Atmos Energy - 10-Q quarterly report FY

See accompanying notes to condensed consolidated financial statements

See accompanying notes to condensed consolidated financial statements

See accompanying notes to condensed consolidated financial statements

See accompanying notes to condensed consolidated financial statements

      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, in the service areas described below:

      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 acquired a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas. As a result of the TXU Gas acquisition, on October 1, 2004, we created the Atmos Energy Mid-Tex Division, which provides gas distribution services to our approximately 1.5 million residential and business customers in Texas, including the Dallas/Fort Worth metropolitan area. We also created the Atmos Pipeline — Texas Division to manage and operate 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. In addition, on April 1, 2005, we took over the operations of a Waco, Texas customer support center, and all call center services formerly provided by TXU Gas under a transitional services agreement were terminated. We intend to close the purchase of the related assets on October 1, 2005 for approximately $1.7 million.

      Our nonutility businesses include our natural gas marketing operations, our pipeline and storage operations and our other nonutility operations which are provided in 22 states. 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

      Our pipeline and storage operations consist of the operations of our Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. The Atmos Pipeline — Texas Division was purchased from TXU Gas and transports 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 on 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 gas-fired 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 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 and nine-month periods ended June 30, 2005 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 solely to that 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 nine months ended June 30, 2005.

      We have two stock-based compensation plans that provide for the granting of incentive stock options, nonqualified stock options, stock appreciation rights, bonus stock, time-lapse 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.

      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 and nine-months ended June 30, 2005 and 2004 would have been impacted as shown in the following table:

      At June 30, 2005, 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.

      Currently authorized rates do not include a return on our merger and integration costs; however, we recover the amortization of these costs through our rates. 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 and nine-month periods ended June 30, 2005 and 2004:

      Accumulated other comprehensive loss, net of tax, as of June 30, 2005 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(SFAS 123 (R)). This standard revises SFAS 123, Accounting for Stock-Based Compensationand 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. In April 2005, the Securities and Exchange Commission (SEC) deferred the

      We will adopt SFAS 123 (R) as of October 1, 2005 using the modified prospective method. Under this method, we will recognize compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service has not yet been rendered as of October 1, 2005, based upon the grant-date fair value of those awards calculated under SFAS 123 for pro forma disclosure purposes. We expect that the adoption of SFAS 123 (R) will reduce our fiscal 2006 net income by approximately $0.5 million.

      On October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company. 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 $1.9 billion (after closing adjustments and before transaction costs and expenses), which we paid in cash. We acquired approximately $112 million of working capital of TXU Gas after the final working capital and capital expenditures settlement was negotiated during the third quarter of 2005, which resulted in a net payment to TXU Corporation of approximately $4.1 million. We did not assume any indebtedness of TXU Gas in connection with the acquisition. TXU Gas retained certain assets, 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.

      We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of approximately 9.9 million 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 to provide 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 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 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 and nine-month periods ended June 30, 2004 as if the acquisition and related financing had taken place at the beginning of fiscal 2004:

      Goodwill and intangible assets are comprised of the following as of June 30, 2005 and September 30, 2004.

      The following presents our goodwill balance allocated by segment and changes in our balance for the nine months ended June 30, 2005:

      During the second quarter of fiscal 2005, we completed our annual goodwill impairment assessment. Based upon the assessment performed, we determined our goodwill was not impaired.

      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.

      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 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 hedged approximately 59 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $6.23 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 open derivative contracts which are used to hedge price risk associated with these fixed-price forward contracts are now designated as cash flow hedges and 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 and nine-month periods ended June 30, 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 nine months ended June 30, 2005 of $9.3 million in net deferred hedging gains ($5.1 million during the three months ended June 30, 2005) in net income when the derivative contracts matured according to their terms. The net

      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 June 30, 2005, AEH had a net open position (including existing storage) of 0.2 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 three and nine-month periods ended June 30, 2005, we recognized approximately $1.4 million and $3.7 million of this obligation as a component of interest expense.

      Long-term debt at June 30, 2005 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 June 30, 2005, the interest rate on our floating rate debt was 3.516 percent.

      On June 30, 2005, we elected to utilize excess cash to repay $72.5 million in principal on five series of our First Mortgage Bonds prior to their scheduled maturity. In connection with the repayment, we paid a $25.0 million make-whole premium in accordance with the terms of the agreements and accrued interest of approximately $1.0 million. In accordance with regulatory requirements, the premium has been deferred and will be recognized over the remaining original lives of the First Mortgage Bonds that were repaid.

      At June 30, 2005 and September 30, 2004, there were no short-term amounts outstanding under our commercial paper program or bank 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 charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather.

      As of June 30, 2005, we had two short-term committed revolving 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. 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. At June 30, 2005, no commercial paper was outstanding.

      We have a second unsecured facility in place for $18.0 million that bears interest at the Federal Funds rate plus 0.5 percent. This facility expired on March 31, 2005 and was renewed effective April 1, 2005 with no material changes to its terms and pricing. There were no borrowings under this facility at June 30, 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 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. At June 30, 2005, our total-debt-to-total-capitalization ratio, as defined, was 60 percent. 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 had a $250.0 million uncommitted demand working capital credit facility that bore interest at the Eurodollar rate plus 2.5 percent that was scheduled to expire on March 31, 2005. On March 30, 2005, the facility was amended and extended to March 31, 2006. This facility is guaranteed by AEH.

      Borrowings under the amended 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 $50 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $51 million, and must not have a maximum cumulative loss from March 30, 2005 exceeding $4 million to $10 million, depending on the total amount of borrowing elected from time to time by AEM. At June 30, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.14 to 1.

      The Company 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 June 30, 2005, but letters of credit reduced the amount available by $4.2 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 $100.0 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, 2005. At June 30, 2005, there was no amount outstanding under this facility.

      In addition, AEM has a $100.0 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 $250.0 million uncommitted demand credit facility described above. This facility is used to supplement AEM’s $250.0 million credit facility. At June 30, 2005, there was $53.0 million outstanding under this facility. On July 1, 2005, this facility was renewed and the amount available for borrowing was increased to $120.0 million.

      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 $9.0 million. At June 30, 2005 approximately $199.6 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 June 30, 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 $600.0 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 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 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 February 9, 2005, our shareholders approved an amendment to our Articles of Incorporation to increase the number of authorized shares from 100 million to 200 million.

      On October 27, 2004, we completed the public offering of 16.1 million shares of our common stock including the underwriters’ exercise of their overallotment option of 2.1 million 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.

      Basic and diluted earnings per share at June 30 are calculated as follows:

      There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended June 30, 2005 and 2004 as their exercise price was less than the average market price of the common stock during that period.

      There were no out-of-the-money options excluded from the computation of diluted earnings per share for the nine months ended June 30, 2005. There were 3,000 out-of-the-money options excluded from the computation of diluted earnings per share for the nine months ended June 30, 2004 as their exercise price was greater 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 post-retirement benefit plans for the three months ended June 30, 2005 and 2004 are presented in the following table. All of these costs are

      The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the nine months ended June 30, 2005 and 2004 are as follows:

      The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 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. In the period leading up to our June 30, 2005 measurement date, these interest rates were declining, which has the effect of increasing the present value of our plan liabilities. Accordingly, we voluntarily contributed in June 2005 $3.0 million to our Pension Account Plan to maintain the level of funding we desire relative to our accumulated benefit obligation. We were not required to make a minimum funding contribution during fiscal 2005 nor do we anticipate making any additional voluntary contributions during the remainder of fiscal 2005.

      We are involved in litigation and environmental matters and claims that arise in the ordinary course of our business. While the ultimate results of such litigation and response actions to such environmental matters and 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.

      As discussed in our Form 10-Q for the three months ended December 31, 2004, we were the plaintiff in a case styledEnergas 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 nine months ended June 30, 2005, 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 June 30, 2005, AEM was committed to purchase 46.4 Bcf within one year, 5.7 Bcf within one to three years and 1.1 Bcf after three years under indexed contracts. AEM is committed to purchase 0.7 Bcf within one year and 0.5 Bcf within one to three years under fixed price contracts with prices ranging from $5.24 to $7.68. Purchases under these contracts totaled $294.0 million and $283.5 million for the three months ended June 30, 2005 and 2004 and $999.4 million and $981.5 million for the nine months ended June 30, 2005 and 2004.

      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.

      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 currently expected to be placed into service in fiscal 2006.

      In May 2005, we entered into a five year agreement with a third party to transport up to 100,000 MMBtu per day of natural gas through our Texas intrastate pipeline system beginning in April 2006. To handle the increased volumes for this project and other planned projects, we will install compression equipment and other pipeline infrastructure, costing approximately $20 million.

      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.

      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. 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 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 the credit department, but are primarily

      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 June 30, 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 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 22 states. Additionally, 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, 2004. We evaluate performance based on net income or loss of the respective operating units.

      Summarized income statements for the three and nine-month periods ended June 30, 2005 and 2004 by segment are presented in the following tables: