See accompanying notes to condensed consolidated financial statements

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

See accompanying notes to condensed consolidated financial statements

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements

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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 nonutility 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:

(1)	Acquired in December 2002.
(2)	Denotes locations where we have more limited 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 division is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas, and Metairie, Louisiana.

      Our nonutility 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 consist primarily 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 instruments.

      Our other nonutility businesses consist primarily of the operations of Atmos Pipeline and Storage, L.L.C., Atmos Power Systems, Inc. and Atmos Energy Services, LLC (AES), 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. Through Atmos Pipeline and Storage, L.L.C. we provide storage services to our customers for a fee, as well as capture pricing arbitrage through the use of derivatives. Through Atmos Power Systems, Inc., we construct electric peaking power- generating plants and associated facilities and may enter into agreements to either lease or sell these plants. Through AES, we provide natural gas management services. Prior to the second quarter of 2004, this entity conducted limited operations. However, beginning,

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

April 1, 2004, AES began providing natural gas supply management services to our utility operations in a limited number of states. We expect to expand these services to substantially all of our utility service areas before the end of fiscal 2004.

      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 three other utility companies. Through our ownership in USP, we owned an approximate 5 percent indirect interest in Heritage Propane Partners, L.P. On January 20, 2004, we and our partners in USP completed the sale of USP’s general and limited partnership interests in Heritage Propane Partners, L.P., for $130.0 million. We received cash proceeds of approximately $24.7 million and recorded a $4.9 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- and six-month periods ended March 31, 2004, are not indicative of expected results of operations for the fiscal year ending September 30, 2004.

      Our accounting policies are described in Note 2 to our 2003 Annual Report on Form 10-K for the year ended September 30, 2003. As described in our Annual Report on Form 10-K, our utility depreciation rates approved by the various regulatory commissions included a component that allowed us to recover the cost of removing our assets. Historically, we recorded the associated obligation as a component of accumulated depreciation. This classification was consistent with others in the industry. Beginning in the second quarter of fiscal 2004, we are classifying our regulatory cost of removal obligation as a regulatory liability on the balance sheet. Additionally, for purposes of our September 30, 2003 information presented in this report, we reclassified from accumulated depreciation to regulatory liabilities a total of $108.4 million in regulatory cost of removal accruals at September 30, 2003, of which $102.4 million was a long-term regulatory liability. These reclassifications do not impact our financial position, results of operations, cash flows or ability to satisfy our financial covenants contained in our various credit agreements as of March 31, 2004 and September 30, 2003. Revised summary historical information reflecting the reclassification of our regulatory cost of removal obligation for the periods from September 30, 1999 to December 31, 2003 is contained in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

      We have two stock-based compensation plans that provide for the granting of incentive stock options, nonqualified 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. Nonemployee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these 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 Statement of Financial Accounting Standard (SFAS) 123, Accounting for Stock-Based Compensation, we account for these plans under the intrinsic-value method described in Accounting

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 and six months ended March 31, 2004 and 2003 would have been impacted as shown in the following table:

      No option grants have occurred under the Long-Term Stock Plan for the Mid-States Division since that entity was acquired in 1997. Due to the limited activities of that plan, the pro forma effect of applying SFAS 123 would have had less than a $0.01 per diluted share effect on earnings per share for the three and six months ended March 31, 2004 and 2003, or $381 and $753 for the three months ended March 31, 2004 and 2003 and $762 and $1,506 for the six months ended March 31, 2004 and 2003.

      We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

customers through the ratemaking process. Significant regulatory assets and liabilities as of March 31, 2004 and September 30, 2003 included the following:

      Currently authorized rates do not include a return on our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are amortized on a straight-line basis over estimated useful lives ranging from 7 to 20 years. These costs will have been substantially amortized by December 2005. Environmental costs have been deferred to future rate filings in accordance with rulings received from various regulatory commissions.

      The following table presents the components of comprehensive income, net of related tax, for the three- and six-month periods ended March 31, 2004 and 2003:

      The only component of accumulated other comprehensive income (loss) relates to unrealized holding gains and losses associated with certain available-for-sale investments.

      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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when to consolidate and which business enterprises should consolidate the VIE. The adoption of this interpretation did not have a material impact on our financial position, results of operations or net cash flows because we are not currently a beneficiary of a VIE.

      During 2003, the Emerging Issues Task Force (the Task Force) added to its agenda Emerging Issues Task Force (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 developed new 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 were effective for interim periods beginning after December 15, 2003. We have adopted the interim-period disclosures, which are contained in Note 8, and will adopt the annual disclosures beginning with our fiscal 2004 Annual Report on Form 10-K.

      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 have elected to recognize the provisions of the Act, beginning with the second quarter of fiscal 2004, which reduced our accumulated postretirement benefit obligation and our net postretirement benefit obligation costs by $4.1 million during the second quarter. The total income statement impact for fiscal 2004 will approximate $2.3 million, as a portion of this benefit will be capitalized.

      On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), Mississippi’s largest natural gas utility. The acquisition of MVG enabled us to expand our service area into Mississippi, which is reflective of our overall strategy to grow through profitable acquisitions. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

      Effective March 1, 2004, we completed the acquisition of the natural gas distribution assets of ComFurT Gas Inc., a privately held natural gas utility and propane distributor based in Buena Vista, Colorado, for approximately $2.0 million in cash. This company served approximately 1,800 natural gas utility customers. The acquisition enabled us to expand our contiguous service area in our Colorado-Kansas division. Unaudited pro forma results of the Company and ComFurT have not been presented as the acquisition has less than a $.01 per diluted share effect on earnings per share.

      Goodwill and intangible assets are comprised of the following as of March 31, 2004 and September 30, 2003.

      The following presents our goodwill balance allocated by segment and changes in our balance for the six months ended March 31, 2004:

      During the second quarter of 2004, we completed our annual goodwill impairment assessment. Based upon the assessment performed, our goodwill was not considered to be impaired.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      We conduct risk management activities through both our utility and natural gas marketing segments. 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. Our determination of the fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains and losses on open contracts. In our determination of fair value, we consider various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts.

      The following table shows the fair values of our risk management assets and liabilities by segment at March 31, 2004 and September 30, 2003:

      We use a combination of storage, fixed physical contracts and fixed financial contracts to protect us and our customers against unusually large winter-period gas price increases. For the 2003-2004 heating season, we hedged between 50 and 55 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $5.36 per MCF. These derivative financial instruments are marked to market pursuant to SFAS 133, Accounting for Derivative Financial Instruments and Hedging Activities. 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 in our utility segment.

      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 7 percent warmer than normal for the entire heating season of October through March, beginning with the 2001-2002 heating season. The prepaid cost of the three-year policy was $13.2 million and was amortized over the appropriate heating seasons based on heating 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 and six months ended March 31, 2003, we recognized

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

amortization expense of $2.5 million and $4.4 million. However, we did not collect under this policy because weather was not at least 7 percent warmer than normal.

      Our natural gas marketing hedging activities are conducted through AEM. AEM is exposed to risks associated with changes in the market price of natural gas, and we manage our exposure to the risk of natural gas price changes through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. The use of these contracts is subject to our risk management policies, which are monitored for compliance on a daily basis.

      We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we participate in natural gas storage transactions in which we seek to find the pricing differences that occur over time. We purchase or sell physical natural gas and then sell or purchase financial contracts at a price sufficient to cover our carrying costs and provide a gross profit margin. Through the use of transportation and storage services and derivatives, we are able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

      Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market on a monthly basis using the inside FERC (iFERC) price at the end of each month. Changes in fair value are recognized as unrealized gains and losses in the period of change. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenue and the carrying value of the inventory as an associated purchased gas cost in our condensed consolidated statement of income when we sell the gas and deliver it out of the storage facility.

      Derivatives associated with our storage gas contracts are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The difference in the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

      Similar to our inventory position, we attempt to mitigate substantially all of the commodity price risk associated with our fixed-price contracts with minimum volume requirements through the use of various offsetting derivatives. These derivatives are not designated as hedges under SFAS 133 because they naturally lock in the economic gross profit margin at the time we enter into the contract. The fixed-price forward and offsetting derivative contracts are marked to market each month with changes in fair value recognized as unrealized gains and losses in our condensed consolidated statement of income. The unrealized gains and losses are realized in the period in which we fulfill the requirements of the fixed-price contract and the derivatives are settled. To the extent that the unrealized gains and losses of the fixed-price forward contracts and the offsetting derivatives do not offset exactly, our earnings will experience some volatility. Over time, gains and losses on the fixed-price contracts will be offset by gains and losses on the derivatives, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

      Effective April 1, 2004, we are changing the way we report the expected gross profit margin associated with our fixed-price contracts by electing to treat our fixed-price forward contracts as normal purchases and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

sales. As a result, we will cease marking the fixed-price forward contracts to market. We have designated the offsetting derivative contracts as cash-flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on open contracts will be recorded as a component of accumulated other comprehensive income and will be recognized in earnings when the hedged volumes are sold. This designation is expected to reduce the amount of volatility somewhat in our condensed consolidated income statement and more accurately reflect the economics of the transaction.

      Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on March 31, 2004, AEH had a net open position (including existing storage) of 0.1 Bcf.

      On January 1, 2003, we recorded a cumulative effect of a change in accounting principle to reflect a change in the way we account for our storage and transportation contracts. Previously we accounted for those contracts under EITF 98-10, Accounting for Energy Trading and Risk Management Activities , which required us to record estimated future gains on our storage and transportation contracts at the time we entered into the contracts and to mark those contracts to market value each month. Effective January 1, 2003, we no longer marked those contracts to market. As a result, we expensed $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Long-term debt at March 31, 2004 and September 30, 2003 consisted of the following: