Atmos Energy - 10-Q quarterly report FY

 

 

 

 

 

 

 

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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large Accelerated Filer þ  Accelerated Filer o  Non-Accelerated Filer o  Smaller Reporting Company o

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2of the Exchange Act)  Yes o     No þ

 

Number of shares outstanding of each of the issuer’s classes of common stock, as of January 30, 2007.

 

 

 

 

 

 

 

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 our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, in the service areas described below:

 

 

 

 

In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulationand/orregulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

 

Our regulated transmission and storage business consists of the regulated operations of our Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands.

 

Our nonregulated businesses operate in 22 states and include our natural gas marketing operations and pipeline, storage and other operations. These businesses are operated through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by the Company and based in Houston, Texas.

 

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/Mid-States and Louisiana 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, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are each wholly-owned by AEH. APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Through December 31, 2006, AES provided natural gas management services to our natural gas distribution operations, other than the Mid-Tex Division. These services included aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices. Effective January 1, 2007, our shared services function began providing these services to our natural gas distribution operations. AES continues to provide limited services to our natural gas distribution divisions, and the revenues AES receives are equal to the costs incurred to provide those services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.

 

 

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 are condensed as permitted by the instructions toForm 10-Qand should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in its Annual Report onForm 10-Kfor the fiscal year ended September 30, 2007. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2007 are not indicative of expected results of operations for the full 2008 fiscal year, which ends September 30, 2008.

 

 

Our accounting policies are described in Note 2 to our Annual Report onForm 10-Kfor the year ended September 30, 2007. Except for the Company’s adoption of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48), discussed below, there were no significant changes to those accounting policies during the three months ended December 31, 2007.

 

In June 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

 

We adopted the provisions of FIN 48 on October 1, 2007. As a result of adopting FIN 48, we determined that we had $6.1 million of liabilities associated with uncertain tax positions. Of this amount, $0.5 million was recognized as a result of adopting FIN 48 with an offsetting reduction to retained earnings. As of December 31, 2007, we had recorded liabilities associated with uncertain tax positions totaling $6.1 million. The realization of all of these tax benefits would reduce our income tax expense by approximately $6.1 million.

 

Prior to October 1, 2007, the $5.6 million liability previously recorded for uncertain tax positions was reflected on the consolidated balance sheet as a component of deferred income taxes. As a result of adopting FIN 48, we recorded a $3.7 million liability as a component of other current liabilities and $2.4 million as a

 

component of deferred credits and other liabilities, with offsetting decreases to the deferred income tax liability.

 

We recognize accrued interest related to unrecognized tax benefits as a component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements. For the three months ended December 31, 2007 we recognized $0.2 million in penalties and interest.

 

We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2001. The Internal Revenue Service is currently conducting a routine examination of our fiscal 2002, 2003 and 2004 tax returns, and we anticipate these examinations will be completed by the end of fiscal 2008. We believe all material tax items which relate to the years under audit have been properly accrued.

 

 

We record certain costs as regulatory assets in accordance with Statement of Financial Accounting Standards (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 other assets 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, 2007 and September 30, 2007 included the following:

 

 

Currently, our 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 be included in future rate filings in accordance with rulings received from various state regulatory commissions.

 

 

The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2007 and 2006:

 

 

Accumulated other comprehensive loss, net of tax, as of December 31, 2007 and September 30, 2007 consisted of the following unrealized gains (losses):

 

 

 

In December 2007, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 141 (revised 2007),Business Combinations. SFAS 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS 141(R) significantly changes the accounting for business combinations in a number of areas, including the treatment of contingent consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, under SFAS 141(R), changes in an acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. The provisions of this standard will apply to acquisitions we complete after October 1, 2009.

 

In December 2007, the FASB issued FASB Statement No. 160,Noncontrolling Interests in Consolidated Financial Statement, an amendment of ARB No. 51. SFAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This new consolidation method significantly changes the accounting for transactions with minority interest holders. The provisions of the standard will be effective for us beginning October 1, 2009. This

 

standard is not expected to have a material impact on our financial position, results of operations or cash flows.

 

 

We conduct risk management activities through both our natural gas distribution 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. These risk management assets and liabilities are subject to continuing market risk until the underlying derivative contracts are settled.

 

The following table shows the fair values of our risk management assets and liabilities by segment at December 31, 2007 and September 30, 2007:

 

 

 

We use a combination of physical 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 natural gas distribution segment ultimately are 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 on our natural gas distribution segment as a result of the use of financial derivatives.

 

 

AEH manages its exposure to the risk of natural gas price changes through a combination of physical 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. AEH 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, 2007, the change in the deferred hedging position in accumulated other comprehensive loss was attributable to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition for the three months ended December 31, 2007 of $5.5 million in net deferred hedging losses in net income when the derivative contracts matured according to their terms. The net deferred hedging gain 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. Most of the deferred hedging balance as of December 31, 2007 is expected to be recognized in net income in fiscal 2008 along with the corresponding hedged purchases and sales of natural gas.

 

Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative hedging instrument and the hedged item and could materially affect our results as ineffectiveness is recognized in the income statement. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments is referred to as basis ineffectiveness. Fair value hedge ineffectiveness arising from the timing of the settlement of physical contracts and the settlement of the related fair value hedge is referred to as timing ineffectiveness. Gains and losses arising from basis and timing ineffectiveness for the three months ended December 31, 2007 and 2006 are as follows:

 

 

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 net 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 may 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, 2007, AEH had a net open position (including existing storage) of 0.1 Bcf.

 

 

 

 

Long-term debt at December 31, 2007 and September 30, 2007 consisted of the following:

 

 

 

At December 31, 2007 and September 30, 2007, there was $202.2 million and $150.6 million outstanding under our commercial paper program and bank credit facilities.

 

 

On December 4, 2006, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in new common stockand/or debt securities available for issuance. As of December 31, 2007, we had approximately $450 million of availability remaining under the registration statement. Due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we are permitted to issue a total of approximately $100 million of equity securities, $50 million of senior debt securities and $300 million of subordinated debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard & Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until an investment grade rating from all of the three credit rating agencies was achieved.

 

 

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on awhen-and-as-neededbasis at the discretion of the banks. 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.

 

 

As of December 31, 2007, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a five-year unsecured facility, expiring December 2011, for $600 million that bears interest at a base rate or at the LIBOR rate for the applicable interest period, plus from 0.30 percent to 0.75 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, 2007, there was $202.2 million outstanding under our commercial paper program.

 

We have a second unsecured facility in place which is a364-dayfacility for $300 million that bears interest at a base rate or the LIBOR rate for the applicable interest period, plus from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. This facility was replaced by another364-dayfacility in November 2007 with no material changes to its terms and pricing. At December 31, 2007, 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 in March 2008. At December 31, 2007, there were no borrowings under this facility.

 

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. 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 revolving credit facilities 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, 2007, our total-debt-to-total-capitalization ratio, as defined, was 56 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under our revolving credit facilities are subject to adjustment depending upon our credit ratings. The revolving credit facilities each contain the same limitation with respect to our total-debt-to-total-capitalization ratio.

 

 

AEM has a $580 million uncommitted demand working capital credit facility that expires March 31, 2008. 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 (i) 0.50 percent per annum above the Federal Funds rate or (ii) the lender’s prime rate plus 0.25 percent. Offshore rate loan borrowings will bear interest at a floating rate equal to a base rate based upon LIBOR for the applicable interest period plus an applicable margin, ranging from 1.25 percent to 1.625 percent 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 1.00 percent to 1.875 percent 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 not to exceed 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 for the most recent 12 month accounting period exceeding $4 million to $23 million, depending on the total amount of borrowing elected from time to time by AEM. At December 31, 2007, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.91 to 1.

 

At December 31, 2007, there were no borrowings outstanding under this credit facility. However, at December 31, 2007, AEM letters of credit totaling $129.9 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 amount available to AEM under this credit facility was $70.1 million at December 31, 2007. 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 of $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, 2007, but letters of credit reduced the amount available by $5.4 million. In January 2008, the unused portion of this facility was terminated by the bank and the remaining balance will be terminated as the outstanding letters of credit expire.

 

The Company has a $200 million intercompany uncommitted revolving credit facility with AEH. This facility bears interest at the lesser of (i) LIBOR plus 0.20 percent or (ii) the marginal borrowing rate available to the Company on any such date under its commercial paper program. Applicable state regulatory commissions have approved this facility through December 31, 2008. At December 31, 2007, there was $57.5 million outstanding under this facility.

 

AEH has a $200 million intercompany uncommitted demand credit facility with the Company which bears interest at the rate of AEM’s $580 million uncommitted demand working capital credit facility plus 0.25 percent. Applicable state regulatory commissions have approved this facility through December 31, 2008. At December 31, 2007, there were no borrowings under this facility.

 

In addition, to supplement its $580 million credit facility, AEM has a $175 million intercompany uncommitted demand credit facility with AEH, which bears interest at LIBOR plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility. At December 31, 2007, there were no borrowings 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, 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, 2007 approximately $304.8 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, 2007. If we were unable to comply with our debt covenants, we could be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our public debt indentures relating to our senior notes and debentures, as well as our 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 December 13, 2006, we completed the public offering of 6,325,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 825,000 shares. The offering was priced at $31.50 and generated net proceeds of approximately $192 million. We used the net proceeds from this offering to reduce short-term debt.

 

 

Basic and diluted earnings per share for the three months ended December 31, 2007 and 2006 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 December 31, 2007 and 2006 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, 2007 and 2006 are presented in the following table. All of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution 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, 2007 and 2006 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. Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. However, additional voluntary contributions are made to satisfy regulatory requirements in certain of our jurisdictions. During the three months ended December 31, 2007, we contributed $2.1 million to our other postretirement plans, and we expect to contribute a total of approximately $12 million to these plans during fiscal 2008.

 

 

 

On December 13, 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines. The data requests include requests for information and documents concerning specified short-term capacity release transportation transactions. We have submitted our responses to the data requests on a timely basis and we intend to fully cooperate with the Commission during its investigation. The Company is currently unable to predict the final outcome of this investigation or the potential impact it could have on the Company’s results of operations, financial condition or cash flows.

 

The Texas Railroad Commission recently issued a directive and is currently developing a rulemaking concerning the replacement of compression couplings at pre-bent gas meter risers which could affect all natural gas utility companies operating in Texas. Compliance with the directive along with adoption of the pending rulemaking will require us to re-direct significant capital spending. These amounts should be recoverable through our rates.

 

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to our Annual Report onForm 10-Kfor the year ended September 30, 2007, except as noted above, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2007. 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 cash flows.

 

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 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, 2007, AEM was committed to purchase 82.1 Bcf within one year, 32.1 Bcf within one to three years and 0.2 Bcf after three years under indexed contracts. AEM is committed to purchase 2.0 Bcf within one year under fixed price contracts with prices ranging from $6.27 to $9.85. Purchases under these contracts totaled $572.0 million and $420.4 million for the three months ended December 31, 2007 and 2006.

 

Our natural gas distribution 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 fiscal year commitments under these contracts as of December 31, 2007 are as follows (in thousands):

 

 

 

At December 31, 2007, we had rate cases in progress in our Kansas and Mid-Tex service areas. In January 2008, we reached a tentative settlement agreement with the Atmos Cities Steering Committee, which represents over half of our Mid-Tex customers. We remain in negotiations with cities which represent the

 

majority of the remaining Mid-Tex customers. In our Kansas rate case, we are currently providing information to and addressing questions raised by the regulatory commission. We believe we will be able to demonstrate to these regulators that our rates are just and reasonable. These regulatory proceedings are discussed in further detail in Management’s Discussion and Analysis — Recent Ratemaking Developments.

 

 

Information regarding our concentration of credit risk is disclosed in Note 15 to our Annual Report onForm 10-Kfor the year ended September 30, 2007. During the three months ended December 31, 2007, there were no material changes in our concentration of credit risk.

 

 

Atmos Energy Corporation and our subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage businesses as well as certain other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

 

Through our nonregulated businesses we provide natural gas management and marketing services to municipalities, other local distribution companies and industrial customers located in 22 states. Additionally, we provide natural gas transportation and storage services to certain of our natural gas distribution 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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution 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 onForm 10-Kfor the fiscal year ended September 30, 2007. We evaluate performance based on net income or loss of the respective operating units.

 

Income statements for the three-month periods ended December 31, 2007 and 2006 by segment are presented in the following tables:

 

 

 

Balance sheet information at December 31, 2007 and September 30, 2007 by segment is presented in the following tables: