003.

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. At September 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 September 30, 2003. The amounts presented exclude accounts receivable for gas sales and services, regulated gas transmission services, amounts receivable 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 September 30, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $51 million and $55 million, respectively, and derivative liabilities with Dominion affiliates of $54 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 Accumulated Other Comprehensive Income in the Company's Consolidated Balance Sheets. The Company's income from operations includes the recognition of the following derivative gains and los ses on affiliated transactions:

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See Note 8 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 September 30, 2003 and 2002 was approximately $38 million and $42 million, respectively, and was approximately $121 million and $123 million for the nine months ended September 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 September 30, 2003 and 2002 was approximately $3 million and $2 million, respectively, and was approximately $8 million and $5 million for the nine months ended September 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 were converted to Dominion money pool borrowings on March 1, 2003. In September 2003, Dominion made a $600 million equity contribution to the Company that was accomplished by reducing the money pool borrowings of the Company's subsidiaries. At September 30, 2003, net outstanding borrowings under the Dominion money pool totaled $541 million. At September 30, 2003 and December 31, 2002, net outstanding borrowings under the demand note totaled $132 million and $563 million, respectively. During the three and nine months ended September 30, 2003, the Company incurred approximately $4 million and $10 million, respectively, of 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 entered into an agreement with a Dominion subsidiary in order to develop, construct, finance and lease a power generation facility in Armstrong, Pennsylvania. The Company will adopt FIN 46 on December 31, 2003 by consolidating its interests in this VIE that includes the power generation facility assets and related debt on the Company's Consolidated Balance Sheets.

In August 2003, the Company received $266 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period August 2003 through August 2007. The sale reduced the Company's natural gas reserves by approximately 66 billion cubic feet (bcf). While the Company is obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and rights to future development drilling. If production from the properties is inadequate to deliver approximately 66 bcf of natural gas scheduled for delivery to the purchaser, the Company has no obligation to make up the shortfall. Cash proceeds received from this volumetric production payment transaction were recorded as deferred revenue. The Company will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser.

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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 as well as certain items attributable to activities of the other segments. Items included in the Corporate and Other segment for the nine months ended September 30, 2003 follow:

• Impairment loss related to certain CNG International investments classified as assets held for sale (see Note 7);
• Severance costs related to the Company's workforce reductions; and
• Cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 (see Note 3).

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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 that 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, as well as inherent operational risks that could disrupt 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 the Company's financial results. Also, because the Company follow s 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 November 3, 2003, the Company's senior unsecured debt was 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.

As of September 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.

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 discussion of the results of segment operations. All variances are stated as actual results for the three and nine months ended September 30, 2003, as compared to the actual results for the same periods of 2002.

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Net income for the third quarter of 2003 was relatively unchanged, as compared with net income in the same quarter of 2002. The 2003 quarterly results reflected an increase in operating revenue, partially offset by the effects of higher operating expenses, as compared to the same period in 2002.

Total operating revenue increased (36 percent), reflecting the recovery of higher purchased gas costs in regulated gas distribution operations; higher average prices and higher volumes in retail sales operations; and higher average realized prices for sales of gas production, partially offset by lower average realized prices and lower production volumes for oil.

Total operating expenses increased (43 percent), reflecting higher average prices in purchased gas costs; an increase in purchased volumes associated with the Company's nonregulated retail energy marketing operations; higher service industry costs related to gas and oil production; lower pension credits and higher other postretirement benefits.

Net income for the nine months ended September 30, 2003 was $465 million, as compared to $418 million in the same period in 2002. The 2003 nine-month results reflected an increase in operating revenue, partially offset by the effects of higher operating expenses, as compared to the same period in 2002. The nine-month results also included 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 on January 1, 2003.

Total operating revenue increased (44 percent), reflecting the recovery of higher purchased gas costs and the impact of comparably colder weather in the first quarter of 2003 related to regulated gas distribution operations; higher average prices and higher volumes in retail sales operations; and comparably higher average realized prices for both gas and oil and higher volumes for gas production.

Total operating expenses increased (52 percent), reflecting higher volume requirements, primarily attributable to colder weather in the first quarter of 2003 in the franchise service areas; higher average prices and higher volumes associated with the Company's nonregulated retail energy marketing operations; an impairment loss recognized in the second quarter of 2003 related to CNG International's Kauai investment classified as assets held for sale; higher severance taxes, service industry costs and rate of depletion for gas and oil production; higher gross receipts taxes for regulated gas distribution operations; lower pension credits and higher other postretirement benefits.

Other income reflected an impairment loss recognized in the second quarter of 2003 related to CNG International's equity investment in Australian natural gas pipelines classified as assets held for sale.

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

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The overall increase in operating revenue, primarily reflected increases in:

• Regulated gas sales revenue, reflecting the recovery of higher purchased gas costs; and
• Other revenue, as a result of new gathering and compression fees charged to producers.

The overall increase in operating expenses, primarily reflected increases in:

• Purchased gas costs, primarily reflecting higher purchased gas prices, including the effect of increased regulatory recoveries; and
• Other operations and maintenance expense, primarily related to higher general and administrative expenses, such as benefits, contractor services, routine maintenance and other expenses.

Gas sales volumes increased 1 bcf and volumes transported decreased 3 bcf, as compared to 2002. Total throughput to industrial customers was 21 bcf in 2003, as compared to 24 bcf in 2002.

The Delivery segment contributed $109 million to net income in the nine months ended September 30, 2003, as compared to $91 million in the same period in 2002. The 2003 nine-month results reflected an increase in operating revenue, partially offset by the effects of higher operating expenses.

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The overall increase in operating revenue, primarily reflected increases in:

• Regulated gas sales revenue, reflecting the recovery of higher purchased gas costs ($208 million) and higher sales volumes ($101 million). Higher sales volumes were attributed to comparably colder weather in the first quarter of 2003. Heating degree-days were 19 percent higher in the franchise service areas in the nine months ended September 30, 2003. Average rates for all customer groups increased, reflecting the pass-through of higher purchased gas costs;
• Gas transportation revenue, primarily due to higher transport volumes, resulting from colder weather experienced in the first quarter of 2003, and increased migration of customers opting for alternate suppliers from regulated gas sales to transportation service; and
• Other revenue, primarily reflecting higher production and gathering fees charged to producers.

The overall increase in operating expenses, primarily reflected increases in:

• Purchased gas costs, reflecting higher purchased gas prices ($252 million) and higher volume requirements ($56 million). Although higher purchased gas prices were reflected in gas cost recovery rates, gas cost regulatory deferrals increased by $29 million, pending recovery through future rates. Higher volume requirements resulted primarily from colder weather during the first quarter of 2003;
• Other operations and maintenance expense, primarily due to higher general and administrative expenses, such as benefits, routine maintenance and other expenses; and
• Other taxes, primarily reflecting higher gross receipts taxes.

Gas sales volumes increased 16 bcf and volumes transported increased 6 bcf, as compared to 2002. While the higher volumes in both sales and transport for residential and commercial customers reflected the impact of comparably colder weather in the first quarter of 2003, the transport volumes reflected a decrease in industrial activity. Total throughput to industrial customers was 75 bcf in 2003, as compared to 79 bcf in 2002.

The Energy segment contributed $36 million to net income in the third quarter of 2003, as compared to $42 million in the same period in 2002. The 2003 quarterly results reflected an increase in operating revenue, offset by the effects of higher operating expenses.

The overall increase in operating revenue, primarily reflected increases in:

• Nonregulated electric sales revenue, primarily resulting from customer growth in retail energy sales;
• Nonregulated gas sales revenue from field services and retail energy marketing operations, reflecting higher prices ($102 million) and higher volumes ($45 million); and
• Gas transportation and storage revenue, primarily reflecting higher average rates for gathering and extraction services and reactivation of the liquefied natural gas facility in August 2003.

The overall increase in operating expenses, primarily reflected increases in:

• Purchased gas costs, reflecting the impact of higher gas prices ($107 million) and higher volumes purchased ($50 million) associated with field services, retail energy marketing and gas transmission operations;
• Electric fuel and energy purchases, primarily resulting from higher volumes purchased for retail energy marketing sales; and
• Other operations and maintenance expense, primarily reflecting higher general and administrative expenses.

The Energy segment contributed $156 million to net income in the nine months ended September 30, 2003, as compared to $147 million in the same period in 2002. The 2003 nine-month results reflected an increase in operating revenue, partially offset by the effects of higher operating expenses.

The overall increase in operating revenue, primarily reflected increases in:

• Nonregulated electric sales revenue, reflecting higher retail energy sales ($62 million), primarily resulting from customer growth, and increased revenue ($15 million) from the Company's power generation facility;
• Nonregulated gas sales revenue from field services and retail energy marketing operations, reflecting higher prices ($415 million) and higher volumes ($91 million); and
• Gas transportation and storage revenue, primarily reflecting higher average rates for gathering and extraction services and reactivation of the liquefied natural gas facility in August 2003.

The overall increase in operating expenses, primarily reflected increases in:

• Purchased gas costs, primarily reflecting higher prices associated with field services, retail energy marketing and gas transmission operations;
• Electric fuel and energy purchases, primarily resulting from higher volumes purchased for nonregulated retail energy marketing sales; and
• Other operations and maintenance expense, primarily reflecting higher overall operating costs, including the liquefied natural gas storage operations, lower pension credits and higher general and administrative expenses.

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