NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2005

      Atmos Energy Corporation (“Atmos” or “the Company”) and its subsidiaries are engaged primarily in the natural gas utility business as well as other natural gas nonutility businesses. Our natural gas utility business distributes natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated natural gas utility divisions, in the service areas described below:

      Our nonutility businesses operate in 22 states and include our natural gas marketing operations, our pipeline and storage operations and our other nonutility operations. These operations are either organized under or managed by Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by the Company.

      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 Kentucky, Louisiana and Mid-States utility 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 business includes the regulated operations of our Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and the nonregulated operations of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. The Atmos Pipeline — Texas Division transports natural gas to our 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 each wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices in exchange for revenues that are equal to the costs incurred to provide these services. Through Atmos Power Systems, Inc., we construct gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

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      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 in its Annual Report on Form  10-K for the fiscal year ended September 30, 2005. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2005 are not indicative of expected results of operations for the full 2006 fiscal year, which ends September 30, 2006.

      Certain prior-period amounts have been reclassified to conform with the current year’s presentation.

      Our accounting policies are described in Note 2 to our Annual Report on Form  10-K for the year ended September 30, 2005. Except for the Company’s adoption of Statement of Financial Accounting Standards (SFAS) 123 (revised), Share-Based Payment, discussed below, there were no significant changes to our accounting policies during the three months ended December 31, 2005.

      Our 1998 Long-Term Incentive Plan provides for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units to officers and key employees. Nonemployee directors are also eligible to receive stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock.

      On October 1, 2005, the Company adopted SFAS 123 (revised), Share-Based Payment (SFAS 123(R)). This standard revises SFAS 123, Accounting for Stock-Based Compensation and supersedes Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), the Company is 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.

      We adopted SFAS 123(R) using the modified prospective method. Under this transition method, stock-based compensation expense for the three months ended December 31, 2005 includes: (i) compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of October 1, 2005, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123; and (ii) compensation expense for all stock-based compensation awards granted subsequent to October 1, 2005, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). We recognize compensation expense on a straight-line basis over the requisite service period of the award. Total stock-based compensation expense included in our statement of income for the three months ended December 31, 2005 was less than $0.1 million and was recorded as a component of operation and maintenance expense. In accordance with the modified prospective method, financial results for prior periods have not been restated.

      Prior to October 1, 2005, we accounted for these plans under the intrinsic-value method described in APB Opinion 25, as permitted by SFAS 123. Under this method, no compensation cost for stock options was recognized for stock-option awards granted at or above fair-market value. Awards of restricted stock were

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

      Had compensation expense for our stock-based awards been recognized as prescribed by SFAS 123, our net income and earnings per share for the three months ended December 31, 2004 would have been impacted as shown in the following table:

      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, 2005 and September 30, 2005 included the following:

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      Currently authorized rates do not include a return on certain of 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. 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, 2005 and 2004:

      Accumulated other comprehensive loss, net of tax, as of December 31, 2005 and September 30, 2005 consisted of the following unrealized gains (losses):

      In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

incurred — generally upon acquisition, construction or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for us by the end of the 2006 fiscal year. We are currently evaluating the impact that FIN 47 may have on our financial position, results of operations and cash flows.

      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. Effective October 1, 2005, the Company changed its mark to market measurement from Inside FERC to Gas Daily to better reflect the prices of our physical commodity.

      The following table shows the fair values of our risk management assets and liabilities by segment at December 31, 2005 and September 30, 2005:

      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 ultimately will 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

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Regulation. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. For the 2005-2006 heating season, we hedged approximately 46 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $9.11 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. AEM also utilizes basis swaps and other non-hedge derivative instruments to manage its exposure to market volatility.

      For the three-month period ended December 31, 2005, the change in the deferred hedging position in accumulated other comprehensive loss was attributable to decreases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition for the three months ended December 31, 2005 of $15.3 million in net deferred hedging gains in net income when the derivative contracts matured according to their terms. The net deferred hedging 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 balance as of December 31, 2005 is expected to be recognized in net income in fiscal 2006 along with the corresponding hedged purchases and sales of natural gas.

      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, 2005, AEH had a net open position (including existing storage) of 0.1 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 in October 2004. 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 payment was recorded in accumulated other comprehensive loss and is being recognized as a component of interest expense over a period of five to ten years. During the three-month period ended December 31, 2005, we recognized approximately $1.4 million of this amount as a component of interest expense.

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      Long-term debt at December 31, 2005 and September 30, 2005 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, 2005, the interest rate on our floating rate debt was 4.525 percent.

      At December 31, 2005 and September 30, 2005, there was $474.1 million and $144.8 million outstanding under our commercial paper program and bank credit facilities.

Credit facilities

      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 and the increased gas supplies required to meet customers’ needs during periods of cold weather.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      As of December 31, 2005, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a three-year unsecured facility, expiring October 2008, for $600 million that bears interest at a base rate or at the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings, and serves as a backup liquidity facility for our $600 million commercial paper program. At December 31, 2005, there was $381.7 million outstanding under our commercial paper program.

      We have a second unsecured facility in place which is a 364-day facility expiring November 2006, for $300 million that bears interest at a base rate or the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings. At December 31, 2005, there were no borrowings under this facility.

      We have a third unsecured facility in place for $18 million that bears interest at the Federal Funds rate plus 0.5 percent. This facility expires on March 31, 2006. There was $17.4 million outstanding under this facility at December 31, 2005.

      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 both our $600 million three-year credit facility and $300 million 364-day 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. At December 31, 2005, our total -debt-to -total-capitalization ratio, as defined, was 61 percent. In addition, the fees that we pay on unused amounts under both the $600 million and $300 million credit facilities are subject to adjustment depending upon our credit ratings.

      On November 28, 2005, AEM amended its $250 million uncommitted demand working capital credit facility to increase the amount of credit available from $250 million to a maximum of $580 million. The credit facility will expire on March 31, 2006.

      Borrowings under the credit facility can be made either as revolving loans or offshore rate loans. Revolving loan borrowings will bear interest at a floating rate equal to a base rate (defined as the higher of 0.50% per annum above the Federal Funds rate or the lender’s prime rate) plus 0.50%. Offshore rate loan borrowings will bear interest at a floating rate equal to a base rate based upon LIBOR plus an applicable margin, ranging from 1.375% to 1.75% per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. Borrowings drawn down under letters of credit issued by the banks will bear interest at a floating rate equal to the base rate, as defined above, plus an applicable margin, which will range from 1.125% to 2.00% per annum, depending on the excess tangible net worth of AEM and whether the letters of credit are swap-related standby letters of credit.

      AEM is required by the financial covenants in the credit facility to maintain a maximum ratio of total liabilities to tangible net worth of 5 to 1, along with minimum levels of net working capital ranging from $20 million to $120 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $121 million, and must not have a maximum cumulative loss from March 30, 2005 exceeding $4 million to $23 million, depending on the total amount of borrowing elected from time to time by AEM. At December 31, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined, was 2.68 to 1.

      At December 31, 2005, $75 million was outstanding under this credit facility. In addition, at December 31, 2005, AEM letters of credit totaling $276.9 million had been issued under the facility, which reduced the amount available by a corresponding amount. 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

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amount available to AEM under this credit facility was $48.1 million at December 31, 2005. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

      The Company also has an unsecured short-term uncommitted credit line for $25 million that is used for working-capital and letter-of -credit purposes. There were no borrowings under this uncommitted credit facility at December 31, 2005, but letters of credit reduced the amount available by $4.4 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.

      AEH, the parent company of AEM, has a $100 million intercompany uncommitted demand credit facility with the Company which bears interest at LIBOR plus 2.75%. This facility has been approved by our state regulators through December 31, 2006. At December 31, 2005, $96.4 million was outstanding under this facility.

      In addition, AEM has a $120 million intercompany uncommitted demand credit facility with AEH for its nonutility business which bears interest at the LIBOR rate plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility described above. This facility is used to supplement AEM’s $580 million credit facility. At December 31, 2005, there was $94 million outstanding under this facility.

      We have other covenants in addition to those described above. Our Series P First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, after November 2007, 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, 1985 may not exceed the sum of accumulated net income for periods after December 31, 1985 plus $9 million. At December 31, 2005 approximately $203.5 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, 2005. 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 million and $300 million revolving credit agreements, 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 other indebtedness, as defined, by at least $250 thousand in the aggregate. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos were 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 August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by our shareholders. The Long-Term Incentive Plan is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock,

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performance-based restricted stock units and stock units to certain employees and non-employee directors of Atmos and its subsidiaries. The objectives of this plan 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. We are authorized to grant awards for up to a maximum of four million shares of common stock under this plan subject to certain adjustment provisions. As of December 31, 2005, non-qualified stock options, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units have been issued under this plan and 1,090,754 shares were available for issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years.

      We used the Black-Scholes pricing model to estimate the fair value of each option granted with the following weighted average assumptions:

      A summary of option activity as of December 31, 2005, and changes during the three months then ended, is presented below:

      The stock options had a weighted-average fair value per share on the date of grant of $3.74 and $3.69 for the three months ended December 31, 2005 and 2004. Net cash proceeds from the exercise of stock options during the three months ended December 31, 2005 and 2004 were less than $0.1 million and $1.1 million. The associated income tax benefit from stock options exercised during the three months ended December 31, 2005 and 2004 was less than $0.1 million for both periods. The total intrinsic value of options exercised during the three months ended December 31, 2005 and 2004 was $4,696 and $176,354.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      As of December 31, 2005, there was $0.4 million of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a weighted-average period of 0.41 years.

      As noted above, the 1998 Long-Term Incentive Plan provides for discretionary awards of time-lapse restricted stock and performance-based restricted stock units to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The associated expense is recognized ratably over the vesting period.

      A summary of the status of the Company’s nonvested restricted shares as of December 31, 2005, and changes during the three months then ended, is presented below:

      As of December 31, 2005, there was $10.2 million of total unrecognized compensation cost related to nonvested restricted shares granted under the 1998 Long-Term Incentive Plan. That cost is expected to be recognized over a weighted-average period of 1.86 years. The total fair value of restricted stock vested during the three months ended December 31, 2005 and 2004 was $0.4 million and $0.5 million.

      Basic and diluted earnings per share for the three months ended December 31, 2005 and 2004 are calculated as follows:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      There were no out-of -the-money options excluded from the computation of diluted earnings per share for the three months ended December 31, 2005 and 2004 as their exercise price was less than the average market price of the common stock during that period.

      The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2005 and 2004 are presented in the following table. 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 assumptions used to develop our net periodic pension cost for the three months ended December 31, 2005 and 2004 are as follows:

      The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. During the three months ended December 31, 2005, we did not make a voluntary contribution to our pension plans. However, we contributed $2.5 million to our other postretirement plans and we expect to contribute approximately $11.9 million to these plans during fiscal 2006.

      With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to our annual report on Form  10-K for the year ended September 30, 2005, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2005. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or net cash flows.

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      In addition, we are involved in other litigation and environmental-related matters or claims that arise in the ordinary course of our business. While the ultimate results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we believe the final outcome of such litigation and response actions 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, 2005, AEM was committed to purchase 45.3 Bcf within one year, 23.5 Bcf within one to three years and 17.6 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year and 0.3 Bcf within one to three years under fixed price contracts with prices ranging from $6.00 to $15.08. Purchases under these contracts totaled $787.7 million and $360.1 million for the three months ended December 31, 2005 and 2004.

      Our utility operations, other than the Mid-Tex Division, 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 its service area which obligate it to purchase specified volumes at market prices. The estimated commitments under these contracts as of December 31, 2005 are as follows (in thousands):

      In February 2005, the Attorney General of the State of Kentucky filed a complaint at the Kentucky Public Service Commission (KPSC) alleging that our present rates are producing revenues in excess of reasonable levels. We answered the complaint and filed a Motion to Dismiss with the KPSC. On February 2, 2006, the KPSC issued an Order denying our Motion to Dismiss and establishing an informal conference to be held on February 14, 2006 for the purpose of developing a procedural schedule and simplification of issues. We do not believe that the Attorney General will be able to demonstrate that our present rates are in excess of reasonable levels.

      In August 2005, we received a “show cause” order from the City of Dallas, which requires us to provide information that demonstrates good cause for showing that our existing distribution rates charged to customers in the City of Dallas should not be reduced. We filed our response to this order in November 2005 and we are responding to requests for information by the City of Dallas. In addition, during the first quarter of fiscal 2006, approximately 80 other cities in the Mid-Tex Division passed resolutions requesting that we “show cause” why existing distribution rates are just and reasonable and required a filing by us on a system-wide basis. We made the required filing on December 30, 2005. We are responding to requests for information by the cities’

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consultant. We believe that we will be able to demonstrate in all these “show cause” proceedings that our rates are just and reasonable.

      In November 2005, we received a notice from the Tennessee Regulatory Authority that it was opening an investigation into allegations that we are overcharging customers in parts of Tennessee by approximately $10 million per year. We believe that we are not overcharging our customers and we intend to participate fully in the investigation.

      In January 2006, the Lubbock, Texas City Council passed a resolution requiring Atmos to submit copies of all documentation necessary for the city to review the rates of Atmos’ West Texas Division to ensure they are just and reasonable. We will provide information to the city on or before February 28, 2006. We believe that we will be able to demonstrate to the City of Lubbock that our rates are just and reasonable.

     Other

      On November 30, 2005, we entered into an agreement 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 (North Side Loop). Under terms of the agreement, we are responsible for contributing no more than $42.5 million to the construction costs of the pipeline. We are also responsible for 50% of the costs of the compression facilities. Approximately 21 miles of the pipeline was placed in service by December 31, 2005 with the remainder of the pipeline expected to be placed in service by March 31, 2006. As of December 31, 2005, we have spent $19.2 million for the North Side Loop project and expect to spend approximately $29.7 million in the remainder of fiscal 2006 for this project.

      During the third quarter of fiscal 2005, we entered into two agreements with third parties to transport natural gas through our Texas intrastate pipeline system beginning in fiscal 2006. To handle the increased volumes for these projects, we will install compression equipment and other pipeline infrastructure. We expect to spend approximately $32 million in fiscal 2006 for these projects.

      On August 29, 2005, Hurricane Katrina struck the Gulf Coast, inflicting significant damage to our eastern Louisiana operations. The hardest hit areas in our service territory were in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes. In total, approximately 230,000 of our natural gas customers were affected in these areas. A significant number of these customers will not require gas service for some time because of sustained damages. We cannot predict with certainty how many of these customers will return to these service areas and over what time period. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. As of December 31, 2005, we believe adequate provision has been made for any losses that may not be fully recovered through insurance or for which we do not receive rate relief.

      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 our customer base.

      Customer diversification also helps mitigate AEM’s 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.

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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 nonperformance by any single counterparty.

      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 AEM’s credit department, but are primarily based on external ratings provided by Moody’s Investor Service Inc. and/or Standard & Poor’s. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrial and commercial customers is non-investment grade. The table below shows the percentages related to the investment ratings as of December 31, 2005 and September 30, 2005.

      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, 2005. Investment grade counterparties have minimum credit ratings of BBB-, assigned by Standard & Poor’s; 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.

      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 throughout 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 22 states. Additionally,

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we provide natural gas transportation and storage services to certain of our utility operations and to third parties.

      Our operations are divided into four segments:

      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, 2005. We evaluate performance based on net income or loss of the respective operating units.

      Summarized income statements for the three-month period ended December 31, 2005 and 2004 by segment are presented in the following tables:

ATMOS ENERGY CORPORATION

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ATMOS ENERGY CORPORATION

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      Balance sheet information at December 31, 2005 and September 30, 2005 by segment is presented in the following tables:

ATMOS ENERGY CORPORATION

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