PART 1. FINANCIAL INFORMATION

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION  

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

      Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain non-utility businesses. Through our natural gas utility business, we distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers through our six regulated natural gas utility divisions, which cover the following service areas:

      In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the utility divisions operate. Our shared services unit is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas and Metairie, Louisiana.

      Our non-utility businesses are organized under Atmos Energy Holdings, Inc. (AEH) and have operations in 18 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, LLC and Trans Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing, L.L.C., which was renamed Atmos Energy Marketing, LLC (AEM).

      AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services primarily consist of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative products.

      Our other non-utility businesses consist primarily of the operations of Atmos Pipeline and Storage, L.L.C. and Atmos Power Systems, Inc., which are wholly-owned by AEH. Through Atmos Pipeline and Storage, L.L.C., we own or have an interest in underground storage fields in Kansas, Kentucky and Louisiana. Additionally, Atmos Pipeline and Storage, L.L.C. contracts for storage service in underground storage facilities on many of the interstate pipelines serving us. Through Atmos Power Systems, Inc. we construct and operate electric peaking power generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

      Finally, prior to January 20, 2004, United Cities Propane Gas, Inc., a wholly-owned subsidiary of AEH, owned an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies. As of December 31, 2003, USP owned all of the general

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partnership interest and approximately 26 percent of the limited partnership interest in Heritage Propane Partners, L.P. a publicly-traded marketer of propane through a nationwide retail distribution network. Through our ownership in USP, we owned an approximate five percent indirect interest in Heritage Propane Partners, L.P. On January 20, 2004, we and our partners in USP completed the previously announced sale of our interest in USP, including the general partnership and limited partnerships in Heritage Propane Partners, L.P., for $130.0 million. We received approximately $24.7 million and will record a $4.4 million pretax book gain in the second quarter of fiscal 2004.

      In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim period financial statements. These consolidated interim period financial statements and notes are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation (“Atmos” or “the Company”) in its Annual Report on Form 10-K for the fiscal year ended September 30, 2003. Because of seasonal and other factors, the results of operations for the three month period ended December 31, 2003 are not indicative of expected results of operations for the fiscal year ending September 30, 2004.

      The following presents a summary of certain of our significant accounting policies. A complete description of our significant accounting policies is included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2003.

      Principles of consolidation  — The accompanying condensed consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated. Additionally, we accounted for our investment in USP under the equity method of accounting for investments.

      Basis of comparison  — Certain prior year amounts have been reclassified to conform with the current year presentation. In conjunction with our adoption of Emerging Issues Task Force (EITF) 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management in fiscal 2003, energy trading contracts resulting in delivery of a commodity where we are the principal in the transaction are included as natural gas marketing sales or purchases. The prior year period has been reclassified to conform with this presentation.

      Use of estimates  — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, risk management and trading activities and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results could differ from those estimates.

      Regulation  — Our utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation . This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates.

      We record certain costs as regulatory assets in accordance with SFAS 71 when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of December 31, 2003 and September 30, 2003 included the following:

      Revenue recognition  — Sales of natural gas to our utility customers are billed on a monthly cycle basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for utility segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense.

      Energy trading contracts resulting in the delivery of natural gas where we are the principal in the transaction are recorded as natural gas marketing sales or purchases at the time of physical delivery. Realized gains and losses from the settlement of financial instruments that do not result in physical delivery of natural gas and unrealized gains and losses from changes in the market value of open contracts are included as components of natural gas marketing revenues. For the three months ended December 31, 2003 and 2002, we included unrealized gains (losses) on open contracts of $4.4 million and ($1.1) million as a component of natural gas marketing revenues.

      Accounts receivable and allowance for doubtful accounts  — Accounts receivable consist of natural gas sales to residential, commercial, industrial, municipal, agricultural and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on an aging of those receivable balances. We apply percentages to each aging category based on our collections experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Our allowance for doubtful accounts as of December 31, 2003 and September 30, 2003 was $13.8 million and $13.1 million.

      Impairment of Long-Lived Assets  — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. To date, no impairment has been recognized.

      Goodwill and intangible assets  — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

      Intangible assets are amortized over their useful lives ranging from 3 to 10 years. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, we assess the recoverability of intangible assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. To date, no impairment has been recognized.

      Derivatives and Hedging Activities  — Our derivative and hedging activities are tailored to the segment to which they relate. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent, based upon the anticipated settlement date of the underlying derivative. These assets and liabilities are recorded as components of other current assets, deferred charges and other assets, other current liabilities or deferred credits and other liabilities depending on the expiration or maturity date of the instrument.

      We use a combination of storage and financial hedges to protect us and our customers against unusually large winter period gas price increases. Our financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities . However, because these costs will ultimately be recovered through our rates, current period changes in the assets and liabilities from risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71 and recognized in purchased gas cost in the income statement when the related costs are recovered through our rates. Accordingly, there is no earnings impact as a result of the use of these financial instruments.

      The principal business of AEM is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the southeastern and midwestern United States. AEM also supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis.

      In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. AEM manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of financial derivatives, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties. Over-the-counter swap agreements require AEM to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Options held to manage price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. AEM links these financial derivatives to physical delivery of natural gas and typically balances its derivative positions at the end of each trading day. We manage our business to maintain no open positions. However, at any point in time, AEM may not have completely offset its risk on these activities and limited net open positions related to our physical storage may occur on a short-term basis. These open trading positions are monitored daily.

      Physical trading involves utilizing physical assets (storage and transportation) to sell and deliver gas to customers or to take a position in the market based on anticipated price movement. In addition to the price

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

risk of any net open position at the end of each trading day, the financial exposure that results from intra-day fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased or sold for future delivery at the beginning of the day may not be hedged until later in the day.

      Those futures contracts that are designated as fair value hedges in accordance with SFAS 133 are recorded at fair value on the balance sheet with an offsetting adjustment to the underlying item being hedged. Those financial contracts that are not designated as hedges are recorded on the balance sheet at fair value with current period changes in these contracts recorded as net gains or losses in our natural gas marketing revenue on the consolidated statement of income. Generally, any price risk related to fixed price forward contracts that are marked to market through earnings is mitigated by offsetting futures contracts that are also marked to market through earnings. Any mark-to-market gains or losses on affiliate contracts are eliminated in consolidation.

      Changes in the valuation of assets and liabilities arising from risk management activities primarily result from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts and newly originated transactions. Market prices and models used to value these transactions reflect our best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under present market conditions. Changes in market prices directly affect our estimate of the fair value of these transactions.

      Pension and Other Postretirement Plans  — Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The assumed return on plan assets is based on management’s expectation of the long-term return on the portfolio of plan assets. The discount rate used to compute the present value of plan liabilities generally is based on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid.

      Comprehensive income  — The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2003 and 2002:

      The only component of accumulated other comprehensive loss relates to unrealized holding losses associated with certain available for sale investments.

      Stock-based compensation plans  — We have two stock-based compensation plans that provide for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to officers and key employees: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. Non-employee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these

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plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.

      As permitted by SFAS 123, Accounting for Stock-Based Compensation we account for these plans under the intrinsic value method described in Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees . Under this method, no compensation cost for stock options is recognized for stock option awards granted at or above fair market value.

      Awards of restricted stock are generally valued at the market price of the Company’s common stock on the date of grant. The unearned compensation is amortized to operation and maintenance expense over the vesting period of the restricted stock.

      Had compensation expense for our stock options issued under the Long-Term Incentive Plan been recognized based on the fair value on the grant date under the methodology prescribed by SFAS 123, our net income and earnings per share for the three months ended December 31, 2003 and 2002 would have been impacted as shown in the following table:

      Because of the limited activities of the Long-Term Stock Plan for the Mid-States Division, the pro forma effects of applying SFAS 123 would have less than a $0.01 per diluted share effect on earnings per share, or $381 and $753 for the three months ended December 31, 2003 and 2002.

      Recent Accounting Developments  — In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51 . The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when and which business enterprises should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. FIN 46 applies immediately to VIEs created after January 31, 2003 or to VIEs obtained after that date. For variable interests held in VIEs acquired prior to February 1, 2003, FIN 46 was originally effective July 1, 2003. However, in October 2003, the FASB deferred the effective date of FIN 46 for VIEs created prior to February 1, 2003 to the first reporting period after December 15, 2003. The adoption of this interpretation did not have a material

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impact on our financial position, results of operations or net cash flows because Atmos currently is not a beneficiary of a VIE.

      During 2003 the Emerging Issues Task Force (the Task Force) added to its agenda EITF Issue 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, to address the meaning of other-than-temporary impairment and its application to certain investments carried at cost. In November 2003, the Task Force continued its deliberations on the matter and did not reach a consensus on what constitutes an “other-than-temporary” impairment. However, the Task Force did reach a consensus regarding the disclosure requirements concerning unrealized losses on available for sale debt and equity securities accounted for under SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, which will be applicable to us beginning with our fiscal 2004 annual report on Form 10-K.

      In December 2003, the FASB issued SFAS 132 (revised), Employers’ Disclosures about Pensions and Other Postretirement Benefits . These revisions require additional disclosures in annual reports concerning the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. Additionally, the statement now requires interim period disclosures regarding net periodic pension cost and employer contributions. The annual disclosures will become fully effective for fiscal years ending after June 15, 2004 and the interim period disclosures are effective for interim periods beginning after December 15, 2003. We have adopted the interim period disclosures as of December 31, 2003 and will adopt the annual disclosures beginning with our fiscal 2004 annual report on Form 10-K. See Note 8.

      In January 2004, the FASB issued FASB Staff Position FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which permits a plan sponsor to defer recognizing the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) in the accounting for its plan under SFAS 106 and in providing disclosures related to the plan required by SFAS 132 (revised) until authoritative guidance on the accounting for the federal subsidy is issued. We estimate the provisions of the Act will reduce our accumulated postretirement benefit obligation and our net postretirement benefit obligation costs for the remainder of fiscal 2004, beginning in the second quarter of 2004. However, our assessment of the reduction has not been completed.

3.     Acquisition of Mississippi Valley Gas Company

      On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), Mississippi’s largest natural gas utility, which enabled us to expand our service area into Mississippi. MVG served approximately 261,500 residential, commercial, industrial and other customers located primarily in the northern and central regions of Mississippi. We paid approximately $74.7 million in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. We also repaid approximately $70.9 million of MVG’s outstanding debt. The results of operations of MVG have been consolidated with our results of operations from the acquisition date.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      During the current quarter, we finalized our purchase price allocation related to the MVG acquisition. The following table summarizes the fair values of the assets acquired and liabilities assumed, in thousands:

      The table below reflects the unaudited pro forma results of the Company and MVG for the three months ended December 31, 2002 as if the acquisition had taken place at the beginning of fiscal 2003.

4.     Goodwill and Intangible Assets

      Goodwill and intangible assets are comprised of the following as of December 31, 2003 and September 30, 2003.

      The following presents our goodwill balance allocated by segment and changes in our balance for the three months ended December 31, 2003:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.     Derivative Instruments and Hedging Activities

      We conduct our risk management activities through both our utility and natural gas marketing segments. The following table shows our risk management assets and liabilities by segment at December 31, 2003 and September 30, 2003:

      The following table shows the components of the change in fair value of our utility and natural gas marketing derivative contract activities for the three months ended December 31, 2003 (in thousands).

      For the 2003-2004 heating season, we hedged between 50 percent and 55 percent of our anticipated flowing gas requirements through a combination of storage, financial hedges and fixed forward contracts at a weighted average cost of approximately $5.25 per Mcf.

      In June 2001, we purchased a three year weather insurance policy with an option to cancel the third year of coverage. The insurance covered our Texas and Louisiana operations to protect against weather that was at least seven percent warmer than normal for the entire heating season of October through March beginning with the 2001-2002 heating season. The cost of the three year policy was $13.2 million, which was prepaid and was amortized over the appropriate heating seasons based on degree days. In the third quarter of fiscal 2003, we cancelled this policy primarily as a result of rate relief in Louisiana and prospects for weather normalization adjustments in Texas. During the three months ended December 31, 2002, we recognized

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amortization expense of $1.9 million. However, we did not collect under this policy because weather was not at least seven percent warmer than normal.

      Our non-utility hedging activities are conducted through AEM. AEM manages margins and limits risk exposure on natural gas inventory, fixed-price physical forwards, and purchases and sales of natural gas at daily prices published by Gas Daily through the use of financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. We manage our business to maintain no open positions. However, at times, limited net open positions related to our physical storage may occur on a short term basis. At the close of business on December 31, 2003, AEM had a net open position (including inventory) of 19 MMcf. As of December 31, 2003, 99 percent of these contracts are scheduled to mature within three years.

      Counterparty credit risk is the risk of loss to AEM from non-performance by another party to a derivative contract that is not guaranteed. Derivative contracts traded on exchanges are generally guaranteed by the exchanges. At December 31, 2003, AEM estimates that approximately 44 percent of its open financial derivative contracts were guaranteed by the exchanges. AEM’s physical contracts are held with creditworthy counterparties and are not guaranteed.

      Long-term debt at December 31, 2003 and September 30, 2003 consisted of the following:

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      Most of the First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1988 may not exceed the sum of accumulated net income for periods after December 31, 1988 plus $15.0 million. At December 31, 2003 approximately $97.9 million of retained earnings was unrestricted with respect to the payment of dividends. We were in compliance with all of our debt covenants as of December 31, 2003.

      At December 31, 2003, short-term debt was comprised of $173.8 million of commercial paper and $18.0 million outstanding under bank credit facilities. At September 30, 2003, short-term debt consisted of $118.6 million of commercial paper. No amounts were outstanding under our bank credit facilities at September 30, 2003.

      We maintain both committed and uncommitted credit facilities. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder months. Our working capital needs can vary significantly due to changes in the price of natural gas charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather.

      We have two short-term committed credit facilities totaling $368.0 million, one of which is an unsecured facility for $350.0 million that bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our commercial paper program. At December 31, 2003, $173.8 million of commercial paper was outstanding. We have a second unsecured facility in place for $18.0 million that bears interest at the Fed Funds rate plus 0.5 percent and is used for working capital purposes. At December 31, 2003, we borrowed $18.0 million under this credit facility. These credit facilities are negotiated at least annually.

      The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our $350.0 million credit facility to maintain a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2003, our total debt to total capitalization ratio, as defined, was 57 percent.

      AEM has a $220.0 million uncommitted demand working capital credit facility that bears interest at LIBOR plus 2.5 percent. AEH and AEM, both wholly-owned by us, were formerly guarantors of all amounts outstanding under this facility. Effective October 1, 2003 with the reorganization of our natural gas marketing segment, AEM became the borrower under the credit facility and AEH became the sole guarantor of the facility. At December 31, 2003 no amount was outstanding under this credit facility, although AEM letters of credit totaling $128.6 million reduced the amount available in accordance with the terms of the facility. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $58.1 million. This credit facility expires on March 31, 2004 and is expected to be renewed.

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      We also have an unsecured short-term uncommitted credit line for $25.0 million. There were no borrowings under this uncommitted credit facility at December 31, 2003 but Atmos Energy Corporation letters of credit reduced the amount available by $3.0 million. This uncommitted line is renewed or renegotiated at least annually with varying terms and we pay no fee for the availability of the line. Borrowings under this line are made on a when and as-available basis at the discretion of the bank. This facility is also used for working capital and letter of credit purposes.

      In addition, AEM has a $100.0 million intercompany credit facility with AEH for its non-utility business which bears interest at LIBOR plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $220.0 million uncommitted demand credit facility described above. At December 31, 2003, $45.0 million was outstanding under this facility.

      Basic and diluted earnings per share at December 31 are calculated as follows:

      There were 240,118 and 1,056,167 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2003 and 2002 as their exercise price is greater than the average market price of the common stock.

      The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the three months ended December 31, 2003 and 2002 are presented below. A portion of these costs are capitalized into our utility rate base as these costs are recoverable through our gas utility rates. Costs that are not capitalized are recorded as a component of operating expense. These amounts do not reflect the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). However, we estimate the provisions of the Act will reduce our net postretirement benefit obligation costs for the remainder

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of fiscal 2004, beginning in the second quarter of 2004. However, our assessment of the reduction has not been completed.

      In our annual report on Form 10-K for the year ended September 30, 2003, we disclosed that we anticipated additional voluntary contributions ranging from $0 – $15 million during fiscal 2004 may be necessary to keep the Atmos Energy Corporation Pension Account Plan (the Pension Account Plan) 100 percent funded on an accumulated benefit obligation (ABO) basis. We did not contribute to our pension plans during the quarter ended December 31, 2003. As of December 31, 2003 there have been no changes to the anticipated level of voluntary contributions that would be required to keep the Pension Account Plan 100 percent funded on an ABO basis.

      On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto, against more than 200 companies in the natural gas industry including us and our Colorado-Kansas Division. The plaintiffs, who purport to represent a class consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, allege the defendants have underpaid royalties on gas taken from wells situated on non-federal and non-Indian lands throughout the United States and offshore waters predicated upon allegations that the defendants’ gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. On April 10, 2000, this case was consolidated for pre-trial proceedings with other similar pending litigation in federal court in Wyoming in which we are also a defendant along with over 200 other defendants in the case of In Re Natural Gas Royalties Qui Tam Litigation. In January 2001, the federal court elected to remand this case back to the Kansas state court. A reconsideration of remand was filed, but it was denied. The state court now has jurisdiction over this proceeding and has issued a preliminary case management order. On April 10, 2003, the

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court denied the plaintiffs’ motion to certify this proceeding as a class action, which ruling was appealed by the plaintiffs. The court did allow the plaintiffs to file an amended complaint, which is somewhat narrower in scope than the original complaint. There have since been no material developments in this case. We continue to believe that the plaintiffs’ claims are still lacking in merit, and we intend to continue to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      On February 13, 2002, a suit was filed in the 287th District Court of Parmer County, Texas by Anderson Brothers, a Partnership, against Atmos Energy Corporation, et al. The plaintiffs’ claims arise out of an alleged breach of contract by us and by a number of our divisions and subsidiaries concerning the sale of natural gas used in irrigation activities since 1998 and an alleged violation of the Texas Agricultural Gas Users Act of 1985. The court has ruled proper venue to be in Parmer County, Texas. We have been responding to numerous discovery requests from the plaintiffs. We also filed suit in Travis County, Texas to have the Texas Agricultural Gas Users Act of 1985 declared unconstitutional. The court denied our motion for summary judgment. We appealed this decision, which appeal was also denied. The plaintiffs seek class action status and to recover unspecified damages plus attorneys’ fees. We have denied any liability and intend to vigorously defend against the plaintiffs’ claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      We are a plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc. and ONEOK Energy Marketing and Trading Company II, filed in December 2001, pending in the District Court of Lubbock County, Texas, 72nd Judicial District. In this case, we are seeking to collect our receivable related to approximately 5.0 Bcf of natural gas that we believe was not delivered. Atmos has settled a portion of its claims with the parties and will continue to pursue recovery of the remaining claims, which we believe are fully recoverable.

      United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a party to an action filed in June 2000 which is pending in the Circuit Court of Sevier County, Tennessee. The plaintiffs’ claims arise out of injuries alleged to have been caused by a low-level propane explosion. The plaintiffs seek to recover damages of $13.0 million. Discovery activities continue in this case. We have denied any liability, and we intend to vigorously defend against the plaintiffs’ claims. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      We are a party to other litigation and claims that arise in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      We are the owner or previous owner of manufactured gas plant sites in Johnson City and Bristol, Tennessee and Hannibal, Missouri which were used to supply gas prior to the availability of natural gas. The

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gas manufacturing process resulted in certain by-products and residual materials including coal tar. The manufacturing process used by our predecessors was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, we may be responsible for response actions with respect to such materials if response actions are necessary.

      United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of 1997 which we have continued through December 31, 2003. The investigative phase of the work at the site has been completed and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We have completed a risk assessment report which has been approved by the TDEC. Finally, we have completed a feasibility study for this site that was submitted in October 2003. The feasibility study recommends a remedial action that will limit the use of and access to the impacted soil, cap the site with the addition of a clay fill and geosynthetic liner, and groundwater monitoring for a period of up to 30 years. The estimated cost of the proposed remedial action is $1.5 million, which is comprised primarily of operating and maintenance costs associated with a groundwater monitoring project. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements.

      In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site which was completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site and we have proposed performing a focused removal action to remove any such residuals. The TDEC has requested that the focused removal action be conducted pursuant to a voluntary agreement. We are continuing the process of negotiating the voluntary agreement with TDEC and hope to conduct the focused removal action later this year.

      On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources addressing the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action, a subsequent site evaluation and to reimburse the response costs incurred by the state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site evaluation field work was conducted in August 1999. A risk assessment for the site has been approved by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site use limitations including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water.

      In 1995, United Cities Gas Company entered into an agreement with a third party resolving its share of the costs of additional investigations and environmental response actions for soil contamination at a former manufactured gas plant in Keokuk, Iowa. However, the extent of groundwater contamination at the site, which is not covered by the agreement, has yet to be determined.

      As of December 31, 2003 we had incurred costs of approximately $1.7 million for the investigations of the Johnson City and Bristol, Tennessee and Hannibal, Missouri sites and had a remaining accrual relating to these sites of $0.2 million, which is recorded as a component of other current liabilities.

      We have completed investigation and remediation activities pursuant to Consent Orders between the Kansas Department of Health and Environment (KDHE) and United Cities Gas Company. The Orders provided for the investigation and remediation of mercury contamination at gas pipeline sites which utilize or

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formerly utilized mercury meter equipment in Kansas. The Final Interim Characterization and Remediation Report has been submitted to the KDHE. We amended the Orders with the KDHE to include all mercury meters that belonged to our Colorado-Kansas Division before the merger with United Cities Gas Company on July 31, 1997. All work on these sites has been completed. On October 1, 2003, we received a letter from the KDHE, in which the KDHE stated that upon our payment to the KDHE of all oversight costs, we will have fulfilled the terms of the Consent Orders. As of December 31, 2003 we had incurred costs of $0.2 million for these sites and had a remaining accrual of $0.2 million for recovery, which is recorded as a component of other current liabilities. The KDHE received final payment for all oversight costs on October 29, 2003. We were then notified on November 6, 2003 that the Consent Orders had been terminated.

      We are a party to other environmental matters and claims that arise out of our ordinary business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance.

      AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2003, AEM is committed to purchase 72.1 Bcf within one year, 23.5 Bcf within one to three years and 7.7 Bcf after three years under indexed contracts. AEM is committed to purchase 1.7 Bcf within one year under fixed price contracts with prices ranging from $4.08 to $7.18. Purchases under these contracts totaled $296.7 million and $273.4 million for the three months ended December 31, 2003 and 2002.

      Our utility segment maintains supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

10.     Concentration of Credit Risk

      Credit risk is the risk of financial loss to us if customers fail to perform their contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with commercial, residential and municipal energy consumers. These transactions principally occur in the South and Midwest regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable is limited due to the large number of customers.

      We maintain credit policies with respect to our counterparties that we believe minimize overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. We maintain a provision for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of counterparty nonperformance.

      The following table presents our credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of December 31, 2003. Investment grade counterparties have minimum credit ratings of BBB assigned by Standard & Poor’s Rating Group or Baa3 assigned by

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Moody’s Investor Service. Non-investment grade counterparties are comprised of counterparties that are below investment grade or are counterparties that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is comprised of numerous smaller counterparties, none of which is individually significant.

(1)	Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers.

      Because AEM’s operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Additionally, AEM’s credit risk has increased due to higher natural gas prices as compared with the prior year. However, this risk is somewhat mitigated because a larger percentage of AEM’s business in the current year is with municipal customers, who typically are rated investment grade, as compared with the prior year.

11.     Segment Information

      Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain non-utility businesses. We distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public authority and industrial customers through our six regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

      Through our non-utility businesses, we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. We also supplement natural gas used by our customers through natural gas storage fields that we own or hold an interest in Kansas, Kentucky, Louisiana and Mississippi. We market natural gas to industrial customers primarily in West Texas and Louisiana. Finally, we construct electric power generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers.

      Our operations are divided into three segments:

	•	The utility segment, which includes our regulated natural gas distribution and sales operations,
	•	The natural gas marketing segment, which includes a variety of natural gas management services and
	•	The other non-utility segment, which includes all of our other non-utility operations.

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      Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate performance based on net income or loss of the respective operating units. Summarized income statements by segment are shown in the following tables.