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” inRule 12b-2of 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 July 31, 2008.

 

 

 

 

 

 

 

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 Energy” 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 deliver 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 primarily in the Midwest and Southeast 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., each of which are 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. Additionally, APS manages our natural gas gathering operations, which were limited in nature as of June 30, 2008. AES provides 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 andnine-monthperiods ended June 30, 2008 are not indicative of our results of operations for the full 2008 fiscal year, which ends September 30, 2008.

 

 

Our accounting policies are described in Note 2 to the financial statements in 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 nine months ended June 30, 2008.

 

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.

 

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.

 

As of June 30, 2008, we had recorded liabilities associated with uncertain tax positions totaling $8.0 million. The realization of all of these tax benefits would reduce our income tax expense by approximately $8.0 million.

 

The following table presents the changes in unrecognized tax benefits for the nine months ended June 30, 2008 (in thousands):

 

 

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. We did not recognize any material penalty and interest expenses during the nine months ended June 30, 2008.

 

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.

 

Additionally, during the second quarter of fiscal 2008, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

 

 

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 reported separately.

 

 

Significant regulatory assets and liabilities as of June 30, 2008 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 (loss), net of related tax, for the three-month and nine-month periods ended June 30, 2008 and 2007:

 

 

Accumulated other comprehensive income (loss), net of tax, as of June 30, 2008 and September 30, 2007 consisted of the following unrealized gains (losses):

 

 

 

In March 2008, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 161 expands the disclosure requirements for derivative instruments and for hedging activities. This statement requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. The provisions of this standard will be effective for us beginning January 1, 2009. Since SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is not expected to have a material impact on our financial position, results of operations or cash flows.

 

In December 2007, the 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 any acquisitions we may 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 June 30, 2008 and September 30, 2007:

 

 

 

 

In our natural gas distribution segment, we use a combination of physical storage and financial derivatives to partially insulate our natural gas distribution customers against gas price volatility during the winter heating season. These financial derivatives have not been designated as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Accordingly, they are recorded at fair value. However, because the costs associated with and the gains and losses arising from these financial derivatives are included in our purchased gas adjustment mechanisms, changes in the fair value of these financial derivatives are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas costs when the related costs are recovered through our rates in accordance with SFAS 71. Accordingly, there is no earnings impact to our natural gas distribution segment as a result of the use of financial derivatives.

 

 

Our natural gas marketing risk management activities are conducted through AEM. AEM is exposed to risks associated with changes in the market price of natural gas, and we manage our 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. AEM uses financial derivatives designated as fair value hedges to offset changes in the fair value of its natural gas inventory and derivatives designated as 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.

 

 

Our pipeline, storage and other activities are also exposed to risks associated with changes in the market price of natural gas, which are managed through a combination of physical storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Atmos Pipeline and Storage, LLC uses financial derivatives designated as fair value hedges to offset changes in the fair value of its natural gas inventory.

 

Under our risk management policies for our nonregulated operations, 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 June 30, 2008, AEH had a net open position (including existing storage) of 0.1 Bcf.

 

 

We periodically manage our exposure to interest rate changes by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. Since fiscal 2004, we have executed five Treasury lock agreements.

 

The most recent treasury lock agreement was executed in March 2007, which fixed the Treasury yield component of the interest cost associated with $100 million of our $250 million 6.35% Senior Notes that were

 

issued in June 2007. This Treasury lock agreement was settled in June 2007, and resulted in the receipt of $4.8 million from the counterparties.

 

The settlement of the five Treasury lock agreements resulted in a net $39.0 million payment to the counterparties. We designated these Treasury lock agreements as a cash flow hedge of an anticipated transaction at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income. The net realized loss recognized upon settlement of the Treasury lock agreements was initially recorded as a component of accumulated other comprehensive income and is currently being recognized as a component of interest expense over the life of the related financing arrangements.

 

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2008 and 2007:

 

 

 

 

 

Unrealized margins recorded in our natural gas marketing and pipeline, storage and other segments are comprised of various components, including, but not limited to, unrealized gains and losses arising from hedge ineffectiveness. Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative instrument and the hedged item and could materially affect our results of operations for the reported period. Although these unrealized gains and losses are currently recorded in our income statement, they are not indicative of the economic gross profit we anticipate realizing when the underlying physical and financial transactions are settled.

 

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. Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity are referred to

 

 

as timing ineffectiveness. The portion of our unrealized margins related to basis and timing ineffectiveness gains and losses for the three and nine months ended June 30, 2008 and 2007 are as follows:

 

 

 

 

Long-term debt at June 30, 2008 and September 30, 2007 consisted of the following:

 

 

 

 

At June 30, 2008, there was $113.3 million outstanding under our commercial paper program and bank credit facilities. At September 30, 2007, there was $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 June 30, 2008, 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 we received an investment grade rating from all of the three credit rating agencies.

 

 

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 June 30, 2008, 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 June 30, 2008, there was $113.3 million outstanding under our commercial paper program.

 

The second facility is a $300 million unsecured364-dayfacility expiring November 2008, 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. At June 30, 2008, there were no borrowings under this facility.

 

The third facility is an $18 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. This facility expired on March 31, 2008 and was renewed effective April 1, 2008 for one year with no material changes to the terms and pricing. At June 30, 2008, 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 June 30, 2008, our

 

 

total-debt-to-total-capitalizationratio, as defined, was 55 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. On March 31, 2008, AEM and the participating banks amended the facility, primarily to extend it to March 31, 2009. In addition, the amendment removed the financial covenant relating to the amount of cumulative losses that could be incurred by AEM and its subsidiaries over a specific period of time and included provisions permitting the participating banks, or their affiliates, to participate in physical commodity transactions with AEM.

 

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. At June 30, 2008, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.97 to 1. Additionally, AEM must maintain minimum levels of net working capital ranging from $20 million to $120 million and a minimum tangible net worth ranging from $21 million to $121 million. As defined in the financial covenants, at June 30, 2008, AEM’s net working capital was $253.3 million and its tangible net worth was $256.5 million.

 

At June 30, 2008, there were no borrowings outstanding under this credit facility. However, at June 30, 2008, AEM letters of credit totaling $161.9 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 $88.1 million at June 30, 2008. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

 

The Company also had an unsecured short-term uncommitted credit line of $25 million that is used for working-capital and letter-of-credit purposes. In January 2008, the unused portion of this facility was terminated by the lending bank and the remaining balance will be terminated as the outstanding letters of credit expire. At June 30, 2008, there was $5.3 million in letters of credit outstanding under this facility.

 

The Company has a $200 million intercompany uncommitted revolving credit facility with AEH. This facility bears interest at the lesser of (i) the one-month LIBOR rate 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 June 30, 2008, there were no borrowings 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 0.75 percent. Applicable state regulatory commissions have approved this facility through December 31, 2008. At June 30, 2008, there was $17.3 million outstanding under this facility.

 

 

In addition, to supplement its $580 million credit facility, AEM has a $200 million intercompany uncommitted demand credit facility with AEH, which bears interest at the rate of AEM’s $580 million uncommitted demand working capital credit facility plus 0.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility. At June 30, 2008, there was $41.0 million outstanding under this facility.

 

 

We had other covenants in addition to those described above. Our Series P First Mortgage Bonds contained provisions that allowed us to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The First Mortgage Bonds provided for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. In May 2008, we redeemed our Series P First Mortgage Bonds which were scheduled to mature in November 2013. Since the bonds have been redeemed, the debt covenants described above no longer apply.

 

We were in compliance with all of our debt covenants as of June 30, 2008. 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 Energy 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 a 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.

 

 

In November 1997, our Board of Directors declared a dividend distribution of one right for each outstanding share of our common stock to shareholders of record at the close of business on May 10, 1998, the description and terms of which were set forth in a rights agreement between us and the rights agent dated May 10, 1998. From that time until the expiration of the rights agreement on May 10, 2008, when all rights terminated, each share of common stock we issued included a right that entitled the holder to purchase from us a one-tenth share of our common stock at a purchase price of $8.00 per share, subject to adjustment.

 

 

 

Basic and diluted earnings (loss) per share for the three and nine months ended June 30, 2008 and 2007 are calculated as follows:

 

 

There were approximately 557,000 and 466,000 restricted and other shares and approximately 99,000 and 165,000 stock options that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2008 and 2007 as their inclusion in the computation would be anti-dilutive.

 

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2008 and 2007 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 and nine months ended June 30, 2008 and 2007 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 and nine months ended June 30, 2008 and 2007 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 has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. We are not required to contribute to our pension plans during fiscal 2008 and do not anticipate making contributions. However, we contributed $6.7 million to our other post-retirement benefit plans during the nine months ended June 30, 2008. We expect to contribute a total of approximately $10 million to these plans during fiscal 2008.

 

 

 

In December 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 forpre-arrangedreleased firm capacity on natural gas pipelines. We have responded timely to two sets of data requests received from the Commission and are fully cooperating with the Commission during this investigation.

 

Subsequent to responding to the second set of data requests, the Commission agreed to allow the Company to conduct our own internal investigation into compliance with the Commission’s rules, and we will provide the results of this internal investigation to the Commission upon its completion. We currently are unable to predict the final outcome of this investigation or the potential impact it could have on our financial position, results of operations or cash flows.

 

On May 29, 2008, the Texas Railroad Commission adopted a rule effective September 1, 2008, which will be applicable to all natural gas utility companies operating in Texas concerning the replacement of compression couplings at pre-bent gas meter risers. Compliance with this rule will require us to expend significant amounts of capital. This will cause us to redirect a greater portion of our capital budget towards

 

 

our Mid-Tex Division but these prudent and mandatory expenditures should be recoverable through our rates in this division. As a result, we anticipate no long-term adverse impact on our financial position, results of operations or cash flows.

 

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to the financial statements in our Annual Report onForm 10-Kfor the year ended September 30, 2007, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2008. 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 June 30, 2008, AEM was committed to purchase 76.5 Bcf within one year, 38.4 Bcf within one to three years and 1.8 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $7.68 to $14.37. Purchases under these contracts totaled $842.1 million and $567.9 million for the three months ended June 30, 2008 and 2007 and $2,274.4 million and $1,551.3 million for the nine months ended June 30, 2008 and 2007.

 

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 June 30, 2008 are as follows (in thousands):

 

 

 

During the three months ended June 30, 2008, we concluded rate cases we had filed in our Kansas and Mid-Tex service areas. As of June 30, 2008, rate cases were in progress in our Georgia and Virginia service areas, and we were working with the intervenors to complete their review of the Mid-Tex Division’s first Rate

 

 

Review Mechanism filing made in April 2008. These regulatory proceedings are discussed in further detail inManagement’s Discussion and Analysis — Recent Ratemaking Developments.

 

 

Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report onForm 10-Kfor the year ended September 30, 2007. During the nine months ended June 30, 2008, 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 primarily in the Midwest and Southeast. Additionally, we provide natural gas transportation and storage services to certain of our natural gas distribution operations and to third parties.

 

We operate the Company through the following four segments:

 

 

In our determination of reportable segments, we consider 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.

 

As described in our Annual Report onForm 10-Kfor the fiscal year ended September 30, 2007, we changed the composition of our operating segments. Effective September 2007, all prior period segment information has been restated to conform to our new segment presentation.

 

 

Income statements for the three and nine-month periods ended June 30, 2008 and 2007 by segment are presented in the following tables: