ATMOS ENERGY CORP - 10-Q Quarterly Report

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 þ No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes þ No o

Number of shares outstanding of each of the issuer’s classes of common stock, as of January 30, 2004.

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).

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

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.

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

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

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.

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

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

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.

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.

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.

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:

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

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:

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.

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.

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

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

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

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

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.

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

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.

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.


	•	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.

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.

Balance sheet information at December 31, 2003 and September 30, 2003 by segment is presented in the following tables:

We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of December 31, 2003 and the related condensed consolidated statements of income and cash flows for the three-month periods ended December 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to the accompanying condensed consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.

We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2003, and the related consolidated statements of income, shareholders’ equity and cash flows for the year then ended (not presented herein) and in our report dated November 10, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2003 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2003.

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of the Company’s documents or oral presentations, the words “anticipate,” “expect,” “estimate,” “plans,” “believes,” “objective,” “forecast,” “goal” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to the Company’s strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions such as warmer than normal weather in the Company’s utility service territories or colder than normal weather which could adversely affect our natural gas marketing activities; regulatory trends and decisions, including deregulation initiatives and the impact of rate proceedings before various state regulatory commissions; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; national, regional and local economic conditions, limited access to financial markets; inflation and increased gas costs, including their effect on commodity prices for natural gas; increased competition; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. A discussion of these risks and uncertainties may be found in the Company’s Form 10-K for the year ended September 30, 2003. Accordingly, while the Company believes these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.

Atmos Energy Corporation and its subsidiaries are primarily engaged in the natural gas utility business as well as certain non-utility businesses. Our operations are divided into three segments: the utility segment, the natural gas marketing segment and our other non-utility segment.

Our utility segment includes our regulated natural gas distribution and sales operations and is operated through our six regulated natural gas utility divisions:


	•	Atmos Energy Colorado — Kansas Division

	•	Atmos Energy Kentucky Division

	•	Atmos Energy Louisiana Division

	•	Atmos Energy Mid-States Division

	•	Atmos Energy Texas Division

	•	Mississippi Valley Gas Company Division

Our natural gas utility distribution business is seasonal and dependent on weather conditions in our service areas. Gas sales to residential and commercial customers are greater during the winter months than during the remainder of the year. The volumes of gas sales during the winter months will vary with the temperatures during these months. The seasonal nature of our sales to residential and commercial customers is partially offset by our sales in the spring and summer months to our agricultural customers in Texas, Colorado and Kansas who use natural gas to operate irrigation equipment.

In addition to weather, our revenues are affected by the cost of natural gas and economic conditions in the areas that we serve. Higher gas costs, which we are generally able to pass through to our customers under purchased gas adjustment clauses, may cause customers to conserve, or, in the case of industrial customers, to use alternative energy sources.

The effects of weather that is above or below normal are partially offset through weather normalization adjustments (WNA) in certain service areas. WNA allows us to increase the base rate portion of customers’ bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. As of December 31, 2003, we have WNA in the following service areas for the following periods, which cover approximately 854,000 or 51 percent of our meters in service:

Our natural gas marketing and other non-utility segments, which are organized under Atmos Energy Holdings, Inc., (AEH) 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 management through the use of derivative products. In providing these services, AEM generates income from its utility, municipal and industrial customers through negotiated prices based on the volume of gas supplied to the customer. AEM also generates income by taking advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices by utilizing storage and transportation capacity that it controls. Finally, AEM supplies our regulated operations with a portion of our natural gas requirements on a competitive bid basis.

AEM’s management of natural gas requirements involves the sale of natural gas and the management of storage and transportation supplies under contracts with customers generally having one to two year terms. AEM also sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years.

Our other non-utility segment consists 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, LLC, we own or have an interest in underground storage fields in Kansas, Kentucky and Louisiana. We use these storage facilities to help meet customer requirements during peak demand periods and to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. We normally inject gas into pipeline storage systems and company owned storage facilities during the summer months and withdraw it in the winter months.

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.

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 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.

Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Our critical accounting policies are reviewed by the Audit Committee on a quarterly basis. Actual results may differ from 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 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 financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in their financial statements. We record regulatory assets for costs that have been deferred for which 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 customers through the ratemaking process. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized because they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our utility operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.

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 a commodity 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 related to our natural gas marketing energy trading contracts and unrealized gains and losses from changes in the market value of open contracts are included as a component of natural gas marketing revenues.

Allowance for Doubtful Accounts — 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.

Derivatives and Hedging Activities — We use a combination of storage and financial hedges to protect us and our natural gas utility customers against unusually large winter period gas price increases. Further, 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 gas futures, including forwards, over-the-counter and exchange-traded options and swap contracts with counterparties.

Our financial hedges are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. 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 estimates 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 and other assumptions used in these models directly affect our estimate of the fair value of these transactions.

However, because the costs of financial instruments used in our utility segment will ultimately be recovered through our rates, current period changes in the assets and liabilities from these risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial instruments. The changes in the assets and liabilities from risk management activities are recognized in purchased gas cost in the income statement when the related costs are recovered through our rates.

In the management of natural gas requirements for municipalities and other local utilities, AEM sells physical natural gas to customers for future delivery. 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 obligation, 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. However, at any point in time, AEM may not have completely offset its risk on these activities.

AEM’s physical trading activities involve 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 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.

Impairment Assessments — We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. We currently have no indefinite-lived intangible assets. We annually evaluate our goodwill balances for impairment during our second fiscal quarter or as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. Our reporting units and our operating segments are the same as each operating unit represents a component of our business. Goodwill is allocated to the reporting units responsible for the acquisition that gave rise to the goodwill.

The discounted cash flow calculations used to assess goodwill impairment 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.

We periodically evaluate whether events or circumstances have occurred that indicate that our intangible assets subject to amortization and 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 these assets by determining whether the carrying value will be recovered through expected future cash flows. These cash flow projections consider various factors such as the timing of the future cash flows and the discount rate and are based upon the best information available at the time the estimate is made. Changes in these factors could materially affect the cash flow projections and result in the recognition of an impairment charge. An impairment charge is recognized as the difference between the carrying amount and the fair value if the sum of the undiscounted cash flows is less than the carrying value of the related asset.

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. 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. 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 primary factors that impact our results of utility operations are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas sales to residential, commercial and public authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Accordingly, our second fiscal quarter historically has been our most critical earnings quarter with an average of 68 percent of our net income having been earned in the second quarter during the three most recently completed fiscal years. Utility sales to industrial customers are much less weather sensitive. Utility sales to agricultural customers, who typically use natural gas to power irrigation pumps during the period from March through September, are primarily affected by rainfall amounts and the price of natural gas. Changes in the cost of gas impact revenue but do not directly affect our gross profit from utility operations because the fluctuations in gas prices are passed through to the customer. However, increases in the cost of gas may adversely impact our accounts receivable collections resulting in higher bad debt expense.

Our natural gas marketing segment generates income from its industrial, utility and municipal customers through negotiated prices based on the volume of gas supplied to the customer. It also generates income by utilizing storage and transportation capacity that it controls to take advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices.

The following table presents our financial highlights for the three months ended December 31, 2003 and 2002:

The following table reconciles the gross profit and throughput information from a segment basis, before intercompany eliminations, to a consolidated basis:

Gross profit for our utility segment primarily consists of gas service margins generated by our six utility operating divisions from the sale of natural gas to approximately 1.7 million residential, commercial, industrial, agricultural and other customers in the 12 states that comprise our utility service areas.

Utility gross profit increased to $139.4 million for the three months ended December 31, 2003 from $130.1 million for the three months ended December 31, 2002. Total throughput for our utility business was 68.2 billion cubic feet (Bcf) during the current year compared to 70.9 Bcf in the prior year. The increase in utility gross profit primarily reflects the impact of MVG for a full quarter in the current fiscal year quarter compared with one month in the prior fiscal year quarter resulting in an increase in utility gross profit and total throughput of $12.8 million and 5.0 Bcf. This increase was partially offset by the impact of weather that was 12 percent warmer than the prior year and 5 percent warmer than normal, resulting in a decrease of approximately $4.0 million, net of a $2.8 million positive WNA impact in our WNA service areas.

The average cost of gas per Mcf sold increased 26 percent to $6.35 for the three months ended December 31, 2003 from $5.03 for the prior year period, resulting in a 22 percent increase in average sales price. However, changes in the cost of gas do not directly affect utility gross profit because the fluctuations in gas prices are passed through to the customer.

Gross profit for our natural gas marketing segment consists primarily of the difference between revenue arising from the sale of physical natural gas to our natural gas marketing customers less the cost to purchase natural gas and unrealized gains and losses from changes in the market value of derivatives.

Our natural gas marketing gross profit was $17.9 million for the three months ended December 31, 2003 compared to gross profit of $3.9 million for the three months ended December 31, 2002. Natural gas marketing sales volumes were 58.9 Bcf during the current year compared to 59.3 Bcf for the prior year. Our natural gas marketing gross profit included an unrealized gain on open contracts of $4.4 million compared with an unrealized loss on open contracts of $1.1 million in the prior year period.

The improvement in our natural gas marketing profit was primarily attributable to enhanced margins, improved optimization of our managed proprietary and third party storage assets and improved management of our full requirements customers.

Our other non-utility segment gross profit primarily consists of margins generated by our third party storage services and our leasing operations. Our other non-utility segment contributed $1.8 million in gross profit during the three months ended December 31, 2003 compared with $3.2 million for the prior year period. The decrease in our non-utility gross profit was primarily attributable to lower transported volumes of approximately 1.0 Bcf by Atmos Pipeline and Storage in the first quarter of fiscal 2004 primarily due to overall warmer weather.

Operating expenses — Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased 13 percent to $95.5 million for the three months ended December 31, 2003 from $84.5 million for the three months ended December 31, 2002. Operation and maintenance expense increased primarily due to the addition of $6.1 million related to the MVG acquisition in December 2002. Taxes other than income taxes increased $2.3 million primarily due to additional franchise, payroll and property taxes associated with the MVG assets acquired in December 2002. Franchise and state gross receipts taxes are paid by our customers as

a component of their monthly bill; thus, these amounts are offset in revenues through customer billings and have no effect on net income. Depreciation and amortization expense increased $2.3 million, which primarily reflects the full quarter impact of depreciation on the MVG assets.

Miscellaneous income (expense) — Miscellaneous income for the three months ended December 31, 2003 was $1.2 million, compared with income of $4.1 million for the three months ended December 31, 2002. The $2.9 million decrease was primarily attributable to a $3.9 million gain associated with a sales-type lease of a distributed electric generation plant which was recognized in the three months ended December 31, 2002 and lower earnings from our indirect investment in Heritage Propane L.P. as compared with the prior year. Beginning in the second quarter of 2004, we will no longer recognize equity earnings from this indirect investment due to our sale of our interest in USP. Miscellaneous income (expense) was favorably impacted by $1.9 million related to the absence of weather insurance amortization resulting from the termination of our weather insurance policy in the third quarter of fiscal 2003.

Interest charges — Interest charges increased 12 percent for the three months ended December 31, 2003 to $17.3 million from $15.5 million for the three months ended December 31, 2002. The increase was primarily attributable to a higher average outstanding debt balance resulting from the financing obtained to fund the acquisition of MVG in December 2002.

Our working capital and liquidity for capital expenditures and other cash needs are provided from internally generated funds, borrowings under our credit facilities and commercial paper program and funds raised from the public debt and equity capital markets. We believe that these sources of funds will provide the necessary working capital and liquidity for capital expenditures and other cash needs for fiscal 2004.

The following presents our capitalization as of December 31, 2003 and September 30, 2003:

Total debt as a percentage of total capitalization, including short-term debt, was 54.7 percent at December 31, 2003 compared with 53.6 percent at September 30, 2003. The increase in our debt levels during the quarter was primarily attributable to seasonal increases in borrowings under our commercial paper program to fund purchase gas costs to meet our flowing gas requirements. Our long-term plan is to maintain the debt to capitalization ratio within a target range of 50-52 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan, access to the debt and equity capital markets and limiting annual maintenance and capital expenditures.

Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Year-to-year changes in our operating cash flows are primarily attributable to working capital changes within our utility segment resulting from the impact of weather, the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the three months ended December 31, 2003, we generated operating cash flow of $11.5 million compared with a use of cash of $13.4 million for the three months ended December 31, 2002. Our cash flow from operating activities was affected by the following:


	•	Improved customer collections during the current quarter compared with the prior quarter resulting in a $22.6 million increase in operating cash flows.

	•	Favorable timing differences, primarily related to the timing of payments for natural gas purchases, improved operating cash flow by $45.3 million.

	•	Cash used to increase our natural gas inventories was $24.5 million higher in the current quarter compared with the prior year quarter primarily reflecting a 26 percent increase in the average cost of gas.

	•	Alternatively, the lag between the time period when we purchase our natural gas and the period in which we can include this cost in our gas rates adversely impacted our cash flows from operations by $42.5 million.

	•	Other working capital changes improved operating cash flow by $24.0 million.

During the last three years, a substantial portion of our cash resources was used to fund acquisitions, our ongoing construction program to provide natural gas services to our customer base and technology improvements. Capital expenditures for fiscal 2004 are expected to approximate $175.0 million. These expenditures will include additional mains, services, meters and equipment.

For the three months ended December 31, 2003 we invested $45.0 million compared with $109.2 million for the three months ended December 31, 2002. Capital expenditures were $45.5 million during the quarter ended December 31, 2003 compared to $35.3 million for the prior year period. Capital projects for each quarter included expenditures for additional mains, services, meters and equipment to grow our customer base. Additionally, capital expenditures for the current quarter include approximately $3.1 million for Mississippi Valley Gas Company Division capital expenditures compared with $1.3 million in the prior year quarter.

Cash flows used for investing activities for the prior year quarter also included $74.7 million for the cash portion of the Mississippi Valley Gas Company purchase price paid in December 2002.

For the three months ended December 31, 2003 our financing activities provided $59.5 million of cash compared with $113.9 million in the prior year quarter. Our significant financing activities for the three months ended December 31, 2003 and 2002 are summarized as follows:


	•	During the three months ended December 31, 2002, we received $147.0 million from a short-term acquisition credit facility which was used primarily to fund the $74.7 million cash portion of the purchase price for MVG in December 2002 and to repay $70.9 million of MVG’s outstanding debt. This facility was subsequently repaid with a portion of the proceeds received from our $250.0 million debt offering completed in January 2003.

	•	Total short-term debt increased by $73.2 million and $59.6 million for the three months ended December 31, 2003 and 2002 reflecting the use of our lines of credit to fund our natural gas purchases for the winter heating season.


	•	We repaid $5.4 million of long-term debt during the three months ended December 31, 2003 compared with a repayment of $15.0 million for the three months ended December 31, 2002, reflecting the payment of scheduled maturities on our long term debt instruments.

	•	We paid $15.7 million in cash dividends during the three months ended December 31, 2003 compared with dividend payments of $12.5 million for the prior year period. The increase in dividends paid reflects the 1.7 percent increase in the quarterly dividend rate approved by the Board of Directors and the increase in the number of shares outstanding as a result of the shares issued in connection with our public offering in June and July 2003 (the 2003 Offering), the funding of our pension plan in June 2003 and the acquisition of MVG in December 2002.

During the quarter ended December 31, 2003, we issued 321,521 shares of common stock which generated proceeds of $7.4 million. The following table summarizes the issuances for the three months ended December 31, 2003 and 2002:

In December 2001, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $600.0 million in new common stock and/or debt. The registration statement was declared effective by the SEC on January 30, 2002. On January 16, 2003, we issued $250.0 million of 5 1/8% Senior Notes due 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes. Additionally, we sold 4,100,000 shares of our common stock in connection with our 2003 Offering under the registration statement. At December 31, 2003, approximately $246.0 million remains available under the shelf registration statement.

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.

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 at December 31, 2003 was $58.1 million. This credit facility expires on March 31, 2004 and is expected to be renewed.

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 uncommitted demand credit facility described above. At December 31, 2003, $45.0 million was outstanding under this facility.

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risk associated with our utility and non-utility businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Inc. (Fitch). Our current debt ratings are as follows:

Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

On January 10, 2003, S&P changed the outlook on our long-term debt rating from “stable” to “negative.” In its press release explaining this action, S&P cited, among other factors, their concern that we have not made significant progress in reducing our debt to total capitalization ratio. Since S&P changed its outlook, we have issued equity and substantially reduced our leverage. Moody’s and Fitch each continue to maintain a “stable” outlook for our ratings.

We have no trigger events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity based on our credit rating or other trigger events.

In addition to the limit on our total debt to capitalization ratio imposed by our committed credit facilities described above, our 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.

The following tables provide information about contractual obligations and commercial commitments at December 31, 2003.

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. AEM’s fixed price contracts are marked to market as derivatives. See further discussion of the fixed price contracts under Item 3.

For the three months ended December 31, 2003 and 2002 our total net periodic pension and other benefits cost was $7.6 million and $7.0 million. 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 operation and maintenance expense. These costs 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 of fiscal 2004, beginning in the second quarter of 2004. However, our assessment of the reduction has not been completed.

The increase in total net periodic pension and other benefits cost during the three months ended December 31, 2003 compared with the three months ended December 31, 2002 is due to an increase in the service cost and interest cost attributable to an increase in the projected benefit obligation. The increase in the projected benefit obligation resulted primarily from an increase in the number of plan participants due to the MVG acquisition and a 125 basis point decrease in the discount rate used to determine the total net periodic pension and other benefits cost in fiscal 2004. Additionally, the expected return on plan assets, which reduces the net periodic pension and other benefits cost, increased as compared with the prior year primarily due to the effects of the contributions we made to the Atmos Pension Account Plan in fiscal 2003 offset by a reduction in the expected return on pension plan assets assumption from 9.25 percent to 9 percent used in the determination of the total net periodic pension and other benefits cost for fiscal 2004.

The following tables present certain operating statistics for our utility, natural gas marketing and other non-utility segments for three months ended December 31, 2003 and 2002. Certain prior year amounts have been reclassified to conform to the current year presentation.


⁽¹⁾	The operational and statistical information includes the operations of MVG since the December 3, 2002 acquisition date.

⁽²⁾	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on 30-year average National Weather Service data for selected locations. Degree day information for the three months ended December 31, 2003 is adjusted for service areas included in the Colorado-Kansas Division, the Amarillo, Texas service area in the Texas Division, the Mid-States Division, the Kentucky Division and the Mississippi Valley Gas Company Division which have weather normalized operations. Degree day information for the three months ended December 31, 2002 is adjusted for service areas included the Mid-States Division, the Kentucky Division and Mississippi Valley Gas Company Division which have weather normalized operations.

⁽³⁾	Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

The following table shows our utility operating income (loss) by division for the three months ended December 31, 2003 and 2002. This presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for rate-making purposes.


⁽¹⁾	Operating income for Mississippi Valley Gas Company reflects operating income since our acquisition of MVG on December 3, 2002.

Atmos Energy Colorado-Kansas Division. In May 2003, the Colorado-Kansas Division filed a rate case with the Kansas Corporation Commission for approximately $7.4 million in additional annual revenues. In January 2004, the Kansas Corporation Commission approved an agreement that allowed a $2.5 million increase in our rates effective March 1, 2004. Additionally, the agreement allows us to increase our monthly customer charges from $5 to $8 and provides that we will not file another full rate application prior to September 1, 2005. Additionally, effective October 2003, WNA became effective in Kansas in accordance with the Kansas Corporation Commission’s ruling in May 2003.

Atmos Energy Texas Division. In September 2003, the Texas Division filed a rate case in its West Texas System to request a $7.7 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. Additionally, in October 2003, we filed a rate case in Lubbock to request a $3.0 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. These filings are still in process with the respective regulatory authorities.

Beginning in October 2003, WNA became effective for our Amarillo, Texas service area in accordance with an agreement approved by the City of Amarillo in August 2003.

Mississippi Valley Gas Company Division. The Mississippi Public Service Commission requires that we file for rate adjustments every six months. The rate filings are made in May and November of each year and the rate adjustments typically become effective in June and December. In October 2003, the Mississippi Public Commission issued a final order which denied our May 2003 request for a rate adjustment. Additionally, we filed our second semi-annual filing on November 5, 2003, and received a rate increase of $5.9 million effective on December 1, 2003.

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 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 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 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 revised SFAS 132, 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.

The fair value of our utility and natural gas marketing derivative contracts at December 31, 2003 is segregated below, by time period and fair value source.

The risk inherent in our market risk-sensitive instruments is the potential loss arising from adverse changes in natural gas commodity prices and interest rates as discussed below. The sensitivity analysis does not, however, consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions we may take to mitigate exposure to such changes. Actual results may differ.

Our utility segment’s hedging activities are designed to protect us and our customers against unusually large winter period gas price increases and include the use of financial hedges and fixed forward contracts. 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 was designed for 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 amortization expense of $1.9 million. However, we did not recognize income under this policy because weather was not at least seven percent warmer than normal.

We purchase natural gas for our utility operations. Substantially all of the cost of gas purchased for utility operations is recovered from our customers through purchased gas adjustment mechanisms. The utility segment has limited market risk in gas prices related to gas purchases in the open market at spot prices for sale to non-regulated energy services customers at fixed prices. As a result, our earnings could be affected by changes in the price and availability of such gas. To protect against volatility in gas prices, we hedge our gas costs by purchasing futures contracts and by purchasing gas in advance of the winter heating season and

placing it in storage. Our utility segment does not use such financial instruments for trading purposes and we are not a party to any leveraged derivatives. Market risk is estimated as a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on projected fiscal 2004 non-regulated gas sales at fixed prices based upon the December 31, 2003 three month market strip, such an increase would result in an increase to cost of gas of approximately $6.5 million in fiscal 2004.

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 gas futures to physical delivery of natural gas and typically balances its futures 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. At December 31, 2003, AEM’s net open positions in its trading operations totaled 19 MMcf.

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 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.

Because AEM’s operations are concentrated in the natural gas industry, its customers and suppliers may be subject to economic risks affecting that industry. Therefore, an economic downturn in the industry could have an adverse affect on the creditworthiness of AEM’s customers. AEM manages credit risk to attempt to minimize its exposure to uncollectible receivables. In compliance with AEM’s existing credit policy, prospective and existing customers are reviewed for creditworthiness and customers not meeting minimum standards, at the discretion of management, provide security deposits and are subject to various requisite secured payment terms.

Our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper and our other short-term borrowings. If market interest rates for short-term borrowings in the first quarter of fiscal 2004 had averaged one percent more, our interest expense would have increased by approximately $1.8 million.

Market risk for fixed-rate long-term obligations is estimated as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates and amounts to approximately $85.1 million based on discounted cash flow analyses.

As of December 31, 2003 we were not engaged in other activities which would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates or market commodity prices.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including the Chairman, President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Chairman, President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures continue to be effective.

Such disclosure controls and procedures are controls and procedures designed to ensure that all information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods set forth in applicable Securities and Exchange Commission forms, rules and regulations. In addition, we have reviewed our internal control over financial reporting and have concluded that there has been no change in such internal control during the first quarter of 2004 that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

See Note 9 to the condensed consolidated financial statements herein for a description of our legal proceedings.

A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	By:	/s/ JOHN P. REDDY



	John P. Reddy
	Senior Vice President and Chief Financial Officer
	(Duly authorized signatory)

These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended December 31, 2003

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to


Texas and Virginia		75-1743247
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas (Address of principal executive offices)		75240 (Zip code)


Class		Shares Outstanding

No Par Value		51,847,832


PART 1. FINANCIAL INFORMATION
	Item 1. Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures about Market Risk
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Changes in Securities and Use of Proceeds
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
Seventh Amendment to Joinder Agreement
Computation of Ratio of Earnings to Fixed Charges
Letter Re: Unaudited Interim Financial Information
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certifications


			December 31,			September 30,
			2003			2003

			(Unaudited)

			(In thousands)
ASSETS
Property, plant and equipment			$	2,523,100		$	2,480,139
	Less accumulated depreciation and amortization			984,876			964,150

		Net property, plant and equipment		1,538,224			1,515,989
Current assets
	Cash and cash equivalents			41,710			15,683
	Cash held on deposit in margin account			1,934			17,903
	Accounts receivable, net			407,045			216,783
	Gas stored underground			192,568			168,765
	Other current assets			88,673			38,863

		Total current assets		731,930			457,997
Goodwill and intangible assets				274,840			273,499
Deferred charges and other assets				267,952			271,023

			$	2,812,946		$	2,518,508

CAPITALIZATION AND LIABILITIES
Shareholders’ equity
	Common stock, no par value (stated at $.005 per share); 100,000,000 shares authorized; issued and outstanding: December 31, 2003 — 51,797,306 shares; September 30, 2003 — 51,475,785 shares		$	259		$	257
	Additional paid-in capital			743,591			736,180
	Retained earnings			136,336			122,539
	Accumulated other comprehensive loss			(834	)		(1,459	)

		Shareholders’ equity		879,352			857,517
Long-term debt				860,705			863,918

		Total capitalization		1,740,057			1,721,435
Current liabilities
	Accounts payable and accrued liabilities			372,430			179,852
	Other current liabilities			120,743			127,923
	Short-term debt			191,795			118,595
	Current maturities of long-term debt			7,195			9,345

		Total current liabilities		692,163			435,715
Deferred income taxes				243,079			223,350
Deferred credits and other liabilities				137,647			138,008

			$	2,812,946		$	2,518,508



			Three Months Ended
			December 31

			2003			2002


			(Unaudited)
			(In thousands, except
			per share data)
Operating revenues
	Utility segment		$	460,488		$	399,968
	Natural gas marketing segment			373,829			343,498
	Other non-utility segment			3,628			2,900
	Intersegment eliminations			(74,329	)		(65,934	)

				763,616			680,432
Purchased gas cost
	Utility segment			322,064			270,495
	Natural gas marketing segment			356,331			339,508
	Other non-utility segment			327			(1,126	)
	Intersegment eliminations			(74,159	)		(65,611	)

				604,563			543,266

	Gross profit			159,053			137,166

Operating expenses
	Operation and maintenance			56,916			50,504
	Depreciation and amortization			23,473			21,194
	Taxes, other than income			15,123			12,844

		Total operating expenses		95,512			84,542

Operating income				63,541			52,624

Miscellaneous income				1,207			4,124
Interest charges				17,335			15,479

Income before income taxes				47,413			41,269
Income tax expense				17,872			15,476

		Net income	$	29,541		$	25,793

Basic net income per share			$	0.57		$	0.60

Diluted net income per share			$	0.57		$	0.60

Cash dividends per share			$	0.305		$	0.300

Weighted average shares outstanding:
	Basic			51,483			42,796

	Diluted			51,861			42,919


Division		Service Area

Atmos Energy Colorado-Kansas Division		Colorado, Kansas, Missouri
Atmos Energy Kentucky Division		Kentucky
Atmos Energy Louisiana Division		Louisiana
Atmos Energy Mid-States Division		Georgia, Illinois, Iowa, Missouri, Tennessee, Virginia
Atmos Energy Texas Division		Texas
Mississippi Valley Gas Company Division ⁽¹⁾		Mississippi


Net property, plant and equipment		$	156,611
Current assets			40,972
Rights-of-way			11,746
Goodwill			83,109
Deferred charges and other assets			9,642

	Total assets acquired		302,080
Current liabilities			(47,800	)
Noncurrent liabilities			(81,753	)
Other acquisition related costs			(23,227	)

	Purchase price	$	149,300


	Three Months Ended
	December 31, 2002

	(In thousands)
Operating revenue	$	716,189
Net income		22,625
Net income per diluted share	$	0.50


			Natural Gas		Other Non-
	Utility		Marketing		Utility
	Segment		Segment		Segment		Total


	(In thousands)
Balance as of September 30, 2003	$	233,741	$	22,600	$	12,128	$	268,469
Refinements to purchase price		1,559		—		—		1,559

Balance as of December 31, 2003	$	235,300	$	22,600	$	12,128	$	270,028



		For the Three Months
		Ended December 31

		2003		2002


		(In thousands)
Net income		$	29,541	$	25,793

Denominator for basic income per share — weighted average common shares			51,483		42,796
Effect of dilutive securities:
	Restricted stock		132		61
	Stock options		246		62

Denominator for diluted income per share — weighted average common shares			51,861		42,919

Income per share — basic		$	0.57	$	0.60

Income per share — diluted		$	0.57	$	0.60


8.	Interim Pension and Other Post Retirement Benefit Plan Information



			Pension Benefits						Other Benefits

			2003			2002			2003			2002


			(Unaudited)
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	2,433		$	2,060		$	1,725		$	1,476
	Interest cost			6,004			5,834			2,103			2,269
	Expected return on assets			(7,524	)		(5,988	)		(335	)		(253	)
	Amortization of transition asset			24			24			378			378
	Amortization of prior service cost			(2	)		35			96			92
	Amortization of actuarial loss			2,018			632			635			444

		Net periodic pension cost	$	2,953		$	2,597		$	4,602		$	4,406

Actuarial assumptions used to develop net periodic pension cost:
		Discount rate		6.00	%		7.25	%		6.00	%		7.25	%
		Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
		Expected return on plan assets		9.00	%		9.25	%		5.30	%		5.30	%



	At December 31, 2003

			Natural Gas		Other
	Utility		Marketing		Non-utility
	Segment⁽¹⁾		Segment		Segment		Consolidated


	(In thousands)
Investment grade counterparties	$	8,351	$	19,732	$	—	$	28,083
Non-investment grade counterparties		—		1,334		—		1,334

	$	8,351	$	21,066	$	—	$	29,417



			For the Three Months Ended December 31, 2003

					Natural Gas		Other
			Utility		Marketing		Non-Utility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	460,209	$	301,424	$	1,983	$	—		$	763,616
Intersegment revenues				279		72,405		1,645		(74,329	)		—

				460,488		373,829		3,628		(74,329	)		763,616
Purchased gas cost				322,064		356,331		327		(74,159	)		604,563

	Gross profit			138,424		17,498		3,301		(170	)		159,053
Operating expenses				89,046		4,288		2,348		(170	)		95,512

Operating income				49,378		13,210		953		—			63,541
Miscellaneous income (expense)				1,067		123		1,195		(1,178	)		1,207
Interest charges				17,060		792		661		(1,178	)		17,335

Income before income taxes				33,385		12,541		1,487		—			47,413
Income tax expense				12,274		5,005		593		—			17,872

		Net income	$	21,111	$	7,536	$	894	$	—		$	29,541


Item 1.	*Financial Statements*


1.	Nature of Business


	*Utility Segment*


	*Natural Gas Marketing Segment*



			For the Three Months Ended December 31, 2002

						Natural
						Gas		Other
			Utility			Marketing		Non-Utility			Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	399,685		$	278,886	$	1,861		$	—		$	680,432
Intersegment revenues				283			64,612		1,039			(65,934	)		—

				399,968			343,498		2,900			(65,934	)		680,432
Purchased gas cost				270,495			339,508		(1,126	)		(65,611	)		543,266

	Gross profit			129,473			3,990		4,026			(323	)		137,166
Operating expenses				80,326			2,614		1,925			(323	)		84,542

Operating income				49,147			1,376		2,101			—			52,624
Miscellaneous income (expense)				(842	)		929		4,938			(901	)		4,124
Interest charges				14,835			1,040		505			(901	)		15,479

Income before income taxes				33,470			1,265		6,534			—			41,269
Income tax expense				12,411			497		2,568			—			15,476

		Net income	$	21,059		$	768	$	3,966		$	—		$	25,793



			At September 30, 2003

					Natural Gas			Other
			Utility		Marketing			Non-Utility		Eliminations			Consolidated


			(In thousands)
ASSETS
Property, plant and equipment, net			$	1,446,976	$	9,288		$	59,725	$	—		$	1,515,989
Investment in subsidiaries				133,586		(2,662	)		—		(130,924	)		—
Current assets
	Cash and cash equivalents			—		14,880			803		—			15,683
	Assets from risk management activities			202		22,941			—		(884	)		22,259
	Other current assets			230,609		197,239			85,119		(92,912	)		420,055
	Intercompany receivables			114,550		—			—		(114,550	)		—

		Total current assets		345,361		235,060			85,922		(208,346	)		457,997
Intangible assets				—		5,030			—		—			5,030
Goodwill				233,741		22,600			12,128		—			268,469
Noncurrent assets from risk management activities				—		1,896			—		(197	)		1,699
Investment in US Propane LLC				—		—			21,071		—			21,071
Deferred charges and other assets				220,258		2,214			25,781		—			248,253

			$	2,379,922	$	273,426		$	204,627	$	(339,467	)	$	2,518,508

CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	857,517	$	74,759		$	58,827	$	(133,586	)	$	857,517
Long-term debt				858,720		—			5,198		—			863,918

		Total capitalization		1,716,237		74,759			64,025		(133,586	)		1,721,435
Current liabilities
	Current maturities of long-term debt			8,227		—			1,118		—			9,345
	Short-term debt			118,595		—			—		—			118,595
	Liabilities from risk management activities			7,941		13,400			—		(551	)		20,790
	Other current liabilities			184,365		183,082			10,008		(90,470	)		286,985
	Intercompany payables			—		5,549			109,001		(114,550	)		—

		Total current liabilities		319,128		202,031			120,127		(205,571	)		435,715
Deferred income taxes				221,912		(9,498	)		11,081		(145	)		223,350
Noncurrent liabilities from risk management activities				—		928			—		(165	)		763
Deferred credits and other liabilities				122,645		5,206			9,394		—			137,245

			$	2,379,922	$	273,426		$	204,627	$	(339,467	)	$	2,518,508


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


	*Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995*


Tennessee		November – April
Georgia		October – May
Mississippi		November – May
Kentucky		November – April
Kansas⁽¹⁾		October – May
Amarillo, Texas⁽¹⁾		October – May


⁽¹⁾	Effective beginning in the 2003-2004 winter heating season


	*Three Months Ended December 31, 2003 compared with Three Months Ended December 31, 2002*



	December 31, 2003			September 30, 2003




	(In thousands, except percentages)
Short-term debt	$	191,795	9.9%	$	118,595	6.4%
Long-term debt		867,900	44.8%		873,263	47.2%
Shareholders’ equity		879,352	45.3%		857,517	46.4%

Total capitalization, including short-term debt	$	1,939,047	100.0%	$	1,849,375	100.0%



		Payments Due by Period

				Less than						After 5
		Total		1 year		1-3 years		4-5 years		years


		(In thousands)
Contractual Obligations
Long-Term Debt		$	867,900	$	7,195	$	10,232	$	11,455	$	839,018
Capital Lease Obligations			5,126		876		1,276		796		2,178
Operating Leases			58,924		10,330		18,821		12,956		16,817

	Total Contractual Obligations	$	931,950	$	18,401	$	30,329	$	25,207	$	858,013

Other Commercial Commitments
Lines of Credit		$	191,795	$	191,795	$	—	$	—	$	—


	*Natural Gas Marketing and Other Non-Utility Operations Sales and Statistical Data*


Item 3.	*Quantitative and Qualitative Disclosures about Market Risk*



	Fair Value of Contracts at December 31, 2003


	Maturity in Years
											Total Fair
Source of Fair Value	Less than 1			1-3			4-5		Greater than 5		Value


	(In thousands)
Prices actively quoted	$	22,795		$	58		$	—	$	—	$	22,853
Prices provided by other external sources		(14,092	)		258			35		—		(13,799	)
Prices based on models and other valuation methods		(1,489	)		(596	)		—		—		(2,085	)

Total Fair Value	$	7,214		$	(280	)	$	35	$	—	$	6,969


Exhibit
Number		Description

	10.1	Seventh Amendment and Joinder Agreement, dated as of December 19, 2003, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC (formerly known as Woodward Marketing, L.L.C.), the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas
	12	Computation of ratio of earnings to fixed charges
	15	Letter regarding unaudited interim financial information
	31	Rule 13a-14(a)/15d-14(a) Certifications
	32	Section 1350 Certifications*