e10vq
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
     
(Mark One)    
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended June 30, 2008
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from               to          
 
Commission File Number 1-10042
 
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
     
Texas and Virginia
  75-1743247
(State or other jurisdiction of
incorporation or organization)
  (IRS employer
identification no.)
 
     
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
  75240
(Zip code)
(Address of principal executive offices)    
 
(972) 934-9227
(Registrant’s telephone number, including area code)
 
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 in Rule 12b-2 of 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.
 
     
Class
 
Shares Outstanding
 
No Par Value
  90,627,522
 


TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
ATMOS ENERGY CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Business
2. Unaudited Interim Financial Information
3. Derivative Instruments and Hedging Activities
4. Debt
5. Shareholders’ Equity
6. Earnings Per Share
7. Interim Pension and Other Postretirement Benefit Plan Information
8. Commitments and Contingencies
9. Concentration of Credit Risk
10. Segment Information
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
PART II. OTHER INFORMATION
SIGNATURES
EXHIBITS INDEX Item 6(a)
Computation of Ratio of Earnings to Fixed Charges
Letter Regarding Unaudited Interim Financial Information
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications


Table of Contents

 
GLOSSARY OF KEY TERMS
 
     
AEC
  Atmos Energy Corporation
AEH
  Atmos Energy Holdings, Inc.
AEM
  Atmos Energy Marketing, LLC
AES
  Atmos Energy Services, LLC
APS
  Atmos Pipeline and Storage, LLC
Bcf
  Billion cubic feet
EITF
  Emerging Issues Task Force
FASB
  Financial Accounting Standards Board
FIN
  FASB Interpretation
Fitch
  Fitch Ratings, Ltd.
GRIP
  Gas Reliability Infrastructure Program
KCC
  Kansas Corporation Commission
LPSC
  Louisiana Public Service Commission
Mcf
  Thousand cubic feet
MMcf
  Million cubic feet
Moody’s
  Moody’s Investors Services, Inc.
NYMEX
  New York Mercantile Exchange, Inc.
RRC
  Railroad Commission of Texas
RSC
  Rate Stabilization Clause
S&P
  Standard & Poor’s Corporation
SEC
  United States Securities and Exchange Commission
SFAS
  Statement of Financial Accounting Standards
TRA
  Tennessee Regulatory Authority
WNA
  Weather Normalization Adjustment


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Table of Contents

 
PART I. FINANCIAL INFORMATION
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    June 30,
    September 30,
 
    2008     2007  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 5,604,416     $ 5,396,070  
Less accumulated depreciation and amortization
    1,591,528       1,559,234  
                 
Net property, plant and equipment
    4,012,888       3,836,836  
Current assets
               
Cash and cash equivalents
    46,501       60,725  
Cash held on deposit in margin account
    62,152        
Accounts receivable, net
    601,164       380,133  
Gas stored underground
    571,532       515,128  
Other current assets
    115,609       112,909  
                 
Total current assets
    1,396,958       1,068,895  
Goodwill and intangible assets
    737,221       737,692  
Deferred charges and other assets
    237,723       253,494  
                 
    $ 6,384,790     $ 5,896,917  
                 
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
               
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
June 30, 2008 — 90,571,457 shares;
September 30, 2007 — 89,326,537 shares
  $ 453     $ 447  
Additional paid-in capital
    1,732,775       1,700,378  
Retained earnings
    371,486       281,127  
Accumulated other comprehensive income (loss)
    693       (16,198 )
                 
Shareholders’ equity
    2,105,407       1,965,754  
Long-term debt
    2,119,729       2,126,315  
                 
Total capitalization
    4,225,136       4,092,069  
Current liabilities
               
Accounts payable and accrued liabilities
    582,353       355,255  
Other current liabilities
    472,088       409,993  
Short-term debt
    113,257       150,599  
Current maturities of long-term debt
    1,059       3,831  
                 
Total current liabilities
    1,168,757       919,678  
Deferred income taxes
    450,669       370,569  
Regulatory cost of removal obligation
    280,108       271,059  
Deferred credits and other liabilities
    260,120       243,542  
                 
    $ 6,384,790     $ 5,896,917  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    June 30  
    2008     2007  
    (Unaudited)  
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 676,639     $ 548,251  
Regulated transmission and storage segment
    46,286       36,707  
Natural gas marketing segment
    1,189,722       854,167  
Pipeline, storage and other segment
    3,880       2,073  
Intersegment eliminations
    (277,382 )     (223,046 )
                 
      1,639,145       1,218,152  
Purchased gas cost
               
Natural gas distribution segment
    476,711       357,608  
Regulated transmission and storage segment
           
Natural gas marketing segment
    1,192,353       854,743  
Pipeline, storage and other segment
    706       228  
Intersegment eliminations
    (276,847 )     (222,443 )
                 
      1,392,923       990,136  
                 
Gross profit
    246,222       228,016  
Operating expenses
               
Operation and maintenance
    117,822       115,141  
Depreciation and amortization
    50,356       48,974  
Taxes, other than income
    57,335       52,881  
Impairment of long-lived assets
          3,289  
                 
Total operating expenses
    225,513       220,285  
                 
Operating income
    20,709       7,731  
Miscellaneous income
    1,600       4,266  
Interest charges
    33,470       34,479  
                 
Loss before income taxes
    (11,161 )     (22,482 )
Income tax benefit
    (4,573 )     (9,122 )
                 
Net loss
  $ (6,588 )   $ (13,360 )
                 
Basic net loss per share
  $ (0.07 )   $ (0.15 )
                 
Diluted net loss per share
  $ (0.07 )   $ (0.15 )
                 
Cash dividends per share
  $ 0.325     $ 0.320  
                 
Weighted average shares outstanding:
               
Basic
    89,648       88,366  
                 
Diluted
    89,648       88,366  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Nine Months Ended
 
    June 30  
    2008     2007  
    (Unaudited)  
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 3,126,672     $ 2,973,528  
Regulated transmission and storage segment
    142,772       122,647  
Natural gas marketing segment
    3,159,092       2,360,902  
Pipeline, storage and other segment
    20,629       27,483  
Intersegment eliminations
    (668,525 )     (588,193 )
                 
      5,780,640       4,896,367  
Purchased gas cost
               
Natural gas distribution segment
    2,296,020       2,174,071  
Regulated transmission and storage segment
           
Natural gas marketing segment
    3,099,428       2,275,291  
Pipeline, storage and other segment
    1,773       682  
Intersegment eliminations
    (666,835 )     (585,971 )
                 
      4,730,386       3,864,073  
                 
Gross profit
    1,050,254       1,032,294  
Operating expenses
               
Operation and maintenance
    359,064       342,373  
Depreciation and amortization
    147,659       149,035  
Taxes, other than income
    153,170       149,694  
Impairment of long-lived assets
          3,289  
                 
Total operating expenses
    659,893       644,391  
                 
Operating income
    390,361       387,903  
Miscellaneous income
    2,974       7,683  
Interest charges
    103,803       109,273  
                 
Income before income taxes
    289,532       286,313  
Income tax expense
    110,783       111,907  
                 
Net income
  $ 178,749     $ 174,406  
                 
Basic net income per share
  $ 2.00     $ 2.02  
                 
Diluted net income per share
  $ 1.99     $ 2.00  
                 
Cash dividends per share
  $ 0.975     $ 0.960  
                 
Weighted average shares outstanding:
               
Basic
    89,281       86,378  
                 
Diluted
    89,937       87,011  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Nine Months Ended
 
    June 30  
    2008     2007  
    (Unaudited)  
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 178,749     $ 174,406  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    147,659       149,035  
Charged to other accounts
    106       148  
Deferred income taxes
    77,864       37,266  
Other
    12,767       17,959  
Net assets / liabilities from risk management activities
    35,169       12,325  
Net change in operating assets and liabilities
    (34,933 )     161,531  
                 
Net cash provided by operating activities
    417,381       552,670  
Cash Flows From Investing Activities
               
Capital expenditures
    (312,878 )     (263,023 )
Other, net
    (4,303 )     (9,867 )
                 
Net cash used in investing activities
    (317,181 )     (272,890 )
Cash Flows From Financing Activities
               
Net decrease in short-term debt
    (35,721 )     (382,416 )
Net proceeds from long-term debt offering
          247,461  
Settlement of Treasury lock agreement
          4,750  
Repayment of long-term debt
    (9,945 )     (2,685 )
Cash dividends paid
    (87,821 )     (83,118 )
Issuance of common stock
    19,063       18,883  
Net proceeds from equity offering
          191,913  
                 
Net cash used in financing activities
    (114,424 )     (5,212 )
                 
Net increase (decrease) in cash and cash equivalents
    (14,224 )     274,568  
Cash and cash equivalents at beginning of period
    60,725       75,815  
                 
Cash and cash equivalents at end of period
  $ 46,501     $ 350,383  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2008
 
1.   Nature of Business
 
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:
 
     
Division   Service Area
 
Atmos Energy Colorado-Kansas Division
  Colorado, Kansas, Missouri(1)
Atmos Energy Kentucky/Mid-States Division
  Georgia(1), Illinois(1), Iowa(1), Kentucky, Missouri(1) Tennessee, Virginia(1)
Atmos Energy Louisiana Division
  Louisiana
Atmos Energy Mid-Tex Division
  Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division
  Mississippi
Atmos Energy West Texas Division
  West Texas
 
 
(1) Denotes states where we have more limited service areas.
 
In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulation and/or regulation 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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
2.   Unaudited Interim Financial Information
 
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 to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in its Annual Report on Form 10-K for the fiscal year ended September 30, 2007. Because of seasonal and other factors, the results of operations for the three and nine-month periods ended June 30, 2008 are not indicative of our results of operations for the full 2008 fiscal year, which ends September 30, 2008.
 
Significant accounting policies
 
Our accounting policies are described in Note 2 to the financial statements in our Annual Report on Form 10-K for 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.


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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):
 
         
Total unrecognized tax benefits at October 1, 2007
  $ 6,156  
Gross increases for current year’s tax positions
     
Gross increases for prior years’ tax positions
    2,331  
Gross decreases for prior years’ tax positions
    (528 )
Settlements
     
         
Total unrecognized tax benefits at June 30, 2008
  $ 7,959  
         
 
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.
 
Regulatory assets and liabilities
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Significant regulatory assets and liabilities as of June 30, 2008 and September 30, 2007 included the following:
 
                 
    June 30,
    September 30,
 
    2008     2007  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 52,623     $ 59,022  
Merger and integration costs, net
    7,689       7,996  
Deferred gas costs
    21,473       14,797  
Environmental costs
    1,014       1,303  
Rate case costs
    13,758       10,989  
Deferred franchise fees
    690       796  
Other
    8,474       10,719  
                 
    $ 105,721     $ 105,622  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 109,439     $ 84,043  
Regulatory cost of removal obligation
    300,994       295,241  
Deferred income taxes, net
    165       165  
Other
    7,292       7,503  
                 
    $ 417,890     $ 386,952  
                 
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Comprehensive income
 
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:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
    (In thousands)  
 
Net income (loss)
  $ (6,588 )   $ (13,360 )   $ 178,749     $ 174,406  
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $531 and $215 for the three months ended June 30, 2008 and 2007 and of $(140) and $964 for the nine months ended June 30, 2008 and 2007
    866       353       (231 )     1,575  
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $482 and $1,863 for the three months ended June 30, 2008 and 2007 and $1,446 and $3,373 for the nine months ended June 30, 2008 and 2007
    787       3,039       2,361       5,501  
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $1,850 and $(2,832) for the three months ended June 30, 2008 and 2007 and $9,047 and $12,504 for the nine months ended June 30, 2008 and 2007
    3,018       (4,621 )     14,761       20,401  
                                 
Comprehensive income (loss)
  $ (1,917 )   $ (14,589 )   $ 195,640     $ 201,883  
                                 
 
Accumulated other comprehensive income (loss), net of tax, as of June 30, 2008 and September 30, 2007 consisted of the following unrealized gains (losses):
 
                 
    June 30,
    September 30,
 
    2008     2007  
    (In thousands)  
 
Accumulated other comprehensive income (loss):
               
Unrealized holding gains on investments
  $ 2,576     $ 2,807  
Treasury lock agreements
    (11,891 )     (14,252 )
Cash flow hedges
    10,008       (4,753 )
                 
    $ 693     $ (16,198 )
                 
 
Recently issued accounting pronouncements
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
3.   Derivative Instruments and Hedging Activities
 
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:
 
                         
    Natural
    Natural
       
    Gas
    Gas
       
    Distribution     Marketing     Total  
    (In thousands)  
 
June 30, 2008:
                       
Assets from risk management activities, current
  $ 37,366     $ 5,534     $ 42,900  
Assets from risk management activities, noncurrent
          5,904       5,904  
Liabilities from risk management activities, current
          (50,686 )     (50,686 )
Liabilities from risk management activities, noncurrent
          (3,724 )     (3,724 )
                         
Net assets (liabilities)
  $ 37,366     $ (42,972 )   $ (5,606 )
                         
September 30, 2007:
                       
Assets from risk management activities, current
  $     $ 21,849     $ 21,849  
Assets from risk management activities, noncurrent
          5,535       5,535  
Liabilities from risk management activities, current
    (21,053 )     (286 )     (21,339 )
Liabilities from risk management activities, noncurrent
          (290 )     (290 )
                         
Net assets (liabilities)
  $ (21,053 )   $ 26,808     $ 5,755  
                         


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Natural Gas Distribution Derivative Activities
 
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.
 
Natural Gas Marketing Derivative Activities
 
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.
 
Pipeline, Storage and Other Derivative Activities
 
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.
 
Treasury Derivative Activities
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
    (In thousands)  
 
Increase (decrease) in fair value:
                               
Treasury lock agreements
  $     $ 2,204     $     $ 2,945  
Forward commodity contracts
    6,636       (4,750 )     16,285       (6,975 )
Recognition of (gains) losses in earnings due to settlements:
                               
Treasury lock agreements
    787       835       2,361       2,556  
Forward commodity contracts
    (3,618 )     129       (1,524 )     27,376  
                                 
Total other comprehensive income (loss) from hedging, net of tax(1)
  $ 3,805     $ (1,582 )   $ 17,122     $ 25,902  
                                 
 
 
(1) Utilizing an income tax rate of approximately 38 percent comprised of the effective rates in each taxing jurisdiction.
 
Hedge Ineffectiveness
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
    (In thousands)  
 
Basis ineffectiveness:
                               
Fair value basis ineffectiveness
  $ (2,402 )   $ 1,073     $ (1,185 )   $ 942  
Cash flow basis ineffectiveness
    (406 )     1,479       (281 )     710  
                                 
Total basis ineffectiveness
    (2,808 )     2,552       (1,466 )     1,652  
Timing ineffectiveness:
                               
Fair value timing ineffectiveness
    (1,842 )     (1,759 )     42,040       80,456  
                                 
Total hedge ineffectiveness
  $ (4,650 )   $ 793     $ 40,574     $ 82,108  
                                 
 
4.   Debt
 
Long-term debt
 
Long-term debt at June 30, 2008 and September 30, 2007 consisted of the following:
 
                 
    June 30,
    September 30,
 
    2008     2007  
    (In thousands)  
 
Unsecured 4.00% Senior Notes, due October 2009
  $ 400,000     $ 400,000  
Unsecured 7.375% Senior Notes, due 2011
    350,000       350,000  
Unsecured 10% Notes, due 2011
    2,303       2,303  
Unsecured 5.125% Senior Notes, due 2013
    250,000       250,000  
Unsecured 4.95% Senior Notes, due 2014
    500,000       500,000  
Unsecured 6.35% Senior Notes, due 2017
    250,000       250,000  
Unsecured 5.95% Senior Notes, due 2034
    200,000       200,000  
Medium term notes
               
Series A, 1995-2, 6.27%, due 2010
    10,000       10,000  
Series A, 1995-1, 6.67%, due 2025
    10,000       10,000  
Unsecured 6.75% Debentures, due 2028
    150,000       150,000  
First Mortgage Bonds
               
Series P, 10.43% due May 2008
          7,500  
Other term notes due in installments through 2013
    1,648       3,890  
                 
Total long-term debt
    2,123,951       2,133,693  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (3,163 )     (3,547 )
Current maturities
    (1,059 )     (3,831 )
                 
    $ 2,119,729     $ 2,126,315  
                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Short-term debt
 
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.
 
Shelf Registration
 
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 stock and/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.
 
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 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.
 
Committed credit facilities
 
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 unsecured 364-day facility 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
total-debt-to-total-capitalization ratio, 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.
 
Uncommitted credit facilities
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Debt Covenants
 
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.
 
5.   Shareholders’ Equity
 
Public Offering
 
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.
 
Shareholder Rights Plan
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
6.   Earnings Per Share
 
Basic and diluted earnings (loss) per share for the three and nine months ended June 30, 2008 and 2007 are calculated as follows:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
    (In thousands, except per share amounts)  
 
Net income (loss)
  $ (6,588 )   $ (13,360 )   $ 178,749     $ 174,406  
                                 
Denominator for basic income per share —
weighted average common shares
    89,648       88,366       89,281       86,378  
Effect of dilutive securities:
                               
Restricted and other shares
                557       464  
Stock options
                99       169  
                                 
Denominator for diluted income per share —
weighted average common shares
    89,648       88,366       89,937       87,011  
                                 
Income (loss) per share — basic
  $ (0.07 )   $ (0.15 )   $ 2.00     $ 2.02  
                                 
Income (loss) per share — diluted
  $ (0.07 )   $ (0.15 )   $ 1.99     $ 2.00  
                                 
 
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.
 
7.   Interim Pension and Other Postretirement Benefit Plan Information
 
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.
 
                                 
    Three Months Ended June 30  
    Pension Benefits     Other Benefits  
    2008     2007     2008     2007  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 3,879     $ 4,017     $ 3,342     $ 2,807  
Interest cost
    6,736       6,496       2,912       2,640  
Expected return on assets
    (6,311 )     (6,089 )     (715 )     (597 )
Amortization of transition asset
                377       377  
Amortization of prior service cost
    (171 )     44             9  
Amortization of actuarial loss
    1,926       2,435              
                                 
Net periodic pension cost
  $ 6,059     $ 6,903     $ 5,916     $ 5,236  
                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Nine Months Ended June 30  
    Pension Benefits     Other Benefits  
    2008     2007     2008     2007  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 11,635     $ 12,053     $ 10,024     $ 8,421  
Interest cost
    20,208       19,486       8,736       7,921  
Expected return on assets
    (18,932 )     (18,267 )     (2,145 )     (1,791 )
Amortization of transition asset
                1,133       1,133  
Amortization of prior service cost
    (513 )     134             25  
Amortization of actuarial loss
    5,778       7,303              
                                 
Net periodic pension cost
  $ 18,176     $ 20,709     $ 17,748     $ 15,709  
                                 
 
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:
 
                                 
    Pension Benefits     Other Benefits  
    2008     2007     2008     2007  
 
Discount rate
    6.30 %     6.30 %     6.30 %     6.30 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %
Expected return on plan assets
    8.25 %     8.25 %     5.00 %     5.20 %
 
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.
 
8.   Commitments and Contingencies
 
Litigation and Environmental Matters
 
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 for pre-arranged released 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

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 on Form 10-K for 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.
 
Purchase Commitments
 
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):
 
         
2008
  $ 71,430  
2009
    632,496  
2010
    164,008  
2011
    14,066  
2012
    12,878  
Thereafter
    16,124  
         
    $ 911,002  
         
 
Regulatory Matters
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Review Mechanism filing made in April 2008. These regulatory proceedings are discussed in further detail in Management’s Discussion and Analysis — Recent Ratemaking Developments.
 
9.   Concentration of Credit Risk
 
Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for 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.
 
10.   Segment Information
 
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:
 
  •  the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
 
  •  the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division,
 
  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services and
 
  •  the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.
 
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 on Form 10-K for 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 on Form 10-K for 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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Income statements for the three and nine-month periods ended June 30, 2008 and 2007 by segment are presented in the following tables:
 
                                                 
    Three Months Ended June 30, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 676,418     $ 27,321     $ 933,931     $ 1,475     $     $ 1,639,145  
Intersegment revenues
    221       18,965       255,791       2,405       (277,382 )      
                                                 
      676,639       46,286       1,189,722       3,880       (277,382 )     1,639,145  
Purchased gas cost
    476,711             1,192,353       706       (276,847 )     1,392,923  
                                                 
Gross profit
    199,928       46,286       (2,631 )     3,174       (535 )     246,222  
Operating expenses
                                               
Operation and maintenance
    95,853       17,042       4,433       1,115       (621 )     117,822  
Depreciation and amortization
    44,737       4,860       381       378             50,356  
Taxes, other than income
    54,141       2,493       391       310             57,335  
                                                 
Total operating expenses
    194,731       24,395       5,205       1,803       (621 )     225,513  
                                                 
Operating income (loss)
    5,197       21,891       (7,836 )     1,371       86       20,709  
Miscellaneous income
    3,508       550       377       2,273       (5,108 )     1,600  
Interest charges
    28,504       6,606       2,850       532       (5,022 )     33,470  
                                                 
Income (loss) before income taxes
    (19,799 )     15,835       (10,309 )     3,112             (11,161 )
Income tax expense (benefit)
    (7,421 )     5,570       (3,995 )     1,273             (4,573 )
                                                 
Net income (loss)
  $ (12,378 )   $ 10,265     $ (6,314 )   $ 1,839     $     $ (6,588 )
                                                 
Capital expenditures
  $ 92,856     $ 18,252     $ 132     $ 2,916     $     $ 114,156  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Three Months Ended June 30, 2007  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 548,104     $ 20,694     $ 649,633     $ (279 )   $     $ 1,218,152  
Intersegment revenues
    147       16,013       204,534       2,352       (223,046 )      
                                                 
      548,251       36,707       854,167       2,073       (223,046 )     1,218,152  
Purchased gas cost
    357,608             854,743       228       (222,443 )     990,136  
                                                 
Gross profit
    190,643       36,707       (576 )     1,845       (603 )     228,016  
Operating expenses
                                               
Operation and maintenance
    93,623       14,139       6,854       1,214       (689 )     115,141  
Depreciation and amortization
    43,661       4,559       376       378             48,974  
Taxes, other than income
    50,005       2,288       295       293             52,881  
Impairment of long-lived assets
    3,289                               3,289  
                                                 
Total operating expenses
    190,578       20,986       7,525       1,885       (689 )     220,285  
                                                 
Operating income (loss)
    65       15,721       (8,101 )     (40 )     86       7,731  
Miscellaneous income
    2,232       620       1,578       3,992       (4,156 )     4,266  
Interest charges
    28,987       6,720       2,012       830       (4,070 )     34,479  
                                                 
Income (loss) before income taxes
    (26,690 )     9,621       (8,535 )     3,122             (22,482 )
Income tax expense (benefit)
    (11,000 )     3,459       (2,925 )     1,344             (9,122 )
                                                 
Net income (loss)
  $ (15,690 )   $ 6,162     $ (5,610 )   $ 1,778     $     $ (13,360 )
                                                 
Capital expenditures
  $ 78,829     $ 10,761     $ 187     $ 454     $     $ 90,231  
                                                 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Nine Months Ended June 30, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
                (In thousands)              
 
Operating revenues from external parties
  $ 3,126,083     $ 72,588     $ 2,568,643     $ 13,326     $     $ 5,780,640  
Intersegment revenues
    589       70,184       590,449       7,303       (668,525 )      
                                                 
      3,126,672       142,772       3,159,092       20,629       (668,525 )     5,780,640  
Purchased gas cost
    2,296,020             3,099,428       1,773       (666,835 )     4,730,386  
                                                 
Gross profit
    830,652       142,772       59,664       18,856       (1,690 )     1,050,254  
Operating expenses
                                               
Operation and maintenance
    291,678       47,560       17,835       3,939       (1,948 )     359,064  
Depreciation and amortization
    130,699       14,683       1,142       1,135             147,659  
Taxes, other than income
    142,063       6,322       3,798       987             153,170  
                                                 
Total operating expenses
    564,440       68,565       22,775       6,061       (1,948 )     659,893  
                                                 
Operating income
    266,212       74,207       36,889       12,795       258       390,361  
Miscellaneous income
    7,654       933       1,775       6,243       (13,631 )     2,974  
Interest charges
    88,802       20,453       6,166       1,755       (13,373 )     103,803  
                                                 
Income before income taxes
    185,064       54,687       32,498       17,283             289,532  
Income tax expense
    71,622       19,351       12,933       6,877             110,783  
                                                 
Net income
  $ 113,442     $ 35,336     $ 19,565     $ 10,406     $     $ 178,749  
                                                 
Capital expenditures
  $ 266,840     $ 40,334     $ 201     $ 5,503     $     $ 312,878  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Nine Months Ended June 30, 2007  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
                (In thousands)              
 
Operating revenues from external parties
  $ 2,973,048     $ 59,029     $ 1,844,271     $ 20,019     $     $ 4,896,367  
Intersegment revenues
    480       63,618       516,631       7,464       (588,193 )      
                                                 
      2,973,528       122,647       2,360,902       27,483       (588,193 )     4,896,367  
Purchased gas cost
    2,174,071             2,275,291       682       (585,971 )     3,864,073  
                                                 
Gross profit
    799,457       122,647       85,611       26,801       (2,222 )     1,032,294  
Operating expenses
                                               
Operation and maintenance
    284,064       37,594       19,022       4,173       (2,480 )     342,373  
Depreciation and amortization
    133,287       13,400       1,153       1,195             149,035  
Taxes, other than income
    141,292       6,584       951       867             149,694  
Impairment of long-lived assets
    3,289                               3,289  
                                                 
Total operating expenses
    561,932       57,578       21,126       6,235       (2,480 )     644,391  
                                                 
Operating income
    237,525       65,069       64,485       20,566       258       387,903  
Miscellaneous income
    6,633       1,530       5,816       5,588       (11,884 )     7,683  
Interest charges
    91,164       20,852       3,418       5,465       (11,626 )     109,273  
                                                 
Income before income taxes
    152,994       45,747       66,883       20,689             286,313  
Income tax expense
    60,530       16,661       26,515       8,201             111,907  
                                                 
Net income
  $ 92,464     $ 29,086     $ 40,368     $ 12,488     $     $ 174,406  
                                                 
Capital expenditures
  $ 222,526     $ 37,142     $ 837     $ 2,518     $     $ 263,023  
                                                 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at June 30, 2008 and September 30, 2007 by segment is presented in the following tables:
 
                                                 
    June 30, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
                (In thousands)              
 
ASSETS
                                               
Property, plant and equipment, net
  $ 3,398,317     $ 556,196     $ 7,546     $ 50,829     $     $ 4,012,888  
Investment in subsidiaries
    476,542             (2,096 )           (474,446 )      
Current assets
                                               
Cash and cash equivalents
    32,949             13,308       244             46,501  
Cash held on deposit in margin account
                62,152                   62,152  
Assets from risk management activities
    37,366             19,770       147       (14,383 )     42,900  
Other current assets
    687,453       16,669       627,786       49,919       (136,422 )     1,245,405  
Intercompany receivables
    490,979                   203,115       (694,094 )      
                                                 
Total current assets
    1,248,747       16,669       723,016       253,425       (844,899 )     1,396,958  
Intangible assets
                2,245                   2,245  
Goodwill
    567,775       132,490       24,282       10,429             734,976  
Noncurrent assets from risk management activities
                5,904                   5,904  
Deferred charges and other assets
    203,663       9,477       1,228       17,451             231,819  
                                                 
    $ 5,895,044     $ 714,832     $ 762,125     $ 332,134     $ (1,319,345 )   $ 6,384,790  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 2,105,407     $ 124,055     $ 155,832     $ 196,655     $ (476,542 )   $ 2,105,407  
Long-term debt
    2,119,140                   589             2,119,729  
                                                 
Total capitalization
    4,224,547       124,055       155,832       197,244       (476,542 )     4,225,136  
Current liabilities
                                               
Current maturities of long-term debt
                      1,059             1,059  
Short-term debt
    113,257             41,000       17,275       (58,275 )     113,257  
Liabilities from risk management activities
                50,822       14,247       (14,383 )     50,686  
Other current liabilities
    635,200       6,078       343,238       95,290       (76,051 )     1,003,755  
Intercompany payables
          536,235       157,859             (694,094 )      
                                                 
Total current liabilities
    748,457       542,313       592,919       127,871       (842,803 )     1,168,757  
Deferred income taxes
    393,426       44,710       8,948       3,585             450,669  
Noncurrent liabilities from risk management activities
                3,724                   3,724  
Regulatory cost of removal obligation
    280,108                               280,108  
Deferred credits and other liabilities
    248,506       3,754       702       3,434             256,396  
                                                 
    $ 5,895,044     $ 714,832     $ 762,125     $ 332,134     $ (1,319,345 )   $ 6,384,790  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    September 30, 2007  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
                (In thousands)              
 
ASSETS
                                               
Property, plant and equipment, net
  $ 3,251,144     $ 531,921     $ 7,850     $ 45,921     $     $ 3,836,836  
Investment in subsidiaries
    396,474             (2,096 )           (394,378 )      
Current assets
                                               
Cash and cash equivalents
    28,881             31,703       141             60,725  
Cash held on deposit in margin account
                                   
Assets from risk management activities
                26,783       12,947       (17,881 )     21,849  
Other current assets
    643,353       20,065       337,169       76,731       (90,997 )     986,321  
Intercompany receivables
    536,985                   114,300       (651,285 )      
                                                 
Total current assets
    1,209,219       20,065       395,655       204,119       (760,163 )     1,068,895  
Intangible assets
                2,716                   2,716  
Goodwill
    567,775       132,490       24,282       10,429             734,976  
Noncurrent assets from risk management activities
                5,535                   5,535  
Deferred charges and other assets
    227,869       4,898       1,279       13,913             247,959  
                                                 
    $ 5,652,481     $ 689,374     $ 435,221     $ 274,382     $ (1,154,541 )   $ 5,896,917  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 1,965,754     $ 88,719     $ 107,090     $ 200,665     $ (396,474 )   $ 1,965,754  
Long-term debt
    2,125,007                   1,308             2,126,315  
                                                 
Total capitalization
    4,090,761       88,719       107,090       201,973       (396,474 )     4,092,069  
Current liabilities
                                               
Current maturities of long-term debt
    1,250                   2,581             3,831  
Short-term debt
    187,284             30,000             (66,685 )     150,599  
Liabilities from risk management activities
    21,053             18,167             (17,881 )     21,339  
Other current liabilities
    519,642       6,394       186,792       53,297       (22,216 )     743,909  
Intercompany payables
          550,184       101,101             (651,285 )      
                                                 
Total current liabilities
    729,229       556,578       336,060       55,878       (758,067 )     919,678  
Deferred income taxes
    326,518       40,565       (8,925 )     12,411             370,569  
Noncurrent liabilities from risk management activities
                290                   290  
Regulatory cost of removal obligation
    271,059                               271,059  
Deferred credits and other liabilities
    234,914       3,512       706       4,120             243,252  
                                                 
    $ 5,652,481     $ 689,374     $ 435,221     $ 274,382     $ (1,154,541 )   $ 5,896,917  
                                                 


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors
Atmos Energy Corporation
 
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of June 30, 2008, and the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2008 and 2007, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2008 and 2007. These financial statements are the responsibility of the Company’s management.
 
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
 
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
 
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2007, and the related consolidated statements of income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
/s/ Ernst & Young LLP
 
Dallas, Texas
August 5, 2008


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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
INTRODUCTION
 
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2007.
 
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
 
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties, which are discussed in more detail in our Annual Report on Form 10-K for the year ended September 30, 2007, include the following: regulatory trends and decisions, including deregulation initiatives and the impact of rate proceedings before various state regulatory commissions; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in one state; adverse weather conditions; our ability to continue to access the capital markets; the effects of inflation and changes in the availability and prices of natural gas, including the volatility of natural gas prices; the capital-intensive nature of our distribution business, increased competition from energy suppliers and alternative forms of energy; increased costs of providing pension and postretirement health care benefits; the impact of environmental regulations on our business; the inherent hazards and risks involved in operating our distribution business, natural disasters, terrorist activities or other events; and other uncertainties, which may be discussed herein, including the outcome of any pending federal or state regulatory investigations, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
 
OVERVIEW
 
Atmos Energy Corporation and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas 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 primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.


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We operate the Company through the following four segments:
 
  •  the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
 
  •  the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division,
 
  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services and
 
  •  the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.
 
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
 
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
 
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the year ended September 30, 2007 and include the following:
 
  •  Regulation
 
  •  Revenue Recognition
 
  •  Allowance for Doubtful Accounts
 
  •  Derivatives and Hedging Activities
 
  •  Impairment Assessments
 
  •  Pension and Other Postretirement Plans
 
Our critical accounting policies are reviewed by the Audit Committee quarterly. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2008.


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RESULTS OF OPERATIONS
 
The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2008 and 2007:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
    (In thousands, except per share data)  
 
Operating revenues
  $ 1,639,145     $ 1,218,152     $ 5,780,640     $ 4,896,367  
Gross profit
    246,222       228,016       1,050,254       1,032,294  
Operating expenses
    225,513       220,285       659,893       644,391  
Operating income
    20,709       7,731       390,361       387,903  
Miscellaneous income
    1,600       4,266       2,974       7,683  
Interest charges
    33,470       34,479       103,803       109,273  
Income (loss) before income taxes
    (11,161 )     (22,482 )     289,532       286,313  
Income tax expense (benefit)
    (4,573 )     (9,122 )     110,783       111,907  
Net income (loss)
  $ (6,588 )   $ (13,360 )   $ 178,749     $ 174,406  
Diluted net income (loss) per share
  $ (0.07 )   $ (0.15 )   $ 1.99     $ 2.00  
 
Our consolidated net income (loss) during the three and nine months ended June 30, 2008 and 2007 was earned in each of our business segments as follows:
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ (12,378 )   $ (15,690 )   $ 3,312  
Regulated transmission and storage segment
    10,265       6,162       4,103  
Natural gas marketing segment
    (6,314 )     (5,610 )     (704 )
Pipeline, storage and other segment
    1,839       1,778       61  
                         
Net loss
  $ (6,588 )   $ (13,360 )   $ 6,772  
                         
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 113,442     $ 92,464     $ 20,978  
Regulated transmission and storage segment
    35,336       29,086       6,250  
Natural gas marketing segment
    19,565       40,368       (20,803 )
Pipeline, storage and other segment
    10,406       12,488       (2,082 )
                         
Net income
  $ 178,749     $ 174,406     $ 4,343  
                         


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The following tables segregate our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ (2,113 )   $ (9,528 )   $ 7,415  
Nonregulated operations
    (4,475 )     (3,832 )     (643 )
                         
Consolidated net loss
  $ (6,588 )   $ (13,360 )   $ 6,772  
                         
Diluted EPS from regulated operations
  $ (0.02 )   $ (0.11 )   $ 0.09  
Diluted EPS from nonregulated operations
    (0.05 )     (0.04 )     (0.01 )
                         
Consolidated diluted EPS
  $ (0.07 )   $ (0.15 )   $ 0.08  
                         
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 148,778     $ 121,550     $ 27,228  
Nonregulated operations
    29,971       52,856       (22,885 )
                         
Consolidated net income
  $ 178,749     $ 174,406     $ 4,343  
                         
Diluted EPS from regulated operations
  $ 1.66     $ 1.39     $ 0.27  
Diluted EPS from nonregulated operations
    0.33       0.61       (0.28 )
                         
Consolidated diluted EPS
  $ 1.99     $ 2.00     $ (0.01 )
                         
 
The following summarizes the results of our operations and other significant events for the nine months ended June 30, 2008:
 
  •  Regulated operations generated 83 percent of net income during the nine months ended June 30, 2008 compared to 70 percent during the nine months ended June 30, 2007. The $27.2 million increase in our regulated operations net income primarily reflects rate increases in our Mid-Tex, Kansas, Kentucky, Louisiana, Tennessee and West Texas service areas coupled with higher rates and throughput in our Atmos Pipeline — Texas Division.
 
  •  Nonregulated operations contributed 17 percent of net income during the nine months ended June 30, 2008 compared to 30 percent during the nine months ended June 30, 2007. The $22.9 million decrease in our nonregulated operations net income primarily reflects lower asset optimization margins partially offset by higher delivered gas margins and higher unrealized gains.
 
  •  For the nine months ended June 30, 2008, we generated $417.4 million in operating cash flow compared with $552.7 million for the nine months ended June 30, 2007, primarily reflecting an increase in cash required to collateralize our risk management accounts.
 
  •  In September 2007, we filed a statement of intent seeking a rate increase of $51.9 million in our Mid-Tex Division. During the fiscal 2008 second quarter, we reached a settlement agreement with approximately 80 percent of the Mid-Tex Division’s customers. In June 2008, the Railroad Commission of Texas (RRC) issued a final order, which ended the case for the remaining 20 percent of the Mid-Tex Division’s customers.


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Three Months Ended June 30, 2008 compared with Three Months Ended June 30, 2007
 
Natural Gas Distribution Segment
 
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
 
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
 
Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 90 percent of our residential and commercial meters in the following states for the following time periods:
 
     
Georgia
  October – May
Kansas
  October – May
Kentucky
  November – April
Louisiana
  December – March
Mississippi
  November – April
Tennessee
  November – April
Texas: Mid-Tex
  November – April
Texas: West Texas
  October – May
Virginia
  January – December
 
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income. Timing differences exist between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. The effect of these timing differences can be significant in periods of volatile gas prices, particularly in our Mid-Tex Division. These timing differences may favorably or unfavorably affect net income; however, these amounts should offset over time with no permanent impact on net income.
 
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.


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Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 199,928     $ 190,643     $ 9,285  
Operating expenses
    194,731       190,578       4,153  
                         
Operating income
    5,197       65       5,132  
Miscellaneous income
    3,508       2,232       1,276  
Interest charges
    28,504       28,987       (483 )
                         
Loss before income taxes
    (19,799 )     (26,690 )     6,891  
Income tax benefit
    (7,421 )     (11,000 )     3,579  
                         
Net loss
  $ (12,378 )   $ (15,690 )   $ 3,312  
                         
Consolidated natural gas distribution sales volumes — MMcf
    41,357       45,252       (3,895 )
Consolidated natural gas distribution transportation volumes — MMcf
    32,126       29,311       2,815  
                         
Total consolidated natural gas distribution throughput — MMcf
    73,483       74,563       (1,080 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.43     $ 0.41     $ 0.02  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 11.53     $ 7.90     $ 3.63  
 
The following table shows our operating income by natural gas distribution division for the three months ended June 30, 2008 and 2007. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Colorado-Kansas
  $ 542     $ 884     $ (342 )
Kentucky/Mid-States
    5,757       1,762       3,995  
Louisiana
    5,086       5,921       (835 )
Mid-Tex
    (3,043 )     (11,415 )     8,372  
Mississippi
    (946 )     2,115       (3,061 )
West Texas
    (563 )     (391 )     (172 )
Other
    (1,636 )     1,189       (2,825 )
                         
Total
  $ 5,197     $ 65     $ 5,132  
                         
 
The $9.3 million increase in natural gas distribution gross profit primarily reflects an $8.9 million increase in rates. The increase in rates primarily was attributable to the Mid-Tex Division, which increased $5.0 million as a result of the 2006 Gas Reliability Infrastructure Program (GRIP) filing, the current year Mid-Tex rate case and the absence of a one-time GRIP refund in the prior year. The current-year period also reflects $3.9 million in rate increases in our Kansas, Kentucky, Louisiana, Missouri, Tennessee and West Texas service areas.


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Gross profit also increased approximately $0.4 million in revenue-related taxes primarily due to higher revenues, on which the tax is calculated, in the current-year quarter compared to the prior-year quarter. This increase, offset by a $2.9 million quarter-over-quarter increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in a $2.5 million decrease in operating income when compared with the prior-year quarter.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $4.2 million.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $2.3 million, primarily due to an overall increase in administrative costs.
 
Depreciation and amortization expense increased $1.1 million for the third quarter of fiscal 2008 compared with third quarter of fiscal 2007. The increase primarily was attributable to increases in assets placed in service during the current year.
 
Operating expenses for the prior-year quarter also include a $3.3 million noncash charge associated with the write-off of software costs.
 
Interest charges allocated to the natural gas distribution segment decreased $0.5 million due to lower average effective interest rates experienced during the current-year quarter compared to the prior-year quarter.
 
Recent Ratemaking Developments
 
Significant ratemaking developments that occurred during the nine months ended June 30, 2008 are discussed below. The amounts described below represent the gross revenues that were requested or received in each rate filing, which may not necessarily reflect the increase in operating income obtained, as certain operating costs may have increased as a result of a commission’s final ruling.
 
Mid-Tex Division Rate Case
 
In September 2007, Atmos Energy filed a statement of intent seeking a system-wide rate increase of $51.9 million in our Mid-Tex Division. During the fiscal 2008 second quarter, we reached a settlement with 438 of the 439 cities (the “Settlement Cities”), which represent approximately 80 percent of the Mid-Tex Division’s customers. The settlement agreement includes i) an annual system-wide rate increase of approximately $10 million, of which approximately $8 million related to the Settlement Cities; ii) the ability to recover the gas cost portion of bad debt expense, iii) a rate review mechanism (RRM) that will adjust rates for the Settlement Cities annually to reflect changes in the Mid-Tex Division’s cost of service and rate base; iv) an authorized return on equity of 9.6 percent; v) an approved capital structure of 52 percent debt/48 percent equity and vi) the establishment of a new program designed to encourage natural gas conservation. New rates for the Settlement Cities were implemented April 1, 2008.
 
In April 2008, the Mid-Tex Division filed its first RRM that will adjust rates, effective October 1, 2008, for the Settlement Cities only. The filing seeks an annual system-wide rate increase of $33.5 million ($26.8 million for the Settlement Cities) and is currently under review.
 
The City of Dallas and unincorporated areas, which represent the remaining 20 percent of the Mid-Tex Division’s customers, elected not to participate in the settlement agreement. The Mid-Tex Division, the City of Dallas and representatives for the unincorporated areas conducted a full rate case before the Railroad Commission of Texas (RRC), culminating in the issuance of a final order in June 2008. Key terms of the final order include i) a $19.6 million system-wide annual rate increase, of which approximately $3.9 million related to the City of Dallas and unincorporated areas, ii) the ability to recover the gas cost portion of bad debt expense, iii) an authorized return on equity of 10 percent; iv) an approved capital structure of 52 percent debt/48 percent equity and v) the establishment of a new program designed to encourage natural gas conservation. New rates for the City of Dallas and the unincorporated areas were implemented in July 2008.
 
The final order did not include an RRM; therefore, we will continue to make annual filings under the Texas Gas Reliability Infrastructure Program (GRIP) in order to update rates for customers in the City of


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Dallas and in the unincorporated areas for approved capital expenditures, and we will continue to file traditional rate cases as necessary to assist in earning our authorized return in these areas.
 
In May 2008, the Mid-Tex Division filed a system-wide 2007 GRIP filing with the RRC. The filing seeks authorization to increase annual rates, on a system-wide basis by $10.3 million based on $58.2 million of capital costs incurred in 2007. It is currently anticipated that the RRC will issue a final order in this proceeding by November 2008. If approved as filed, the filing should result in an annual rate increase of approximately $2 million for customers in the City of Dallas and the unincorporated areas.
 
Other Rate Case Filings
 
In May 2006, Atmos Energy began receiving “show cause” ordinances from several of the cities in the West Texas Division. In December 2007, our West Texas Division reached a settlement agreement with the West Texas cities, resulting in an approved GRIP filing to include in rate base approximately $7.0 million of capital costs incurred during calendar year 2006. The filing should result in additional annual revenues of approximately $1.1 million.
 
In July 2008, the West Texas cities signed an agreement to implement a rate review mechanism for our West Texas system. The RRM will adjust rates on a periodic basis to reflect changes in the West Texas Division’s cost of service and rate base for this service area. The West Texas Division expects to file its first RRM in September 2008, which will adjust rates for the West Texas cities effective November 15, 2008.
 
In May 2008, the City of Lubbock approved its Conservation and Customer Value Plan (CCVP), which contains an annual rate review mechanism that would adjust rates to reflect changes in the West Texas Division’s cost of service and rate base. The West Texas Division filed its annual review filing under the CCVP in June 2008, which is currently under review by the City of Lubbock. The filing recommends a $0.5 million decrease in annual rates, and is expected to become effective October 1, 2008.
 
In October 2007, our Kentucky/Mid-States Division settled its $11.1 million rate case filed in May 2007 with the Tennessee Regulatory Authority. The settlement resulted in an increase in annual revenues of $4.0 million and a $4.1 million reduction in depreciation expense.
 
In September 2007, we filed an application with the Kansas Corporation Commission (KCC) requesting a rate increase of $5.0 million in our Kansas service area. A final order adopting the Company’s settlement with the KCC Staff was issued in May 2008 resulting in an increase in annual revenues of $2.1 million.
 
In February 2008, we filed for an annual rate increase of $0.9 million in the Virginia jurisdiction of our Kentucky/Mid-States Division. New rates, subject to refund, were implemented in April 2008. A procedural schedule has been established that should result in a final order being issued by the fourth quarter of fiscal year 2008.
 
In March 2008, we filed for an annual rate increase of $6.2 million in the Georgia jurisdiction of our Kentucky/Mid-States Division. The first round of hearings was completed in July 2008. A procedural schedule has been established that should result in a final order being issued by the fourth quarter of fiscal year 2008.
 
Stable Rate Filings
 
Louisiana Division.  In December 2007, we filed our TransLa annual rate stabilization clause with the Louisiana Public Service Commission requesting an increase of $2.2 million, including an increase in depreciation expense of approximately $0.4 million. The filing was for the test year ended September 30, 2007. The TransLa filing was approved in March 2008 and resulted in an increase of $2.1 million in annual revenues effective April 1, 2008. In April 2008, we filed the LGS annual rate stabilization clause, requesting an increase of $2.6 million. The filing was for the test year ended December 31, 2007. The LGS filing was approved in June 2008 and resulted in an increase of $1.7 million in annual revenues effective July 1, 2008.
 
Mississippi Division.  In December 2007, the Mississippi Public Service Commission approved our annual stable rate filing with no change in rates.


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Regulated Transmission and Storage Segment
 
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking and lending arrangements and sales of inventory on hand.
 
Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 18,761     $ 15,718     $ 3,043  
Third-party transportation
    22,485       16,807       5,678  
Storage and park and lend services
    2,387       1,893       494  
Other
    2,653       2,289       364  
                         
Gross profit
    46,286       36,707       9,579  
Operating expenses
    24,395       20,986       3,409  
                         
Operating income
    21,891       15,721       6,170  
Miscellaneous income
    550       620       (70 )
Interest charges
    6,606       6,720       (114 )
                         
Income before income taxes
    15,835       9,621       6,214  
Income tax expense
    5,570       3,459       2,111  
                         
Net income
  $ 10,265     $ 6,162     $ 4,103  
                         
Gross pipeline transportation volumes — MMcf
    181,112       157,825       23,287  
                         
Consolidated pipeline transportation volumes — MMcf
    152,450       125,639       26,811  
                         
 
The $9.6 million increase in gross profit primarily was attributable to a $4.4 million increase from rate adjustments resulting from our 2006 and 2007 GRIP filings and a $2.5 million increase from transportation volumes. Consolidated throughput increased 21 percent, primarily due to increased transportation in the Barnett Shale region of Texas. The improvement in gross profit also reflects $1.5 million of increased per-unit transportation margins due to favorable market conditions.
 
Operating expenses increased $3.4 million primarily due to increased pipeline integrity and maintenance costs.
 
Recent Ratemaking Developments
 
In April 2008, the RRC approved the GRIP filing for our Atmos Pipeline — Texas Division to include in rate base approximately $46.6 million of capital costs incurred during calendar year 2007. The filing should


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result in additional annual revenues of approximately $7.0 million. These revenues represent the gross revenues that were received in the filing, which may not necessarily result in an equal increase in operating income, as some operating costs may increase.
 
Natural Gas Marketing Segment
 
Our natural gas marketing activities are conducted through Atmos Energy Marketing, LLC (AEM). AEM aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues received for services we deliver.
 
Our asset optimization activities seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time.
 
AEM continually manages its net physical position to attempt to increase in the future the potential economic gross profit that was created when the original transaction was executed. Therefore, AEM may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market conditions and recognize any associated gains or losses at that time. If AEM elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to hedge the original financial instruments. If AEM elects to defer the withdrawal of gas, it will reset its financial instruments by settling the original financial instruments and executing new ones to correspond to the revised withdrawal schedule.
 
We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The hedged natural gas inventory is marked to market at the end of each month based on the Gas Daily index with changes in fair value recognized as unrealized gains and losses in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.
 
AEM also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the execution of the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.


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Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas marketing segment for the three months ended June 30, 2008 and 2007 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.
 
Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical (spot) and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Delivered gas
  $ 11,231     $ 9,999     $ 1,232  
Asset optimization
    (37,551 )     (33,376 )     (4,175 )
                         
      (26,320 )     (23,377 )     (2,943 )
Unrealized margins
    23,689       22,801       888  
                         
Gross profit
    (2,631 )     (576 )     (2,055 )
Operating expenses
    5,205       7,525       (2,320 )
                         
Operating loss
    (7,836 )     (8,101 )     265  
Miscellaneous income
    377       1,578       (1,201 )
Interest charges
    2,850       2,012       838  
                         
Loss before income taxes
    (10,309 )     (8,535 )     (1,774 )
Income tax benefit
    (3,995 )     (2,925 )     (1,070 )
                         
Net loss
  $ (6,314 )   $ (5,610 )   $ (704 )
                         
Gross natural gas marketing sales volumes — MMcf
    103,403       104,783       (1,380 )
                         
Consolidated natural gas marketing sales volumes — MMcf
    82,122       85,413       (3,291 )
                         
Net physical position (Bcf)
    17.5       21.5       (4.0 )
                         
 
The $2.1 million decrease in our natural gas marketing segment’s gross profit primarily reflects a $4.2 million decrease in realized asset optimization margins. Natural gas market conditions were significantly less volatile during the current-year compared with the prior-year, which created fewer opportunities to realize arbitrage gains. During the quarter, AEM elected to defer storage withdrawals and reset the corresponding financial instruments in order to increase, in future periods, the potential gross profit it could realize from its asset optimization activities. As a result, AEM realized settlement losses without corresponding storage withdrawal gains in the current quarter. In the prior year, AEM accelerated the withdrawal of physical gas into the fiscal 2007 second quarter and executed new financial instruments to hedge the original financial instruments. The losses incurred on the settlement of these financial instruments in the prior-year quarter were smaller than the settlement losses experienced in the current quarter.
 
The increased loss generated from realized asset optimization activities was partially offset by a $1.2 million increase in realized delivered gas margins. The increase was largely attributable to slightly higher per-unit margins, compared with the prior-year quarter, partially offset by slightly lower sales volumes.


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Gross profit margin was also favorably impacted by a $0.9 million increase in unrealized margins attributable to a narrowing of the spreads between current cash prices and forward natural gas prices. The change in unrealized margins also reflects the recognition of previously unrealized margins as a component of realized margins as a result of injecting and withdrawing gas and settling financial instruments as a part of AEM’s asset optimization activities.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, decreased $2.3 million primarily due to a decrease in employee and other administrative costs.
 
Economic Gross Profit
 
AEM monitors the impact of its asset optimization efforts by estimating the gross profit, before associated storage fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic gross profit, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement is referred to as the potential gross profit.(1) The following table presents AEM’s economic gross profit and its potential gross profit at June 30, 2008, March 31, 2008, December 31, 2007 and September 30, 2007.
 
                                 
                Associated Net
       
    Net Physical
    Economic Gross
    Unrealized Gain
    Potential Gross
 
Period Ending
  Position     Profit     (Loss)     Profit(1)  
    (Bcf)     (In millions)     (In millions)     (In millions)  
 
June 30, 2008
    17.5     $ 48.2     $ 34.3     $ 13.9  
March 31, 2008
    20.7     $ 10.8     $ (0.6 )   $ 11.4  
December 31, 2007
    17.7     $ 44.2     $ 32.9     $ 11.3  
September 30, 2007
    12.3     $ 40.8     $ 10.8     $ 30.0  
 
 
(1) Potential gross profit represents the increase in AEM’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include storage and other operating expenses and increased income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic gross profit or the potential gross profit will be fully realized in the future. We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.
 
As of June 30, 2008, based upon AEM’s planned inventory withdrawal schedule and associated planned settlement of financial instruments, the economic gross profit was $48.2 million. This amount will be reduced by $34.3 million of net unrealized gains recorded in the financial statements as of June 30, 2008 that will reverse when the inventory is withdrawn and the accompanying financial instruments are settled. Therefore, the potential gross profit was $13.9 million at June 30, 2008.
 
The $2.5 million increase in potential gross profit as compared to March 31, 2008, is comprised of a $37.4 million increase in the economic gross profit, principally due to the election to roll positions into forward months as described above, partially offset by a $34.9 million increase in unrealized gains primarily attributable to recognizing as a component of realized margin previously unrealized losses and a favorable movement in the market prices used to value our natural gas storage inventory.
 
The economic gross profit is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic gross profit or the potential gross profit calculated as of June 30, 2008 will be fully realized in the future nor can we predict in what time


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periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted. Assuming AEM fully executes its plan in place on June 30, 2008, without encountering operational or other issues, we anticipate a portion of the potential gross profit as of June 30, 2008 will be recognized during the final quarter of fiscal 2008 with most of the remainder recognized during fiscal 2009.
 
Pipeline, Storage and Other Segment
 
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 Atmos Energy Holdings, Inc.
 
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, beginning in fiscal 2006, APS initiated activities in the natural gas gathering business. As of June 30, 2008, these activities were limited in nature.
 
AES, through December 31, 2006, 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 natural gas distribution service areas at competitive prices. Effective January 1, 2007, these services were moved to our shared services function included in our natural gas distribution segment. 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.
 
Results for this segment are primarily impacted by seasonal weather patterns and volatility in the natural gas markets. Additionally, this segment’s results include an unrealized component as APS hedges its risk associated with its asset optimization activities.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our pipeline, storage and other segment for the three months ended June 30, 2008 and 2007 are presented below.
 
                         
    Three Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Storage and transportation services
  $ 3,691     $ 4,060     $ (369 )
Asset optimization
    (1,329 )     (2,247 )     918  
Other
    1,210       845       365  
Unrealized margins
    (398 )     (813 )     415  
                         
Gross profit
    3,174       1,845       1,329  
Operating expenses
    1,803       1,885       (82 )
                         
Operating income (loss)
    1,371       (40 )     1,411  
Miscellaneous income
    2,273       3,992       (1,719 )
Interest charges
    532       830       (298 )
                         
Income before income taxes
    3,112       3,122       (10 )
Income tax expense
    1,273       1,344       (71 )
                         
Net income
  $ 1,839     $ 1,778     $ 61  
                         


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Pipeline, storage and other gross profit increased $1.3 million primarily due to a $0.9 million increase in asset optimization margins as a result of a more favorable settlement of our asset management contracts in the current-year period. This increase was coupled with a $0.4 million increase in unrealized margins associated with asset optimization activities.
 
Operating expenses for the three months ended June 30, 2008 were consistent with the prior-year quarter.
 
Nine Months Ended June 30, 2008 compared with Nine Months Ended June 30, 2007
 
Natural Gas Distribution Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2008 and 2007 are presented below.
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 830,652     $ 799,457     $ 31,195  
Operating expenses
    564,440       561,932       2,508  
                         
Operating income
    266,212       237,525       28,687  
Miscellaneous income
    7,654       6,633       1,021  
Interest charges
    88,802       91,164       (2,362 )
                         
Income before income taxes
    185,064       152,994       32,070  
Income tax expense
    71,622       60,530       11,092  
                         
Net income
  $ 113,442     $ 92,464     $ 20,978  
                         
Consolidated natural gas distribution sales volumes — MMcf
    261,692       265,508       (3,816 )
Consolidated natural gas distribution transportation volumes — MMcf
    105,605       101,572       4,033  
                         
Total consolidated natural gas distribution throughput — MMcf
    367,297       367,080       217  
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.44     $ 0.46     $ (0.02 )
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 8.77     $ 8.19     $ 0.58  


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The following table shows our operating income by natural gas distribution division for the nine months ended June 30, 2008 and 2007. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Colorado-Kansas
  $ 22,766     $ 24,524     $ (1,758 )
Kentucky/Mid-States
    49,800       44,913       4,887  
Louisiana
    36,254       39,540       (3,286 )
Mid-Tex
    119,661       82,932       36,729  
Mississippi
    23,397       25,918       (2,521 )
West Texas
    13,332       18,230       (4,898 )
Other
    1,002       1,468       (466 )
                         
Total
  $ 266,212     $ 237,525     $ 28,687  
                         
 
The $31.2 million increase in natural gas distribution gross profit primarily reflects a $31.7 million net increase in rates. The net increase in rates primarily was attributable to the Mid-Tex Division which increased $24.1 million as a result of the 2006 GRIP filing, the previous and current year Mid-Tex rate cases and the absence of a one time GRIP refund in the prior year. The current-year period also reflects $10.7 million in rate increases in our Kansas, Kentucky, Louisiana, Tennessee and West Texas service areas.
 
Gross profit also increased approximately $6.5 million in revenue-related taxes primarily due to higher revenues, on which the tax is calculated, in the current-year period compared to the prior-year period. This increase, partially offset by a $2.5 million period-over-period increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in a $4.0 million increase in operating income, when compared with the prior-year period.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased by $2.5 million.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $11.1 million, primarily due to increased administrative and natural gas odorization costs partially offset by lower employee costs. The increase in operation and maintenance expense also reflects the absence in the current-year period of a nonrecurring $4.3 million deferral of hurricane-related operation and maintenance expenses in the prior-year period.
 
The provision for doubtful accounts decreased $3.5 million to $10.2 million for the nine months ended June 30, 2008. The decrease primarily was attributable to strong collection efforts.
 
Depreciation and amortization expense decreased $2.6 million for the nine months ended June 30, 2008 compared with the nine months ended June 30, 2007. The decrease primarily was attributable to changes in depreciation rates as a result of recent rate cases.
 
Operating expenses for the prior-year period also include a $3.3 million noncash charge associated with the write-off of software costs.
 
Results for the current-year period include a $1.2 million gain on the sale of irrigation assets in our West Texas Division during the fiscal 2008 second quarter.
 
Interest charges allocated to the natural gas distribution segment decreased $2.4 million due to lower average outstanding short-term debt balances in the current-year period compared with the prior-year period.


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Regulated Transmission and Storage Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2008 and 2007 are presented below.
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 69,409     $ 62,149     $ 7,260  
Third-party transportation
    58,946       45,162       13,784  
Storage and park and lend services
    6,288       6,943       (655 )
Other
    8,129       8,393       (264 )
                         
Gross profit
    142,772       122,647       20,125  
Operating expenses
    68,565       57,578       10,987  
                         
Operating income
    74,207       65,069       9,138  
Miscellaneous income
    933       1,530       (597 )
Interest charges
    20,453       20,852       (399 )
                         
Income before income taxes
    54,687       45,747       8,940  
Income tax expense
    19,351       16,661       2,690  
                         
Net income
  $ 35,336     $ 29,086     $ 6,250  
                         
Gross pipeline transportation volumes — MMcf
    593,452       528,144       65,308  
                         
Consolidated pipeline transportation volumes — MMcf
    429,758       359,447       70,311  
                         
 
The $20.1 million increase in gross profit primarily was attributable to a $10.0 million increase from rate adjustments resulting from our 2006 and 2007 GRIP filings and a $6.1 million increase from transportation volumes. Consolidated throughput increased 20 percent primarily due to increased transportation in the Barnett Shale region of Texas. The improvement in gross profit also reflects increased service fees and per-unit transportation margins due to favorable market conditions which contributed $3.6 million. New compression contracts and transportation capacity enhancements also contributed $2.4 million. These increases were partially offset by a $1.6 million decrease in sales of excess gas compared to the same period in the prior year and a $1.0 million decrease in parking and lending services due to market conditions.
 
Operating expenses increased $11.0 million primarily due to increased pipeline integrity and maintenance costs.


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Natural Gas Marketing Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas marketing segment for the nine months ended June 30, 2008 and 2007 are presented below.
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Delivered gas
  $ 55,599     $ 44,320     $ 11,279  
Asset optimization
    (10,339 )     38,558       (48,897 )
                         
      45,260       82,878       (37,618 )
Unrealized margins
    14,404       2,733       11,671  
                         
Gross profit
    59,664       85,611       (25,947 )
Operating expenses
    22,775       21,126       1,649  
                         
Operating income
    36,889       64,485       (27,596 )
Miscellaneous income
    1,775       5,816       (4,041 )
Interest charges
    6,166       3,418       2,748  
                         
Income before income taxes
    32,498       66,883       (34,385 )
Income tax expense
    12,933       26,515       (13,582 )
                         
Net income
  $ 19,565     $ 40,368     $ (20,803 )
                         
Gross natural gas marketing sales volumes — MMcf
    348,789       306,931       41,858  
                         
Consolidated natural gas marketing sales volumes — MMcf
    298,351       264,325       34,026  
                         
Net physical position (Bcf)
    17.5       21.5       (4.0 )
                         
 
The $25.9 million decrease in our natural gas marketing segment’s gross profit primarily reflects a $48.9 million decrease in realized asset optimization margins. As a result of a less volatile natural gas market experienced during the year, AEM has been regularly deferring storage withdrawals and resetting the associated financial instruments to increase the potential gross profit it could realize from its asset optimization activities in future periods. As a result, AEM recognized settlement losses without corresponding storage withdrawal gains during the current fiscal year. Additionally, AEM experienced increased storage fees charged by third parties during this time period. In the prior year, AEM was able to recognize arbitrage gains as changes in its originally scheduled storage injection and withdrawal plans had a significantly smaller impact.
 
The decrease in realized asset optimization margins was partially offset by an $11.3 million increase in realized delivered gas margins. The increase reflects both increased sales volumes and increased per-unit margins. Gross sales volumes increased 14 percent compared with the prior-year period as we were able to successfully execute our marketing initiatives. The increase in the per-unit margin primarily reflects favorable basis gains on certain contracts. After excluding the effect of these location basis gains, our per-unit margins decreased four percent in the current-year period due to increased competition experienced during the third fiscal quarter in a higher-priced natural gas market.
 
Gross profit margin was also favorably impacted by an $11.7 million increase in unrealized margins attributable to a narrowing of the spreads between current cash prices and forward natural gas prices. The change in unrealized margins also reflects the recognition of previously unrealized margins as a component of realized margins as a result of injecting and withdrawing gas and settling financial instruments as a part of AEM’s asset optimization activities.


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Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $1.6 million. The increase reflects $2.4 million for the settlement of certain tax matters partially offset by a $0.8 million decrease in employee and other administrative costs.
 
Pipeline, Storage and Other Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our pipeline, storage and other segment for the nine months ended June 30, 2008 and 2007 are presented below.
 
                         
    Nine Months Ended
 
    June 30  
    2008     2007     Change  
    (In thousands)  
 
Storage and transportation services
  $ 11,325     $ 11,850     $ (525 )
Asset optimization
    3,783       10,947       (7,164 )
Other
    3,701       2,992       709  
Unrealized margins
    47       1,012       (965 )
                         
Gross profit
    18,856       26,801       (7,945 )
Operating expenses
    6,061       6,235       (174 )
                         
Operating income
    12,795       20,566       (7,771 )
Miscellaneous income
    6,243       5,588       655  
Interest charges
    1,755       5,465       (3,710 )
                         
Income before income taxes
    17,283       20,689       (3,406 )
Income tax expense
    6,877       8,201       (1,324 )
                         
Net income
  $ 10,406     $ 12,488     $ (2,082 )
                         
 
Pipeline, storage and other gross profit decreased $7.9 million primarily due to a $7.2 million decrease in asset optimization margins as a result of a less volatile natural gas market. The change in gross profit also reflects a decrease of $1.0 million in unrealized margins associated with asset optimization activities.
 
Operating expenses for the nine months ended June 30, 2008 remained generally unchanged compared with the prior-year period.
 
Liquidity and Capital Resources
 
Our working capital and liquidity for capital expenditures and other cash needs are provided from internally generated funds and borrowings under our credit facilities and commercial paper program. Additionally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
 
Cash Flows
 
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
 
Cash flows from operating activities
 
Period-over-period changes in our operating cash flows primarily are attributable to changes in net income, working capital changes, particularly within our natural gas distribution segment resulting from the


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price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
 
For the nine months ended June 30, 2008, we generated operating cash flow of $417.4 million from operating activities compared with $552.7 million for the nine months ended June 30, 2007. Period over period, our operating cash flow was reduced primarily by cash required to collateralize our risk management accounts, which reduced operating cash flows by $84.2 million. Additionally, changes in accounts receivable and gas stored underground reduced operating cash flow by $219.9 million. These decreases were partially offset by favorable timing of accounts payable and accrued liabilities which increased operating cash flow by $141.8 million. Finally, other changes in working capital and other items increased operating cash flow by $27.0 million.
 
Cash flows from investing activities
 
In recent years, a substantial portion of our cash resources has been used to fund acquisitions and growth projects, our ongoing construction program and improvements to information systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
 
Capital expenditures for fiscal 2008 are expected to range from $455 million to $465 million. For the nine months ended June 30, 2008, we incurred $312.9 million for capital expenditures compared with $263.0 million for the nine months ended June 30, 2007. The increase in capital spending primarily reflects an increase in main replacements in our Mid-Tex Division and spending in the natural gas distribution segment for our new automated metering initiative. This initiative is expected to improve the efficiency of our meter reading process through the installation of equipment that automatically reads and transfers customer consumption and other data to our customer information systems.
 
Cash flows from financing activities
 
For the nine months ended June 30, 2008, our financing activities reflected a use of cash of $114.4 million compared with $5.2 million in the prior-year period. Our significant financing activities for the nine months ended June 30, 2008 and 2007 are summarized as follows.
 
  •  During the nine months ended June 30, 2008, we repaid a net $35.7 million under our short-term credit facilities. The net repayment reflects the timing of the use of our line of credit to finance natural gas purchases.
 
  •  We repaid $9.9 million of long-term debt during the nine months ended June 30, 2008 compared with $2.7 million during the nine months ended June 30, 2007. The increased payments during the current-year period reflects the prepayment of $7.5 million of our Series P First Mortgage Bonds. In connection with this prepayment we paid a $0.2 million make-whole premium in accordance with the terms of the bonds and related indenture.
 
  •  In December 2006, we sold 6.3 million shares of common stock in an offering, including the underwriters’ exercise of their overallotment option of 0.8 million shares, generating net proceeds of approximately $192 million. The net proceeds from this issuance were used to reduce our short-term debt.
 
  •  During the nine months ended June 30, 2008, we paid $87.8 million in cash dividends compared with $83.1 million for the nine months ended June 30, 2007. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.96 per share during the nine months


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  ended June 30, 2007 to $0.975 per share during the nine months ended June 30, 2008 combined with our December 2006 equity offering and new share issuances under our various equity plans.
 
  •  During the nine months ended June 30, 2008, we issued 0.7 million shares of common stock under our various equity plans which generated net proceeds of $19.1 million. In addition, we granted 0.5 million shares of common stock under our 1998 Long-Term Incentive Plan.
 
The following table summarizes our share issuances for the nine months ended June 30, 2008 and 2007.
 
                 
    Nine Months Ended
 
    June 30  
    2008     2007  
 
Shares issued:
               
Direct Stock Purchase Plan
    294,071       238,689  
Retirement Savings Plan
    410,350       306,920  
1998 Long-Term Incentive Plan
    538,100       500,684  
Outside Directors Stock-for-Fee Plan
    2,399       1,776  
Public Offering
          6,325,000  
                 
Total shares issued
    1,244,920       7,373,069  
                 
 
Credit Facilities
 
As of June 30, 2008, we had a total of approximately $1.5 billion of credit facilities, comprised of three short-term committed credit facilities totaling $918 million and, through AEM, an uncommitted credit facility that can provide up to $580 million. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis 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 charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather.
 
As of June 30, 2008, the amount available to us under our credit facilities, net of outstanding letters of credit, was $1.0 billion. We believe these credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs. These facilities are described in further detail in Note 4 to the unaudited condensed consolidated financial statements.
 
Shelf Registration
 
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 stock and/or debt securities available for issuance. As of June 30, 2008, we had approximately $450 million available for issuance under the registration statement. Due to certain restrictions imposed 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 three credit rating agencies was achieved.
 
Credit Ratings
 
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt,


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operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
 
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). Our current debt ratings are all considered investment grade and are as follows:
 
                         
    S&P     Moody’s     Fitch  
 
Unsecured senior long-term debt
    BBB       Baa3       BBB+  
Commercial paper
    A-2       P-3       F-2  
 
Currently, with respect to our unsecured senior long-term debt, S&P maintains its positive outlook and Fitch maintains its stable outlook. Moody’s recently reaffirmed its stable outlook. None of our ratings are currently under review.
 
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
 
Debt Covenants
 
We were in compliance with all of our debt covenants as of June 30, 2008. Our debt covenants are described in Note 4 to the unaudited condensed consolidated financial statements.
 
Capitalization
 
The following table presents our capitalization as of June 30, 2008, September 30, 2007 and June 30, 2007:
 
                                                 
    June 30,
    September 30,
    June 30,
 
    2008     2007     2007  
    (In thousands, except percentages)  
 
Short-term debt
  $ 113,257       2.6 %   $ 150,599       3.5 %   $       %
Long-term debt
    2,120,788       48.9 %     2,130,146       50.2 %     2,430,518       55.0 %
Shareholders’ equity
    2,105,407       48.5 %     1,965,754       46.3 %     1,988,142       45.0 %
                                                 
Total capitalization
  $ 4,339,452       100.0 %   $ 4,246,499       100.0 %   $ 4,418,660       100.0 %
                                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 51.5 percent at June 30, 2008, 53.7 percent at September 30, 2007 and 55.0 percent at June 30, 2007. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.
 
Contractual Obligations and Commercial Commitments
 
Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2008.


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In February 2008, Atmos Pipeline and Storage, LLC announced plans to construct and operate a salt-cavern gas storage project in Franklin Parish, Louisiana. The project, located near several large interstate pipelines, includes the development of three 5 billion cubic feet (Bcf) caverns for a total of 15 Bcf of working gas storage, with six-turn injection and withdrawal capacity. Pending regulatory approval, the first cavern is projected to go into operation by mid-2011, with the other two caverns projected to be operational by 2012 and 2014. Based on market demand, four additional storage caverns could potentially be developed.
 
Risk Management Activities
 
We conduct risk management activities through both our natural gas distribution and natural gas marketing segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our fair value hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the derivatives being treated as mark-to-market instruments through earnings. In addition, natural gas inventory would be reflected on the balance sheet at the lower of cost or market instead of at fair value.
 
We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying derivative. Substantially all of our derivative financial instruments are valued using external market quotes and indices. The following tables show the components of the change in the fair value of our natural gas distribution and natural gas marketing commodity derivative contracts for the three and nine months ended June 30, 2008 and 2007:
 
                                 
    Three Months Ended
    Three Months Ended
 
    June 30, 2008     June 30, 2007  
    Natural Gas
    Natural Gas
    Natural Gas
    Natural Gas
 
    Distribution     Marketing     Distribution     Marketing  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ 9,505     $ (22,975 )   $ 3,802     $ (24,994 )
Contracts realized/settled
    339       30,185       (144 )     15,994  
Fair value of new contracts
    5,675             (5,797 )      
Other changes in value
    21,847       (50,182 )     (5,385 )     24,898  
                                 
Fair value of contracts at end of period
  $ 37,366     $ (42,972 )   $ (7,524 )   $ 15,898  
                                 
 
                                 
    Nine Months Ended
    Nine Months Ended
 
    June 30, 2008     June 30, 2007  
    Natural Gas
    Natural Gas
    Natural Gas
    Natural Gas
 
    Distribution     Marketing     Distribution     Marketing  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (21,053 )   $ 26,808     $ (27,209 )   $ 15,003  
Contracts realized/settled
    (26,971 )     (11,071 )     (27,662 )     (10,593 )
Fair value of new contracts
    5,395             (7,058 )      
Other changes in value
    79,995       (58,709 )     54,405       11,488  
                                 
Fair value of contracts at end of period
  $ 37,366     $ (42,972 )   $ (7,524 )   $ 15,898  
                                 


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The fair value of our natural gas distribution and natural gas marketing derivative contracts at June 30, 2008, is segregated below by time period and fair value source:
 
                                         
    Fair Value of Contracts at June 30, 2008  
    Maturity in Years        
                      Greater
    Total Fair
 
Source of Fair Value
  Less than 1     1-3     4-5     Than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ (7,511 )   $ 2,373     $     $     $ (5,138 )
Prices based on models and other valuation methods
    (275 )     (193 )                 (468 )
                                         
Total Fair Value
  $ (7,786 )   $ 2,180     $     $     $ (5,606 )
                                         
 
Pension and Postretirement Benefits Obligations
 
For the nine months ended June 30, 2008 and 2007, our total net periodic pension and other benefits cost was $35.9 million and $36.4 million. These costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
Our total net periodic pension and other benefit costs remained relatively unchanged during the current-year period when compared with the prior-year period as the assumptions we made during our annual pension plan valuation completed June 30, 2007 were consistent with the prior year. 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. At our June 30, 2007 measurement date, the interest rates were consistent with rates at our prior-year measurement date, which resulted in no change to our 6.30 percent discount rate used to determine our fiscal 2008 net periodic and post-retirement cost. In addition, our expected return on our pension plan assets remained constant at 8.25 percent.
 
We are currently in the process of completing our fiscal 2008 pension plan valuation. Based upon market conditions as of the June 30, 2008 valuation date, we expect no significant increase in our fiscal 2009 net periodic pension cost.
 
During the nine months ended June 30, 2008, we contributed $6.7 million to our other postretirement plans, and we expect to contribute a total of approximately $10 million to these plans during fiscal 2008.


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OPERATING STATISTICS AND OTHER INFORMATION
 
The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage, natural gas marketing and pipeline, storage and other segments for the three and nine-month periods ended June 30, 2008 and 2007.
 
Natural Gas Distribution Sales and Statistical Data
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
 
METERS IN SERVICE, end of period
                               
Residential
    2,922,415       2,900,716       2,922,415       2,900,716  
Commercial
    271,542       274,273       271,542       274,273  
Industrial
    2,265       2,739       2,265       2,739  
Public authority and other
    9,234       16,576       9,234       16,576  
                                 
Total meters
    3,205,456       3,194,304       3,205,456       3,194,304  
                                 
INVENTORY STORAGE BALANCE — Bcf
    41.7       43.9       41.7       43.9  
HEATING DEGREE DAYS(1)
                               
Actual (weighted average)
    174       163       2,810       2,873  
Percent of normal
    102 %     98 %     100 %     101 %
SALES VOLUMES — MMcf(2)
                               
Gas sales volumes
                               
Residential
    18,584       21,421       151,549       155,021  
Commercial
    15,199       16,672       82,325       83,231  
Industrial
    4,687       5,248       17,899       18,551  
Public authority and other
    2,887       1,911       9,919       8,705  
                                 
Total gas sales volumes
    41,357       45,252       261,692       265,508  
Transportation volumes
    33,211       30,431       109,002       105,125  
                                 
Total throughput
    74,568       75,683       370,694       370,633  
                                 
OPERATING REVENUES (000’s)(2)
                               
Gas sales revenues
                               
Residential
  $ 352,893     $ 294,756     $ 1,878,855     $ 1,795,124  
Commercial
    213,594       170,425       903,771       855,468  
Industrial
    53,843       44,345       167,154       162,621  
Public authority and other
    33,135       18,193       100,983       84,550  
                                 
Total gas sales revenues
    653,465       527,719       3,050,763       2,897,763  
Transportation revenues
    14,163       12,040       46,954       46,997  
Other gas revenues
    9,011       8,492       28,955       28,768  
                                 
Total operating revenues
  $ 676,639     $ 548,251     $ 3,126,672     $ 2,973,528  
                                 
Average transportation revenue per Mcf
  $ 0.43     $ 0.40     $ 0.43     $ 0.45  
Average cost of gas per Mcf sold
  $ 11.53     $ 7.90     $ 8.77     $ 8.19  
 
See footnotes following these tables.


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Regulated Transmission and Storage, Natural Gas Marketing and Pipeline, Storage and Other Operations Sales and Statistical Data
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2008     2007     2008     2007  
 
CUSTOMERS, end of period
                               
Industrial
    702       700       702       700  
Municipal
    56       64       56       64  
Other
    503       424       503       424  
                                 
Total
    1,261       1,188       1,261       1,188  
                                 
INVENTORY STORAGE BALANCE — Bcf
                               
Natural gas marketing
    18.8       25.1       18.8       25.1  
Pipeline, storage and other
    1.2       1.9       1.2       1.9  
                                 
Total
    20.0       27.0       20.0       27.0  
                                 
REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf(2)
    181,112       157,825       593,452       528,144  
NATURAL GAS MARKETING SALES VOLUMES — MMcf(2)
    103,403       104,783       348,789       306,931  
OPERATING REVENUES (000’s)(2)
                               
Regulated transmission and storage
  $ 46,286     $ 36,707     $ 142,772     $ 122,647  
Natural gas marketing
    1,189,722       854,167       3,159,092       2,360,902  
Pipeline, storage and other
    3,880       2,073       20,629       27,483  
                                 
Total operating revenues
  $ 1,239,888     $ 892,947     $ 3,322,493     $ 2,511,032  
                                 
 
Notes to preceding tables:
 
 
(1) A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Generally, normal degree days are based on 30-year average National Weather Service data for selected locations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.
 
(2) Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.
 
RECENT ACCOUNTING DEVELOPMENTS
 
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.
 
Item 3.   Quantitative and Qualitative Disclosures About Market Risk
 
Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the year ended September 30, 2007. During the nine months ended June 30, 2008, there were no material changes in our quantitative and qualitative disclosures about market risk.


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Item 4.   Controls and Procedures
 
As indicated in the certifications in Exhibit 31 of this report, the Company’s Chief Executive Officer and Chief Financial Officer have evaluated the Company’s disclosure controls and procedures as of June 30, 2008. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are effective in ensuring that material information required to be disclosed by the Company in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. In addition, there were no changes during the Company’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
PART II. OTHER INFORMATION
 
Item 1.   Legal Proceedings
 
During the nine months ended June 30, 2008, except as noted in Note 8 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and environmental-related matters that were disclosed in Note 13 to our Annual Report on Form 10-K for the year ended September 30, 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.
 
Item 6.   Exhibits
 
A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
Atmos Energy Corporation
(Registrant)
 
  By: 
/s/  John P. Reddy
John P. Reddy
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
 
Date: August 6, 2008


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EXHIBITS INDEX
Item 6(a)
 
             
Exhibit
      Page
Number
 
Description
 
Number
 
  12     Computation of ratio of earnings to fixed charges    
  15     Letter regarding unaudited interim financial information    
  31     Rule 13a-14(a)/15d-14(a) Certifications    
  32     Section 1350 Certifications*    
 
 
* These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.


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