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 31, 2005.

Atmos Energy Corporation (“Atmos” or “the Company”) and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. Through our natural gas utility business, we distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public-authority and industrial customers through our seven regulated natural gas utility divisions, which cover the following service areas:


⁽¹⁾	Acquired in October 2004.

⁽²⁾	Denotes locations where we have more limited service areas.

As further described in Note 3, on October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas). The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, storage, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. We also own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas. On October 1, 2004, we created the Atmos Energy Mid-Tex Division to provide gas distribution services to the approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area we acquired from TXU Gas. We also created the Atmos Pipeline — Texas Division to manage the TXU Gas pipeline and storage operations we acquired.

In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the utility divisions operate. Our shared-services division is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas, and Metairie, Louisiana. However, on November 4, 2004, we entered into an agreement with Capgemini Energy L.P. pursuant to which we will assume the operations of the Waco, Texas call center on April 1, 2005 and will close the purchase of the related assets on October 1, 2005. In connection therewith, all call center services provided by TXU Gas under the transitional services agreement will terminate on April 1, 2005.

Our nonutility businesses include our natural gas marketing operations, our pipeline and storage operations and our other nonutility operations which are provided in 18 states. These operations are either organized under or managed by Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by Atmos Energy Corporation.

Our natural gas marketing operations are managed by Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides a variety of natural gas management services to municipalities, natural

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

Our pipeline and storage operations consist of the operations of the Atmos Pipeline – Texas Division, a division of Atmos Energy Corporation; and of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. As previously discussed, the Atmos Pipeline — Texas Division was purchased from TXU Gas and supplies natural gas to the Atmos Energy Mid-Tex Division, transports natural gas to third parties and manages five underground storage reservoirs in Texas. Through APS, we own or have an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.

Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations. These services, which began April 1, 2004, include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

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, 2004. Because of seasonal and other factors, the results of operations for the three months ended December 31, 2004 are not indicative of expected results of operations for the fiscal year ending September 30, 2005. Further, the impact of the TXU Gas acquisition on the statement of cash flows is reflected in the acquisitions line item; therefore, the net changes in operating assets and liabilities will not reflect balance sheet changes attributable to the acquisition.

Our accounting policies are described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2004. There were no significant changes to our accounting policies during the three months ended December 31, 2004.

We have two stock-based compensation plans that provide for the granting of incentive stock options, nonqualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based restricted stock units to officers and key employees: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. Nonemployee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.

As permitted by Statement of Financial Accounting Standards (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 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, 2004 and 2003 would have been impacted as shown in the following table:

At December 31, 2004, there were 300 options outstanding under the Long-Term Stock Plan for the Mid-States Division, all of which were fully vested. Because of the limited activities of this plan, the pro forma effects of applying SFAS 123 would have less than a $0.01 per diluted share effect on earnings per share.

We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities

and the regulatory cost of removal obligation is separately reported. Significant regulatory assets and liabilities as of December 31, 2004 and September 30, 2004 included the following:

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

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

Accumulated other comprehensive loss, net of tax, as of December 31, 2004 and September 30, 2004 consisted of the following unrealized gains (losses):

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123 (revised), Share-Based Payment. This standard revises SFAS 123, Accounting for Stock-Based Compensation and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. Under SFAS 123 (R), public companies will be required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award. SFAS 123 (R) will become effective for the Company on a prospective basis during the fourth quarter of fiscal 2005. Upon adoption, we will recognize compensation cost for the portion of outstanding awards for which the requisite service has not yet been rendered, based upon the grant-date fair value of those awards calculated under SFAS 123 for pro forma disclosure purposes. The standard also permits us to restate prior period information on a basis consistent with the calculations used for our pro forma stock compensation disclosure. We are currently assessing the impact of this standard and whether we will restate prior period information.

On October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas). The purchase was accounted for as an asset purchase. The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, storage, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs in Texas.

The purchase price for the TXU Gas acquisition was approximately $1.905 billion (after preliminary closing adjustments and before transaction costs and expenses), which we paid in cash. We acquired approximately $121 million of working capital of TXU Gas and did not assume any indebtedness of TXU Gas in connection with the acquisition. TXU Gas retained certain assets and provided for the repayment of all of its indebtedness and redeemed all of its preferred stock prior to closing and retained and agreed to pay certain other liabilities under the terms of the acquisition agreement. The purchase price is subject to adjustment for the actual amount of working capital we acquired and other specified matters. We anticipate that the working capital settlement will be finalized during the second quarter of fiscal 2005.

We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of 9,939,393 shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper

backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. In October 2004, we paid off the outstanding commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004, which generated net proceeds of approximately $1.39 billion, and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of $382.0 million.

The following table summarizes the fair values of the assets acquired and liabilities assumed on October 1, 2004, in thousands:

The sale of TXU Gas’s assets was held through a competitive bid process. We believe the resulting goodwill is recoverable given the expected synergies we can achieve as a result of the TXU Gas acquisition. To that end, the TXU Gas acquisition significantly expands our existing utility operations in Texas. The North Texas operations of TXU Gas bridge our geographic operations between our existing utility operations in West Texas and Louisiana. TXU Gas’s headquarters and service area are centered in Dallas, Texas, which is also the location of our corporate headquarters. Further, the addition of the regulated pipelines and storage operations in North Texas may create additional gas marketing and other opportunities for our non-regulated subsidiaries, which include gas marketing and storage operations. The goodwill generated in the acquisition is deductible for tax purposes.

Our allocation of the purchase price is preliminary and is subject to change due to the pending completion of the working capital settlement and our continuing review of the acquired assets and liabilities. The amount currently allocated to property, plant and equipment represents our estimate of the fair value of the assets acquired. We have based that estimate on the amount we believe will ultimately be approved as rate base for rate setting purposes.

The table below reflects the unaudited pro forma results of the Company and TXU Gas for the three months ended December 31, 2003 as if the acquisition and related financing had taken place at the beginning of fiscal 2004 (in thousands, except per share data):

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

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

⁽¹⁾

Effective October 1, 2004, we created the pipeline and storage segment which reflects the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC, which was previously included in our other nonutility segment. Accordingly, goodwill allocable to Atmos Pipeline and Storage, LLC was transferred to the pipeline and storage segment.

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

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

We use a combination of storage, fixed physical contracts and fixed financial contracts to partially insulate us and our customers against gas price volatility during the winter heating season. Because the gains or losses of financial derivatives 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, Accounting for the Effects of Certain Types of Regulation. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. For the 2004-2005 heating season, we have hedged approximately 50 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $6.22 per Mcf. Our utility hedging activities also include the cost of our Treasury lock agreements which are described in further detail below.

AEM manages its exposure to the risk of natural gas price changes through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our financial derivative activities include fair value hedges to offset changes in the fair value of our natural gas inventory and cash flow hedges to offset anticipated purchases and sales of gas in the future.

Effective April 1, 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales and ceased marking these contracts to market. As a result, unrealized gains and losses on these open derivative contracts are now recorded as a component of accumulated other comprehensive income and are recognized in earnings as a component of revenue when the hedged volumes are sold.

For the three months ended December 31, 2004, the change in the deferred hedging position in accumulated other comprehensive income from an unrealized gain as of September 30, 2004 to an unrealized loss as of December 31, 2004 was attributable to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition of $4.3 million in net deferred hedge gains in net income when the derivatives matured according to their terms. The net deferred hedge loss associated with open cash flow hedges remains subject to market price fluctuations until the positions are

either settled under the terms of the hedge contracts or terminated prior to settlement. Substantially all of the deferred hedging position as of December 31, 2004 is expected to be recognized in net income during fiscal 2005.

Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on December 31, 2004, AEH had a net open position (including existing storage) of 0.3 Bcf.

During fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the anticipated issuance of $875 million of long-term debt subsequent to September 30, 2004. This long-term debt was issued on October 22, 2004 and was used to repay a portion of the commercial paper used to fund the TXU Gas acquisition, as described in Note 3. We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. This amount will remain in accumulated other comprehensive income and will be recognized as a component of interest expense over the next ten years. During the first quarter of fiscal 2005, we recognized approximately $0.9 million of this obligation as a component of interest expense.

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

Our unsecured floating rate debt bears interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At December 31, 2004, the interest rate on our floating rate debt was 2.465 percent.

At December 31, 2004, short-term debt consisted of $15.0 million of commercial paper and $13.8 million outstanding under our bank credit facilities. At September 30, 2004, there were no short-term amounts outstanding under our commercial paper program or bank credit facilities.

our short-term borrowing requirements, which are typically highest during colder winter 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.

As of December 31, 2004, we had two short-term committed credit facilities totaling $618.0 million, one of which is an unsecured facility for $600.0 million that bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our $600.0 million commercial paper program. At December 31, 2004, $15.0 million of commercial paper was outstanding. We entered into this facility on October 22, 2004 to replace our $350.0 million credit facility that served as the backup liquidity facility for our $350.0 million commercial paper program.

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, 2004, we had borrowed $13.8 million under this credit facility.

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 $600.0 million credit facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. The total debt to total capitalization ratio is calculated quarterly and up to $200.0 million in short-term debt may be excluded from the defined capitalization ratio only for the three months ended December 31, 2004. At December 31, 2004, our total-debt-to-total-capitalization ratio, as defined, was 61 percent. Pursuant to the terms of the credit facility, we excluded $28.8 million of short-term debt from the calculation of our total-debt-to-total-capitalization ratio as of December 31, 2004. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under our $600.0 million credit facility are subject to adjustment depending upon our credit ratings.

AEM has a $250.0 million uncommitted-demand working capital credit facility that bears interest at the Eurodollar rate plus 2.5 percent and expires on March 31, 2005. This facility is guaranteed by AEH. At December 31, 2004, no amounts were outstanding under this credit facility. However, at December 31, 2004, AEM letters of credit totaling $117.2 million had been issued under the facility and reduce the amount available that can be borrowed. 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 $32.8 million at December 31, 2004. Finally, this line of credit is collateralized by a blocked account maintained at AEM whereby collections from customers are deposited into the account and AEM withdraws funds from the account through an established approval process.

Atmos Energy Corporation also has an unsecured short-term uncommitted credit line for $25.0 million that is used for working-capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at December 31, 2004, but Atmos Energy Corporation (AEC) letters of credit reduced the amount available by $4.1 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.

In addition, AEM has a $100.0 million intercompany credit facility with AEC through AEH for its nonutility business which bears interest at the Eurodollar rate plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $250.0 million uncommitted-demand credit facility described

above. This facility is used to supplement AEM’s $250.0 million credit facility and has been approved by our state regulators through December 31, 2005. At December 31, 2004, $15.0 million was outstanding under this facility and is eliminated in consolidation.

In addition to the 70 percent limit on our total debt-to-capitalization ratio imposed by our committed credit facilities, 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, 2004 approximately $138.7 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, 2004. If we do not comply with our debt covenants, we may be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our two public debt indentures relating to our senior notes and debentures, as well as our $600.0 million revolving credit agreement, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. In addition, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on any other financial obligation, as defined, by at least $250 thousand. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos is downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.

Except as described above, we have no triggering 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 triggering events.

On October 27, 2004, we completed the public offering of 16,100,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 2,100,000 shares. The offering was priced at $24.75 and generated net proceeds of approximately $382.0 million. We used the net proceeds from this offering, together with net proceeds of $235.7 million from a public offering we conducted in July 2004 and $1.39 billion received from the issuance of senior unsecured notes to pay off the $1.7 billion in outstanding commercial paper described in Note 3 and fund the remainder of the purchase price for the TXU Gas acquisition.

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2004. There were 240,118 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2003 as their exercise price was 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, 2004 and 2003 are presented below. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense. The amounts for the three months ended December 31, 2003 do not reflect the impact of the Medicare Prescription Drug,

Improvement and Modernization Act of 2003 (the Act) as we recognized the impact of the Act beginning in the second quarter of fiscal 2004.

We did not contribute to our pension plans during the three months ended December 31, 2004. We are not required to make a minimum funding contribution during fiscal 2005 nor do we anticipate making any voluntary contributions during fiscal 2005. During the three months ended December 31, 2004, we contributed $2.4 million to our other post-retirement plans and we expect to contribute $11.7 million to these plans during fiscal 2005.

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

We were the 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, in the 72nd Judicial District in the District Court of Lubbock County, Texas. This case was filed to recover damages resulting from various claims involving the sale, measurement, transportation and balancing of natural gas. This case and all related claims have been settled. The settlement did not have a material effect on our financial condition, results of operations or net cash flows.

During the three months ended December 31, 2004, there were no other material changes in the status of the litigation and environmental matters that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2004. However, with the acquisition of the natural gas distribution and pipeline operations of TXU Gas Company on October 1, 2004, we assumed responsibility for certain litigation and claims that arose in the ordinary course of the business of TXU Gas Company. 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.

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, 2004, AEM is committed to purchase 43.3 Bcf within one year and 3.2 Bcf within one to three years under indexed contracts. AEM is committed to purchase 1.0 Bcf within one year under fixed price contracts with prices ranging from $5.24 to $8.91. Purchases under these contracts totaled $360.1 million and $296.7 million for the three months ended December 31, 2004 and 2003.

Our historical utility operations maintain 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.

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in this service area which obligate it to purchase specified volumes at market prices. The estimated commitments under these contracts as of December 31, 2004 are as follows (in thousands):

In January 2005, we signed a letter of intent with a third party to jointly construct, own and operate a 45-mile large diameter natural gas pipeline in the northern portion of the Dallas/ Fort Worth Metroplex. Under terms of the letter of intent, the third party will provide the initial capital to build the pipeline and we will contribute up to $42.5 million within two years of signing of a definitive agreement. The pipeline is expected to be in service by December 2005.

Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern 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 for the utility segment is mitigated by the large number of individual customers and diversity in customer base.

This diversification in AEM’s customers helps mitigate its credit exposure. AEM maintains credit policies with respect to its counterparties that it believes minimizes 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. AEM also monitors the financial condition of existing counterparties on an ongoing basis. Customers not meeting minimum standards are required to provide adequate assurance of financial performance.

AEM maintains 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.

AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable, (2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by the credit department, but are primarily based on external ratings provided by Moody’s Investor Service Inc. and/or Standard & Poor’s Rating Service, a Division of the McGraw-Hill Companies, Inc. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrials and commercials is non-investment grade. The table below shows the percentages related to the investment ratings as of December 31, 2004 and September 30, 2004. As indicated below, a majority of AEM’s customers are rated as investment grade.

The following table presents our derivative counterparty credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of December 31, 2004. 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 composed of counterparties that are below investment grade or 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 composed 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.

Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our seven 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 nonutility businesses we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.


	•	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,

	•	the pipeline and storage segment, which includes our regulated and nonregulated natural gas transmission and storage services and

	•	the other nonutility segment, which includes all of our other nonutility operations.

Effective October 1, 2004, we created the pipeline and storage segment which reflects the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, L.L.C, which was previously included in our other nonutility segment. Segment information for all prior year periods has been restated to reflect our new organizational structure.

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. Although our utility segment operations are geographically dispersed, they are reported as a single segment as each utility division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our annual report on Form 10-K for the fiscal year ended September 30, 2004. 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, 2004 and September 30, 2004 by segment is presented in the following tables:

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of December 31, 2004, and the related condensed consolidated statements of income for the three-month periods ended December 31, 2004 and 2003, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2004 and 2003. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2004, 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 9, 2004, 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, 2004, 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, 2004.

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”, “believe”, “expect”, “estimate”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” 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 that 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; the Company’s ability to continue to access the capital markets; the effects of inflation and changes in the availability and prices of natural gas, including the volatility of natural gas prices; increased competition from energy suppliers and alternative forms of energy; risks relating to the acquisition of the TXU Gas operations, including without limitation, the Company’s increased indebtedness resulting from the acquisition and the successful integration of the TXU Gas operations; and other uncertainties discussed herein, 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, 2004. 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 engaged primarily in the natural gas utility business as well as certain other natural gas nonutility businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public-authority and industrial customers through our seven regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.


	•	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,


	•	the pipeline and storage segment, which includes our regulated and nonregulated natural gas transmission and storage services and

	•	the other nonutility segment, which includes all of our other nonutility operations.

The first quarter of fiscal 2005 was highlighted by our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas). The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs in Texas.

The purchase price for the TXU Gas acquisition was approximately $1.905 billion, before transaction costs and expenses, which we paid in cash. We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of 9,939,393 shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. In October 2004, we paid off the outstanding commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004, which generated net proceeds of approximately $1.39 billion and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of approximately $382.0 million.

As a result of the acquisition, effective October 1, 2004, we created the pipeline and storage segment which reflects the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC, which was previously included in our other nonutility segment.

The TXU Gas acquisition essentially doubled the size of the Company. The following table presents selected financial information for the Mid-Tex Division and Atmos Pipeline – Texas Division operations for the three months ended December 31, 2004:

The impact of the TXU Gas acquisition, combined with continued strong performance in our natural gas marketing segment contributed to the following financial results during the first quarter of fiscal 2005:


	•	Our utility segment net income increased $15.9 million. The increase reflects the impact of the Mid-Tex operations ($17.4 million) and the effect of rate increases in our West Texas and Mississippi jurisdictions that were not in effect during the first quarter of fiscal 2004, partially offset by an increase in interest expense attributable to an increase in our debt balances to fund the TXU Gas acquisition.

	•	Our natural gas marketing segment net income increased $5.7 million during the three months ended December 31, 2004 compared with the three months ended December 31, 2003. The increase in natural gas marketing net income primarily reflects favorable results from the management of our storage portfolio coupled with a favorable movement in the forward indices used to value our storage financial instruments.

	•	Our pipeline and storage segment contributed $9.1 million in net income for the quarter ended December 31, 2004 compared with $0.5 million for the quarter ended December 31, 2003, primarily reflecting the acquisition of the Atmos Pipeline — Division ($6.9 million).

	•	Our total debt to capitalization ratio at December 31, 2004 was 59.8 percent compared with 43.3 percent at September 30, 2004 reflecting the impact of the financing for the TXU Gas acquisition.

	•	Operating cash flow provided $67.9 million compared with $11.5 million, reflecting favorable results in net working capital management efforts partially offset by increases in natural gas stored underground and deferred gas costs.

	•	Capital expenditures increased to $67.2 million from $45.5 million primarily reflecting the acquisition of the Mid-Tex Division ($23.4 million) and the Atmos Pipeline — Division ($1.1 million).

Our condensed 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 estimates are reviewed by the Audit Committee on a quarterly basis. Actual results may differ from estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the year ended September 30, 2004 and include the following:


	•	Regulation

	•	Revenue Recognition

	•	Allowance for Doubtful Accounts

	•	Derivatives and Hedging Activities

	•	Impairment Assessments

	•	Pension and Other Postretirement Plans

There have been no significant changes to these critical accounting policies during the three months ended December 31, 2004.

The following table presents our financial highlights for the three months ended December 31, 2004 and 2003:

The following table shows our operating income by segment for the three-month periods ended December 31, 2004 and 2003. The presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


⁽¹⁾	Operating income for the Mid-Tex Division reflects operating income since October 1, 2004.

⁽²⁾	Operating income for the pipeline and storage segment reflects operating income for the Atmos Pipeline — Texas Division since October 1, 2004.

⁽³⁾	Adjusted for service areas that have weather normalized operations.

Our utility segment has historically contributed 70 to 85 percent of our consolidated net income. The primary factors that impact the results of our 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 has historically been our most critical earnings quarter with an average of approximately 68 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. Additionally, we typically experience higher levels of accounts receivable, accounts payable, gas stored underground and short-term debt balances during the winter heating season due to the seasonal nature of our revenues and the need to purchase and store gas to support these operations. Utility sales to industrial customers are much less weather sensitive. Utility sales to agricultural customers, which 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 our customers. Accordingly, we believe gross profit margin is a better indicator of our financial performance than revenues. However, higher gas costs may cause

customers to conserve, or, in the case of industrial customers, to use alternative energy sources. Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense.

The effects of weather that is above or below normal are partially offset through weather normalization adjustments, or WNA, in certain of our 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, 2004, we had, or received regulatory approvals for, WNA in the following service areas for the following periods, which covered approximately 1.1 million meters:

The Atmos Energy Mid-Tex Division does not have WNA. However, its operations benefit from a rate structure that combines a monthly customer charge with a declining block rate schedule to mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provides for the recovery of most of our fixed costs for such operations under most weather conditions.

Utility gross profit increased to $257.3 million for the three months ended December 31, 2004 from $138.4 million for the three months ended December 31, 2003. Total throughput for our utility business was 118.9 billion cubic feet (Bcf) during the current year compared to 68.2 Bcf in the prior year.

The increase in utility gross profit margin primarily reflects the impact of the Mid-Tex Division resulting in an increase in utility gross profit margin and total throughput of $114.0 million and 51.9 Bcf. The $4.9 million increase in the gross profit generated from our historical operations primarily reflects rate increases in our Mississippi and West Texas jurisdictions that were absent in the prior year quarter.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $172.2 million for the three months ended December 31, 2004 from $89.0 million for the three months ended December 31, 2003. Operation and maintenance expense increased by $44.4 million primarily due to the addition of $40.1 million in operation and maintenance expenses associated with the Mid-Tex Division and higher labor and benefit costs in our historical operations. Taxes other than income taxes increased $22.2 million, primarily due to additional franchise, payroll and property taxes associated with the Mid-Tex assets acquired in October 2004. Franchise and state gross receipts taxes are paid by our customers as a component of their monthly bills; thus, these amounts are offset in revenues through customer billings and have no effect on net income. Depreciation and amortization expense increased $16.6 million, which primarily reflects the inclusion of depreciation associated with the Mid-Tex assets ($15.7 million).

As a result of the aforementioned factors, our utility segment operating income for the three months ended December 31, 2004 increased to $85.1 million from $49.4 million for the three months ended December 31, 2003.

Interest charges allocated to the utility segment for the three months ended December 31, 2004 increased to $27.3 million from $17.1 million for the three months ended December 31, 2003. The increase was attributable to the interest expense associated with the issuance of long-term debt to finance the acquisition of the Mid-Tex Division in October 2004.

Our natural gas marketing segment aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers the gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative products. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues for services we deliver.

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

Gross profit margin for our natural gas marketing segment consists primarily of marketing activities, which represent the utilization of proprietary and customer-owned transportation and storage assets to provide the various services our customers request, and storage activities, which are derived from the optimization of our managed proprietary and third party storage and transportation assets.

Our natural gas marketing segment’s gross profit margin was comprised of the following for the three months ended December 31, 2004 and 2003:

Our natural gas marketing segment’s gross profit margin was $26.8 million for the three months ended December 31, 2004 compared to gross profit of $17.5 million for the three months ended December 31, 2003.

Natural gas marketing sales volumes were 66.1 Bcf during the three months ended December 31, 2004 compared with 70.2 Bcf for the prior year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 60.3 Bcf during the current year period compared with 58.9 Bcf in the prior year period. The increase in consolidated natural gas marketing sales volumes was primarily due to our ability to sell volumes we purchased under favorable pricing conditions at a lower price than our competitors in certain of our markets, partially offset by continued efforts to eliminate lower margin transactions and focus our marketing efforts on higher margin customers. Gross profit margin from our natural gas marketing segment for the three months ended December 31, 2004 included an unrealized gain of $10.7 million compared with an unrealized gain of $5.1 million in the prior-year period.

The contribution to gross profit from our storage activities was a gain of $17.3 million for the three months ended December 31, 2004 compared to a gain of $5.6 million for the three months ended December 31, 2003. The $11.7 million improvement primarily was attributable to a $3.2 million improvement in the realized storage contribution and an $8.5 million improvement in the unrealized storage contribution for the three months ended December 31, 2004 compared to the prior year period. The improvement in the realized storage contribution for the three months ended December 31, 2004 primarily was due to our ability to capture higher spreads in our storage book during the current year and the restructuring of certain asset management transactions to improve the profitability of these transactions. The increase in unrealized income in the current period was primarily attributable to a favorable movement during the three months ended December 31, 2004 in the forward indices used to value the storage financial instruments combined with greater physical natural gas storage quantities at December 31, 2004 compared to the prior year period.

Our marketing activities contributed $9.5 million to our gross profit for the three months ended December 31, 2004 compared to $11.9 million for the three months ended December 31, 2003. The decrease in the marketing contribution primarily was attributable to an unfavorable movement in the forward indices used to value certain financial instruments partially offset by the increase in sales volumes as discussed above.

The improved gross profit margin resulted in an increase in our natural gas marketing segment operating income to $23.0 million for the three months ended December 31, 2004 compared with operating income of $13.2 million for the three months ended December 31, 2003.

Our pipeline and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC, which was previously included in our other nonutility segment. The Atmos Pipeline — Texas Division supplies natural gas to the Atmos Energy Mid-Tex Division and transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking arrangements, blending and sales of inventory on hand. These operations represent one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are estimated to contain a substantial portion of the nation’s remaining onshore natural gas reserves. This pipeline system provides access to all of these basins.

Atmos Pipeline and Storage, LLC, owns or has an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.

Similar to our utility segment, our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas transportation requirements are affected by the winter heating season requirements of our customers. 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. Further, as the Atmos Pipeline — Texas Division operations provide all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of this division.

As a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Pipeline and storage gross profit increased to $39.8 million for the three months ended December 31, 2004 from $2.6 million for the three months ended December 31, 2003. Total pipeline transportation volumes were 130.0 Bcf during the three months ended December 31, 2004 compared with 2.4 Bcf for the prior year period. Excluding intersegment transportation volumes, total pipeline transportation volumes were 72.8 Bcf during the current year period. There were no third party transportation volumes in the prior year period as Atmos Pipeline and Storage, LLC’s total throughput was to affiliated parties.

The increase in pipeline and storage gross profit margin primarily reflects the impact of the Atmos Pipeline — Texas Division resulting in an increase in pipeline and storage gross profit margin and total transportation volumes of $34.9 million and 72.8 Bcf. The $2.3 million increase in the gross profit generated by Atmos Pipeline and Storage, LLC primarily reflects an unrealized gain of $1.7 million compared with and unrealized loss in the prior year quarter of $0.7 million.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $19.5 million for the three months ended December 31, 2004 from $1.5 million for the three months ended December 31, 2003 due to the addition of $18.5 million in operating expenses associated with the Atmos Pipeline — Texas Division. As the Atmos Pipeline — Texas Division is a regulated entity, franchise and state gross receipts taxes are paid by our customers; thus, these amounts are offset in revenues through customer billings and have no effect on net income. Included in operating expense was $2.0 million associated with taxes other than income taxes, of which $1.9 million was associated with our Atmos Pipeline — Texas Division.

As a result of the aforementioned factors, our pipeline and storage segment operating income for the three months ended December 31, 2004 increased to $20.3 million from $1.1 million for the three months ended December 31, 2003.

Interest charges allocated to this segment for the three months ended December 31, 2004 increased to $6.2 million from $0.2 million for the three months ended December 31, 2003. The increase was attributable to the interest expense associated with the issuance of long-term debt to finance the acquisition of the Atmos Pipeline — Texas Division in October 2004.

Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC (AES), and Atmos Power Systems, Inc. Through AES, we provide natural gas management services to our utility operations. These services, which began April 1, 2004, include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices. AES’ revenues represent charges to our utility divisions equal to the costs incurred to

provide those services. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

Operating income for this segment primarily reflects the leasing income associated with two sales-type lease transactions completed in 2001 and 2002. The increase in operating income during the three months ended December 31, 2004 compared with the prior year quarter reflects the absence of a one time charge of $0.4 million associated with the wind down of a noncore business.

Miscellaneous income for the three months ended December 31, 2004 was $0.6 million compared with $1.2 million for the three months ended December 31, 2003. The $0.6 million decrease was primarily attributable the absence of equity earnings from our investment in U.S. Propane L.P., which was sold in January 2004.

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 the remainder of fiscal 2005.

The following presents our capitalization as of December 31, 2004 and September 30, 2004:

Total debt as a percentage of total capitalization, including short-term debt, was 59.8 percent at December 31, 2004 and 43.3 percent at September 30, 2004. The increase in the debt to capitalization ratio was attributable to the issuance of $1.39 billion in senior unsecured long-term debt, partially offset by the issuance of 16.1 million shares of our common stock in October 2004 to partially finance the TXU Gas acquisition. Our ratio of total debt to capitalization is expected to be greater during the current winter heating season as we make additional short-term borrowings to fund natural gas purchases and meet our working capital requirements. Within three to five years from the closing of the acquisition, we intend to reduce our capitalization ratio to a target range of 53 to 55 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 equity capital markets and reduced 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, the successful integration of the natural gas distribution and pipeline operations of TXU Gas we acquired and other factors.

Year-over-year changes in our operating cash flows are attributable primarily to changes in net income, working capital changes within our utility segment resulting from the impact of weather, the price of natural

For the three months ended December 31, 2004, we generated operating cash flow of $67.9 million compared with $11.5 million for the three months ended December 31, 2003. Our cash flow from operating activities was affected by the following:


	•	Favorable movements during the three months ended December 31, 2004 in the market indices used to value our risk management assets and liabilities favorably impacted operating cash flow by $26.7 million.

	•	The timing of cash collections from our customers unfavorably impacted operating cash flow by $155.7 million.

	•	The timing of payments for accounts payable and other accrued liabilities favorably affected operating cash flow by $291.3 million.

	•	However, increases in our natural gas inventories attributable to lower utility gas sales volumes coupled with a 14 percent higher average cost of gas compared with the prior year quarter resulted in a $24.4 million decrease in operating cash flows.

	•	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 resulted in a decrease in operating cash flows of $82.6 million.

	•	Other working capital changes positively affected operating cash flow by $1.1 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 2005 are expected to range from $340 million to $350 million. Of this amount, approximately $200 — $210 million is expected to be incurred by the Mid-Tex Division and Atmos Pipeline — Texas Division.

For the three months ended December 31, 2004, we invested $67.2 million compared with $45.5 million for the three months ended December 31, 2003. Capital expenditures for the three months ended December 31, 2004 include approximately $23.4 million for the Atmos Energy Mid-Tex Division and $1.1 million for the Atmos Pipeline — Texas Division.

Our cash used for investing activities for the three months ended December 31, 2004 reflects the $1.913 billion cash paid for the TXU Gas acquisition including related transaction costs and expenses. The final purchase price is subject to adjustment for the actual amount of working capital we acquired and other specified matters. We anticipate that the purchase price will be finalized during the second quarter of fiscal 2005.

For the three months ended December 31, 2004, our financing activities provided $1.7 billion in cash compared with $59.5 million in cash for the prior year quarter. Our significant financing activities for the three months ended December 31, 2004 and 2003 are summarized as follows:


	•	In October 2004, we sold 16.1 million common shares, including the underwriters’ exercise of their overallotment option of 2.1 million shares, under a new shelf registration statement declared effective in September 2004, generating net proceeds of $382.0 million. Additionally, we issued senior unsecured debt under the shelf registration statement consisting of $400 million of 4.00% senior notes due 2009, $500 million of 4.95% senior notes due 2014, $200 million of 5.95% senior notes due 2034 and $300 million of floating rate senior notes due 2007. The floating rate notes will bear interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. The net proceeds received from the sale of these senior notes were $1.39 billion. The net proceeds from these issuances, combined with the


		net proceeds from our July 2004 offering were used to pay off the approximately $1.7 billion in outstanding commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition.

	•	During the three months ended December 31, 2004 and 2003, short-term borrowings under our commercial paper program provided $28.8 million and $73.2 million. The decrease in cash flows provided by short-term borrowings primarily reflects the use of excess proceeds remaining from our October 2004 debt and equity offerings after financing the TXU Gas acquisition to partially fund working capital needs during the first quarter of fiscal 2005.

	•	We repaid $3.4 million of long-term debt during the three months ended December 31, 2004 compared with $5.4 million during the three months ended December 31, 2003. The decreased payments during the current quarter reflected the timing of the maturities of our various debt obligations.

	•	During the three months ended December 31, 2004 we paid $24.5 million in cash dividends compared with dividend payments of $15.7 million for the three months ended December 31, 2003. The increase in dividends paid over the prior year period reflects the 27.5 million increase in the number of common shares outstanding and an increase in the quarterly dividend rate from $0.305 per share during the three months ended December 31, 2003 to $0.31 share during the three months ended December 31, 2004.

	•	During the quarter ended December 31, 2004, we issued 358,046 shares of common stock, in addition to the 16.1 million common shares issued in our October 2004 public offering, which generated net proceeds of $11.1 million. The following table summarizes the issuances for the three months ended December 31, 2004 and 2003:

In August 2004, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $2.2 billion in new common stock and/or debt, which became effective on September 15, 2004. In October 2004, we sold 16.1 million common shares and issued $1.4 billion in unsecured senior notes to partially finance the TXU Gas acquisition. After these issuances, we have approximately $401.5 million of availability remaining under the shelf registration statement.

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the bank. 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 winter 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. Our cash needs for working capital and capital expenditures will increase substantially as a result of the acquisition of the natural gas distribution and pipeline operations of TXU Gas. On October 22, 2004, we replaced our $350.0 million

credit facility with a new $600.0 million committed credit facility that serves as a backup liquidity facility for our commercial paper program. We believe this facility, combined with our operating cash flow will be sufficient to fund these increased working capital needs. These facilities are described in further detail in Note 6 to the consolidated financial statements.

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 nonutility 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 all considered investment grade and are as follows:

Currently, S&P and Moody’s maintain a stable outlook and Fitch maintains a negative outlook. None of our ratings are currently under review.

A credit rating is not a recommendation to buy, sell or hold securities. All of our current ratings for long-term debt are categorized as investment grade. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent 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.

In addition to the 70 percent limit on our total debt-to-capitalization ratio imposed by our committed credit facilities, 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 our accumulated net income for periods after December 31, 1988, plus $15.0 million. At December 31, 2004, approximately $138.7 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, 2004. If we do not comply with our debt covenants, we may be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our two public debt indentures relating to our senior notes and debentures, as well as our $600.0 million revolving credit agreement, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. In addition, Atmos Energy Marketing, LLC’s (AEM) credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on any other financial obligation, as defined, by at least $250 thousand. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos is downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.

As a result of the issuance of our unsecured senior notes in October 2004 and the issuance of short-term debt under our commercial paper program, our contractual obligations associated with our long-term debt, short-term debt and interest expense increased.

The following table reflects the significant changes in our contractual obligations as of December 31, 2004 as a result of these events. There were no other significant changes in our contractual obligations and commercial commitments during the three months ended December 31, 2004.


⁽¹⁾	See Note 6 to the consolidated financial statements.

⁽²⁾	Gas purchase commitments were determined based upon contractually determined volumes at prices estimated based upon the index specified in the contract, adjusted for estimated basis differentials and contractual discounts as of December 31, 2004.

Additionally, in January 2005, we signed a letter of intent with a third party to jointly construct, own and operate a 45-mile large diameter natural gas pipeline in the northern portion of the Dallas/ Fort Worth Metroplex. Under terms of the letter of intent, the third party will provide the initial capital to build the pipeline and we will contribute up to $42.5 million within two years of signing of a definitive agreement.

We conduct risk management activities through both our utility and natural gas marketing segments. In our utility segment, we use a combination of storage, fixed physical contracts and fixed financial contracts to protect us and our customers against unusually large winter-period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock-in our gross profit margin through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could recognize significant ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting resulting in the derivatives being treated as mark to market instruments through earnings.

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. Substantially all of our derivative financial instruments are valued using external market quotes and indices. The following

The fair value of our utility and natural gas marketing derivative contracts at December 31, 2004, is segregated below by time period and fair value source:

AEM engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. AEM purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. AEM is able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market on a monthly basis using the inside FERC (iFERC) price at the end of each month. Derivatives associated with our natural gas inventory are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The difference in the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) is reported as a component of revenue and can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

AEM continually manages its positions to enhance the future profitability of its storage position. Therefore, AEM may change its scheduled injection and withdrawal plans from one time period to another based on market conditions or adjust the amount of storage capacity it holds on a discretionary basis in an effort to achieve this objective. AEM monitors the impacts of these optimization efforts by estimating the forecasted gross profit margin that it captured through the purchase and sale of physical natural gas and the associated financial derivatives. The forecasted gross profit margin, less the effect of unrealized gains or losses recognized in the financial statements, provides a measure of the net increase or decrease in the gross profit margin that could occur in future periods if the optimization efforts are fully attained.

As of December 31, 2004, based upon AEM’s derivatives position and inventory withdrawal schedule, the forecasted gross profit margin was approximately $15.0 million. Approximately $13.0 million of net unrealized

The forecasted gross profit margin calculation is based upon planned injection and withdrawal schedules, and the realization of the forecasted gross profit margin is contingent upon the execution of this plan, weather, and other execution factors. Since AEM actively manages and optimizes its portfolio to enhance the future profitability of its storage position, it may change its scheduled injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot assure that the forecasted gross profit margin or the projected increase in future gross profit margin calculated as of December 31, 2004 will be fully realized in the future and in what time period. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, permanent impacts on earnings may result.

For the three months ended December 31, 2004 and 2003 our total net periodic pension and other benefits cost was $9.1 million and $7.6 million. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense.

The increase in total net periodic pension and other benefits cost during the current year period compared with the prior year period primarily reflects the increase in the number of employees resulting from the TXU Gas acquisition, which increased our service cost. Additionally, we increased our discount rate and reduced our assumed rate of return on our pension plan assets for fiscal 2005, which increased our service and interest cost and reduced our expected return on plan assets, which partially offsets our net periodic pension and other benefits cost.

We did not contribute to our pension plans during the three months ended December 31, 2004. We are not required to make a minimum funding contribution nor do we anticipate making any voluntary contributions during fiscal 2005. During the three months ended December 31, 2004, we contributed $2.4 million to our other post-retirement plans and we expect to contribute $11.7 million to these plans during fiscal 2005.

Although we did not assume the existing employee benefit liabilities or plans of TXU Gas, we have agreed to give certain transitioned employees credit for years of TXU Gas service under our pension plan. For purposes of our post-retirement medical plan, we received a credit of $20.0 million (subject to post-closing adjustment) against the purchase price to permit us to provide partial past service credits for retiree medical benefits under our retiree medical plan. The $20.0 million credit approximates the actuarially determined present value of the accumulated benefits related to the past service of the transferred employees.

The following tables present certain operating statistics for our utility, natural gas marketing, pipeline and storage and other nonutility segments for the three months ended December 31, 2004 and 2003. Certain prior year amounts have been reclassified to conform to the current year presentation.


⁽¹⁾	The operational and statistical information includes the operations of the Mid-Tex Division and Atmos Pipeline — Texas Division since the October 1, 2004 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, 2004 and 2003 is adjusted for certain service areas included within the Colorado-Kansas Division, the West Texas Division, certain service areas in the Mid-States Division, the Kentucky Division and the 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 will discuss our recent ratemaking activities during the first quarter of fiscal 2005. The amounts described below represent the gross revenues that were requested or received in the rate filing, which may not necessarily reflect the increase in operating income obtained, as certain operating costs may have increased as a result of a commission’s final ruling.

Mississippi. The Mississippi Public Service Commission (MPSC) 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. Starting with the November 2004 filing, rate adjustments will typically become effective in January and July. In September 2004, the MPSC authorized additional annualized revenue of $4.7 million on our May 2004 filing, which became effective on June 1, 2004. However, the MPSC also disallowed certain deferred costs totaling $2.8 million. We withdrew our appeal regarding the MPSC’s decision regarding this disallowance.

We filed our second semiannual filing for 2004 on November 5, 2004, requesting rate adjustments of $6.0 million in annualized revenue. The MPSC allowed us to include $3.0 million in annualized revenue into our rates effective January 1, 2005. In February 2005, we and the Mississippi Public Utilities Staff (MPUS) signed a stipulation agreement that provides for an additional $1.3 million in annualized revenue that is retroactive to January 2005. The MPSC is expected to ratify the stipulation agreement during the second quarter of fiscal 2005.

Mid-Tex. In December 2004, we made a filing under the Gas Reliability Infrastructure Program (GRIP) to include approximately $32.0 million of distribution and pipeline capital expenditures made by TXU Gas during calendar year 2003, which will result in additional revenues of approximately $6.7 million. We expect these capital costs will be recovered through a monthly customer charge beginning in the second half of fiscal 2005. The allowed rate of return is 8.258 percent.

In September 2004, the Mid-Tex Division filed its 36-Month Gas Contract Review with the Railroad Commission of Texas (the Commission). This proceeding involves a prudency review of gas purchases totaling $2.2 billion made by the Mid-Tex Division from November 1, 2000 through October 31, 2003. The proceeding has involved informal discussions in preparation for potential settlement discussions. However, a formal procedural schedule has been adopted providing for formal discovery and a formal hearing in the event that settlement can not be reached.

The Mid-Tex Division is also pursuing an appeal to the Travis County District Court of the Final Order in its last systemwide rate case completed in May 2004 to obtain a return on its investment associated with the Poly I replacement pipe that was originally disallowed in the last rate case. Additionally, the Mid-Tex Division is seeking the right to surcharge for gas cost underrecoveries. The case is awaiting assignment of a judge and the establishment of a briefing schedule.

During the first quarter of fiscal 2005, the Mid-Tex Division pursued a filing initiated by TXU Gas seeking authorization of a surcharge to recover the rate case expenses incurred by the Mid-Tex Division, Atmos Pipeline — Texas Division, and the intervening cities in connection with their last systemwide rate case completed in May 2004. The filing also covered the estimated expenses to prosecute the aforementioned recovery docket and the severed dockets from the systemwide rate case. On January 25, 2005, the Commission issued an order authorizing the recovery of the $10.2 million over a 3-year period with interest. This order is still subject to potential motions for rehearing and court appeals.

Atmos Pipeline — Texas. Concurrent with our Mid-Tex Division GRIP filing in December 2004, we also made a GRIP filing for our regulated pipeline to include approximately $12.0 million of distribution and pipeline capital expenditures made by TXU Gas during calendar year 2003, which will result in additional revenues of approximately $1.8 million. We expect these capital costs will be recovered through a monthly customer charge beginning in the second half of fiscal 2005. The allowed rate of return is 8.258 percent.

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the condensed consolidated financial statements.

We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest-rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business.

We conduct risk management activities through both our utility and natural gas marketing segments. In our utility segment, we use a combination of storage, fixed physical contracts and fixed financial contracts to protect us and our customers against unusually large winter period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock-in our gross profit margin through a combination of storage and financial derivatives including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our risk management activities and related accounting treatment are described in further detail in Note 5 to the condensed consolidated financial statements. Additionally, 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.

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. However, our utility operations have commodity price risk exposure to fluctuations in spot natural gas prices related to purchases for sales to our non-regulated energy services customers at fixed prices.

For our utility segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on projected non-regulated gas sales for the remainder of fiscal 2005, a hypothetical 10 percent increase in fixed prices, based upon the December 31, 2004 three month market strip, would increase our purchased gas cost by approximately $4.5 million for the remainder of fiscal 2005.

Our natural gas marketing segment is also exposed to risks associated with changes in the market price of natural gas. For our natural gas marketing segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open position (including existing storage) at the end of each period. Based on AEH’s net open position (including existing storage) at December 31, 2004 of 0.3 Bcf, a $0.50 change in the forward NYMEX price would have had less than a $0.1 million impact on our consolidated net income.

Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short term borrowings. Had interest rates associated with our short term borrowings increased by an average of one percent, our interest expense would have increased by approximately $0.3 million during the three months ended December 31, 2004.

We also assess market risk for our fixed-rate, long-term obligations. We estimate market risk for our fixed-rate, long-term obligations as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates associated with these debt instruments. Fair value is estimated using a discounted cash flow analysis. Assuming this one percent hypothetical decrease, the fair value of our fixed-rate, long-term obligations would have increased by approximately $155.7 million during the three months ended December 31, 2004.

As of December 31, 2004 we were not engaged in other activities that 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 the Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) and 15d-15(b). Based upon that evaluation, the Chairman, President and Chief Executive Officer, and the 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, our management, including the Chairman, President and Chief Executive Officer, and the Senior Vice President and Chief Financial Officer, evaluated our internal control over financial reporting pursuant to Exchange Act Rules 13a-15(d) and 15d-15(d). Based upon that evaluation, management has concluded that there has been no change in such internal control during the first quarter of fiscal 2005 that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

During the three months ended December 31, 2004, there were no material changes in the status of the litigation and environmental matters that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2004 except as disclosed in Note 10 to the condensed consolidated financial statements for the three months ended December 31, 2004. With the acquisition of the natural gas distribution and pipeline operations of TXU Gas Company on October 1, 2004, we assumed responsibility for certain litigation and claims that arose in the ordinary course of the business of TXU Gas Company. 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.

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, 2004

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		79,348,039


PART 1. FINANCIAL INFORMATION
	Item 1. Financial Statements
ATMOS ENERGY CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) December 31, 2004
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
	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 6. Exhibits
SIGNATURES
EXHIBITS INDEX Item 6(a)
11th Amendment to Credit Agreement
Form of Non-Qualified Stock Option Agreement
Form of Restricted Stock Award Agreement
Form of Award Agreement of Performance-Based Restricted Stock Units
Form of Award Agreement of Restricted Stock with Time-Lapse Vesting
Computation of Ratio of Earnings to Fixed Charges
Letter Re: Unaudited Interim Financial Information
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications


			December 31,			September 30,
			2004			2004

			(Unaudited)

			(In thousands, except share data)
ASSETS
Property, plant and equipment			$	4,544,069		$	2,633,651
	Less accumulated depreciation and amortization			1,320,926			911,130

		Net property, plant and equipment		3,223,143			1,722,521
Current assets
	Cash and cash equivalents			25,162			201,932
	Accounts receivable, net			640,760			211,810
	Gas stored underground			389,625			200,134
	Other current assets			152,686			63,236

		Total current assets		1,208,233			677,112
Goodwill and intangible assets				703,038			238,272
Deferred charges and other assets				271,682			231,978

			$	5,406,096		$	2,869,883

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, 2004 — 79,257,756 shares; September 30, 2004 — 62,799,710 shares	$	396		$	314
	Additional paid-in capital			1,393,250			1,005,644
	Retained earnings			177,108			142,030
	Accumulated other comprehensive loss			(31,676	)		(14,529	)

		Shareholders’ equity		1,539,078			1,133,459
Long-term debt				2,255,173			861,311

		Total capitalization		3,794,251			1,994,770
Current liabilities
	Accounts payable and accrued liabilities			653,403			185,295
	Other current liabilities			283,130			223,265
	Short-term debt			28,797			—
	Current maturities of long-term debt			5,897			5,908

		Total current liabilities		971,227			414,468
Deferred income taxes				200,737			213,930
Regulatory cost of removal obligation				241,986			103,579
Deferred credits and other liabilities				197,895			143,136

			$	5,406,096		$	2,869,883



			Three Months Ended
			December 31

			2004			2003


			(Unaudited)

			(In thousands, except per
			share data)
Operating revenues
	Utility segment		$	913,681		$	460,488
	Natural gas marketing segment			493,801			373,829
	Pipeline and storage segment			43,690			2,919
	Other nonutility segment			1,359			709
	Intersegment eliminations			(83,907	)		(74,329	)

				1,368,624			763,616
Purchased gas cost
	Utility segment			656,370			322,064
	Natural gas marketing segment			466,957			356,331
	Pipeline and storage segment			3,872			327
	Other nonutility segment			—			—
	Intersegment eliminations			(83,027	)		(74,159	)

				1,044,172			604,563

	Gross profit			324,452			159,053
Operating expenses
	Operation and maintenance			113,126			56,916
	Depreciation and amortization			43,997			23,473
	Taxes, other than income			38,655			15,123

		Total operating expenses		195,778			95,512

Operating income				128,674			63,541
Miscellaneous income				385			1,207
Interest charges				32,542			17,335

Income before income taxes				96,517			47,413
Income tax expense				36,918			17,872

		Net income	$	59,599		$	29,541

Basic net income per share			$	0.79		$	0.57

Diluted net income per share			$	0.79		$	0.57

Cash dividends per share			$	0.310		$	0.305

Weighted average shares outstanding:
	Basic			75,306			51,483

	Diluted			75,725			51,861


Division		Service Area

Atmos Energy Colorado-Kansas Division		Colorado, Kansas, Missouri⁽²⁾
Atmos Energy Kentucky Division		Kentucky
Atmos Energy Louisiana Division		Louisiana
Atmos Energy Mid-States Division		Georgia⁽²⁾, Illinois⁽²⁾, Iowa ⁽²⁾,
		Missouri⁽²⁾Tennessee, Virginia⁽²⁾
Atmos Energy West Texas Division		West Texas
Mississippi Valley Gas Company Division		Mississippi
Atmos Energy Mid-Tex Division⁽¹⁾		Texas, including the Dallas/Fort
		Worth metropolitan area


Cash purchase price		$	1,904,877
Transaction costs and expenses			7,655

	Total purchase price	$	1,912,532

Net property, plant and equipment		$	1,472,295
Accounts receivable			81,035
Gas stored underground			141,664
Other current assets			19,089
Goodwill			464,963
Deferred charges and other assets			41,634
Accounts payable and accrued liabilities			(43,216	)
Other current liabilities			(88,939	)
Regulatory cost of removal obligation			(138,991	)
Deferred income taxes			10,993
Deferred credits and other liabilities			(47,995	)

	Total	$	1,912,532


	Three Months Ended
	December 31, 2003

Operating revenue	$	1,111,510
Net income		43,384
Net income per diluted share	$	0.56


			Natural Gas		Pipeline and		Other
	Utility		Marketing		Storage		Non-Utility
	Segment		Segment		Segment		Segment			Total

					(In thousands)
Balance as of September 30, 2004	$	199,400	$	24,282	$	—	$	10,430		$	234,112
Intersegment transfer of assets⁽¹⁾		—		—		10,430		(10,430	)		—
TXU Gas acquisition (Note 3)		331,557		—		133,406		—			464,963

Balance as of December 31, 2004	$	530,957	$	24,282	$	143,836	$	—		$	699,075



		For the Three Months
		Ended December 31

		2004		2003


		(In thousands)
Net income		$	59,599	$	29,541

Denominator for basic income per share — weighted average common shares			75,306		51,483
Effect of dilutive securities:
	Restricted and other shares		275		132
	Stock options		144		246

Denominator for diluted income per share — weighted average common shares			75,725		51,861

Income per share — basic		$	0.79	$	0.57

Income per share — diluted		$	0.79	$	0.57


9.	Interim Pension and Other Post Retirement Benefit Plan Information



			Pension Benefits						Other Benefits

			2004			2003			2004			2003


			(In thousands)
Components of net periodic pension cost:
	Service cost		$	3,136		$	2,433		$	2,478		$	1,725
	Interest cost			6,017			6,004			2,366			2,103
	Expected return on assets			(6,885	)		(7,524	)		(518	)		(335	)
	Amortization of transition asset			1			24			378			378
	Amortization of prior service cost			(2	)		(2	)		96			96
	Amortization of actuarial loss			1,891			2,018			151			635

		Net periodic pension cost	$	4,158		$	2,953		$	4,951		$	4,602

Actuarial assumptions used to develop net periodic pension cost:
		Discount rate		6.25%			6.00%			6.25%			6.00%
		Rate of compensation increase		4.00%			4.00%			4.00%			4.00%
		Expected return on plan assets		8.75%			9.00%			5.30%			5.30%


2005	$	386,293
2006		117,507
2007		19,999
2008		10,717
2009		8,532
Thereafter		32,442

	$	575,490



	At December 31, 2004

			Natural Gas
	Utility		Marketing
	Segment⁽¹⁾		Segment		Consolidated


	(In thousands)
Investment grade counterparties	$	755	$	11,911	$	12,666
Non-investment grade counterparties		—		157		157

	$	755	$	12,068	$	12,823


Item 1.	*Financial Statements*


	*Significant Accounting Policies*


	*Stock-Based Compensation Plans*


	*Regulatory Assets and Liabilities*



			For the Three Months Ended December 31, 2004

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	913,406	$	432,910	$	21,752	$	556	$	—		$	1,368,624
Intersegment revenues				275		60,891		21,938		803		(83,907	)		—

				913,681		493,801		43,690		1,359		(83,907	)		1,368,624
Purchased gas cost				656,370		466,957		3,872		—		(83,027	)		1,044,172

	Gross profit			257,311		26,844		39,818		1,359		(880	)		324,452
Operating expenses				172,224		3,859		19,471		1,154		(930	)		195,778

Operating income				85,087		22,985		20,347		205		50			128,674
Miscellaneous income (expense)				972		246		315		593		(1,741	)		385
Interest charges				27,259		401		6,171		402		(1,691	)		32,542

Income before income taxes				58,800		22,830		14,491		396		—			96,517
Income tax expense				21,777		9,568		5,407		166		—			36,918

		Net income	$	37,023	$	13,262	$	9,084	$	230	$	—		$	59,599



			At December 31, 2004

					Natural			Pipeline
					Gas			and		Other
			Utility		Marketing			Storage		Nonutility		Eliminations			Consolidated


			(In thousands)
ASSETS
Property, plant and equipment, net			$	2,790,193	$	7,711		$	423,796	$	1,443	$	—		$	3,223,143
Investment in subsidiaries				173,967		(1,662	)		—		—		(172,305	)		—
Current assets
	Cash and cash equivalents			5,594		19,053			—		515		—			25,162
	Assets from risk management activities			755		15,161			—		—		(3,093	)		12,823
	Other current assets			862,819		283,166			58,526		18,913		(53,176	)		1,170,248
	Intercompany receivables			501,326		—			—		30,894		(532,220	)		—

		Total current assets		1,370,494		317,380			58,526		50,322		(588,489	)		1,208,233
Intangible assets				—		3,963			—		—		—			3,963
Goodwill				530,957		24,282			143,836		—		—			699,075
Noncurrent assets from risk management activities				—		—			—		—		—			—
Deferred charges and other assets				241,080		1,610			6,882		22,119		(9	)		271,682

			$	5,106,691	$	353,284		$	633,040	$	73,884	$	(760,803	)	$	5,406,096


CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	1,539,078	$	96,903		$	44,410	$	32,654	$	(173,967	)	$	1,539,078
Long-term debt				2,247,779		—			—		7,394		—			2,255,173

		Total capitalization		3,786,857		96,903			44,410		40,048		(173,967	)		3,794,251
Current liabilities
	Current maturities of long-term debt			3,917		—			—		1,980		—			5,897
	Short-term debt			28,797		—			—		15,000		(15,000	)		28,797
	Liabilities from risk management activities			10,167		11,103			—		—		(5,101	)		16,169
	Other current liabilities			653,134		215,587			78,514		7,539		(34,410	)		920,364
	Intercompany payables			—		33,260			498,960		—		(532,220	)		—

		Total current liabilities		696,015		259,950			577,474		24,519		(586,731	)		971,227
Deferred income taxes				203,680		(11,271	)		6,324		1,977		27			200,737
Noncurrent liabilities from risk management activities				—		984			—		—		(132	)		852
Regulatory cost of removal obligation				241,986		—			—		—		—			241,986
Deferred credits and other liabilities				178,153		6,718			4,832		7,340		—			197,043

			$	5,106,691	$	353,284		$	633,040	$	73,884	$	(760,803	)	$	5,406,096



			At September 30, 2004

					Natural			Pipeline
					Gas			and		Other
			Utility		Marketing			Storage		Nonutility		Eliminations			Consolidated


			(In thousands)
ASSETS
Property, plant and equipment, net			$	1,669,304	$	7,875		$	43,784	$	1,558	$	—		$	1,722,521
Investment in subsidiaries				164,300		(1,484	)		—		—		(162,816	)		—
Current assets
	Cash and cash equivalents			182,846		18,734			—		352		—			201,932
	Assets from risk management activities			25,692		24,412			—		—		(5,664	)		44,440
	Other current assets			253,829		170,363			13,473		18,815		(25,740	)		430,740
	Intercompany receivables			1,995		—			—		16,079		(18,074	)		—

		Total current assets		464,362		213,509			13,473		35,246		(49,478	)		677,112
Intangible assets				—		4,160			—		—		—			4,160
Goodwill				199,400		24,282			10,430		—		—			234,112
Noncurrent assets from risk management activities				—		734			—		—		(172	)		562
Deferred charges and other assets				207,019		1,661			25		22,711		—			231,416

			$	2,704,385	$	250,737		$	67,712	$	59,515	$	(212,466	)	$	2,869,883


CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	1,133,459	$	103,376		$	28,499	$	32,425	$	(164,300	)	$	1,133,459
Long-term debt				853,472		—			—		7,839		—			861,311

		Total capitalization		1,986,931		103,376			28,499		40,264		(164,300	)		1,994,770
Current liabilities
	Current maturities of long-term debt			3,917		—			—		1,991		—			5,908
	Short-term debt			—		—			—		—		—			—
	Liabilities from risk management activities			34,304		11,407			—		—		(6,253	)		39,458
	Other current liabilities			236,257		124,577			24,014		7,558		(23,304	)		369,102
	Intercompany payables			—		9,906			8,168		—		(18,074	)		—

		Total current liabilities		274,478		145,890			32,182		9,549		(47,631	)		414,468
Deferred income taxes				208,325		(3,360	)		6,961		1,977		27			213,930
Noncurrent liabilities from risk management activities				—		1,700			—		—		(562	)		1,138
Regulatory cost of removal obligation				103,579		—			—		—		—			103,579
Deferred credits and other liabilities				131,072		3,131			70		7,725		—			141,998

			$	2,704,385	$	250,737		$	67,712	$	59,515	$	(212,466	)	$	2,869,883


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*


		Mid-Tex			Atmos Pipeline —
		Division			Texas Division


		(In thousands,
		unless otherwise noted)
Operating revenues		$	402,248		$	38,514
Gross profit			113,959			34,867
Operating expenses			75,411			18,477
Operating income			38,548			16,390
Miscellaneous income			410			114
Interest charges			11,440			5,767
Income tax expense			10,085			3,834
Net income		$	17,433		$	6,903

Utility sales volumes — MMcf			40,150			NA
Utility transportation volumes — MMcf			11,799			NA

	Total utility throughput — MMcf		51,949			NA

Pipeline transportation volumes — MMcf			NA			72,753

Heating Degree Days — Percent of Normal			78	%		NA


	*Three Months Ended December 31, 2004 Compared with Three Months Ended December 31, 2003*


Georgia		October – May
Kansas		October – May
Kentucky		November – April
Mississippi		November – May
Tennessee		November – April
Amarillo, Texas		October – May
West Texas		October – May
Lubbock, Texas		October – May
Virginia⁽¹⁾		January – December



	December 31, 2004			September 30, 2004



	(In thousands, except percentages)
Short-term debt	$	28,797	0.7%	$	—	—
Long-term debt		2,261,070	59.1%		867,219	43.3%
Shareholders’ equity		1,539,078	40.2%		1,133,459	56.7%

Total capitalization, including short-term debt	$	3,828,945	100.0%	$	2,000,678	100.0%



	Payments Due by Period

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


	(In thousands)
Contractual Obligations
Long-term debt⁽¹⁾	$	2,265,177	$	5,897	$	312,828	$	412,125	$	1,534,327
Short-term debt⁽¹⁾		28,797		28,797		—		—		—
Interest charges		1,326,995		116,559		239,231		219,020		752,185
Gas purchase commitments⁽²⁾		575,490		386,293		137,506		19,249		32,442



	Fair Value of Contracts at December 31, 2004


	Maturity in Years

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


	(In thousands)
Prices actively quoted	$	(2,372	)	$	(197	)	$	—	$	—	$	(2,569	)
Prices provided by other external sources		(943	)		(88	)		—		—		(1,031	)
Prices based on models and other valuation methods		(31	)		(567	)		—		—		(598	)

Total Fair Value	$	(3,346	)	$	(852	)	$	—	$	—	$	(4,198	)



			Three Months Ended
			December 31

			2004⁽¹⁾			2003

METERS IN SERVICE, end of period
	Residential			2,886,511			1,508,062
	Commercial			277,531			152,488
	Industrial			2,298			3,463
	Agricultural			8,299			9,354
	Public authority and other			10,088			10,020

		Total meters		3,184,727			1,683,387

HEATING DEGREE DAYS⁽²⁾
	Actual (weighted average)			988			1,240
	Percent of normal			88	%		95	%
UTILITY SALES VOLUMES — MMcf⁽³⁾
Gas sales volumes
	Residential			50,769			27,507
	Commercial			27,863			13,356
	Industrial			8,243			6,249
	Agricultural			66			495
	Public authority and other			4,016			3,074

		Total gas sales volumes		90,957			50,681
Utility transportation volumes				29,741			20,680

Total utility throughput				120,698			71,361

UTILITY OPERATING REVENUES (000’s)⁽³⁾
Gas sales revenues
	Residential		$	523,143		$	263,549
	Commercial			264,992			115,564
	Industrial			66,500			44,546
	Agricultural			675			3,034
	Public authority and other			32,430			21,909

		Total utility gas sales revenues		887,740			448,602
Transportation revenues				16,432			8,101
Other gas revenues				9,509			3,785

		Total utility operating revenues	$	913,681		$	460,488

Utility average transportation revenue per Mcf			$	0.55		$	0.39
Utility average cost of gas per Mcf sold			$	7.22		$	6.35


	*Natural Gas Marketing, Pipeline and Storage and Other Nonutility Operations Sales and Statistical Data*


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


Exhibit			Page
Number		Description	Number

	10.1	Eleventh Amendment to Credit Agreement, dated as of December 14, 2004, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC, the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas
	10.2	Form of Non-Qualified Stock Option Agreement under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
	10.3	Form of Restricted Stock Award Agreement under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
	10.4	Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
	10.5	Form of Award Agreement of Restricted Stock with Time-Lapse Vesting under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
	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*