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, 2004
 
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
(Address of principal executive offices)
  75240
(Zip code)

(Registrant’s telephone number, including area code)

(972) 934-9227

           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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)     Yes  þ           No  o

          Number of shares outstanding of each of the issuer’s classes of common stock, as of August 2, 2004.

 
     
Class Shares Outstanding


No Par Value
  62,601,735


TABLE OF CONTENTS

PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 6. Exhibits and Reports on Form 8-K
EXHIBITS INDEX Item 6(a)
Revolving Credit Agreement
Computation of Earnings to Fixed Charges
Report from Auditors
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications


 

PART 1.     FINANCIAL INFORMATION

 
 
Item 1. Financial Statements
 

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

                     
June 30, September 30,
2004 2003


(Unaudited)
(In thousands)
ASSETS
Property, plant and equipment
  $ 2,588,059     $ 2,480,139  
 
Less accumulated depreciation and amortization
    903,313       855,745  
     
     
 
   
Net property, plant and equipment
    1,684,746       1,624,394  
Current assets
               
 
Cash and cash equivalents
    126,895       15,683  
 
Cash held on deposit in margin account
          17,903  
 
Accounts receivable, net
    243,719       216,783  
 
Gas stored underground
    90,141       168,765  
 
Other current assets
    18,710       38,863  
     
     
 
   
Total current assets
    479,465       457,997  
Goodwill and intangible assets
    275,844       273,499  
Deferred charges and other assets
    240,477       271,023  
     
     
 
    $ 2,680,532     $ 2,626,913  
     
     
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
               
 
Common stock, no par value (stated at $.005 per share); 100,000,000 shares authorized; issued and outstanding:
               
   
June 30, 2004 — 52,579,303 shares;
               
   
September 30, 2003 — 51,475,785 shares
  $ 263     $ 257  
 
Additional paid-in capital
    762,464       736,180  
 
Retained earnings
    167,535       122,539  
 
Accumulated other comprehensive loss
    (3,416 )     (1,459 )
     
     
 
   
Shareholders’ equity
    926,846       857,517  
Long-term debt
    863,266       863,918  
     
     
 
   
Total capitalization
    1,790,112       1,721,435  
Current liabilities
               
 
Accounts payable and accrued liabilities
    201,123       179,852  
 
Other current liabilities
    210,759       133,957  
 
Short-term debt
          118,595  
 
Current maturities of long-term debt
    5,918       9,345  
     
     
 
   
Total current liabilities
    417,800       441,749  
Deferred income taxes
    227,899       223,350  
Regulatory cost of removal obligation
    105,059       102,371  
Deferred credits and other liabilities
    139,662       138,008  
     
     
 
    $ 2,680,532     $ 2,626,913  
     
     
 

See accompanying notes to condensed consolidated financial statements

1


 

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

                     
Three Months Ended
June 30

2004 2003


(Unaudited)
(In thousands, except
per share data)
Operating revenues
               
 
Utility segment
  $ 256,252     $ 245,998  
 
Natural gas marketing segment
    364,339       374,832  
 
Other nonutility segment
    6,210       3,685  
 
Intersegment eliminations
    (80,743 )     (136,045 )
     
     
 
      546,058       488,470  
Purchased gas cost
               
 
Utility segment
    163,093       161,426  
 
Natural gas marketing segment
    352,708       367,395  
 
Other nonutility segment
    3,150       467  
 
Intersegment eliminations
    (80,385 )     (135,882 )
     
     
 
      438,566       393,406  
     
     
 
Gross profit
    107,492       95,064  
Operating expenses
               
 
Operation and maintenance
    50,467       45,141  
 
Depreciation and amortization
    23,268       23,192  
 
Taxes, other than income
    12,297       12,675  
     
     
 
   
Total operating expenses
    86,032       81,008  
     
     
 
Operating income
    21,460       14,056  
Miscellaneous income
    2,187       686  
Interest charges
    16,011       16,042  
     
     
 
Income (loss) before income taxes
    7,636       (1,300 )
Income tax expense (benefit)
    2,871       (1,099 )
     
     
 
   
Net income (loss)
  $ 4,765     $ (201 )
     
     
 
Per share data
               
 
Basic income (loss) per share
  $ 0.09     $ (0.00 )
     
     
 
 
Diluted income (loss) per share
  $ 0.09     $ (0.00 )
     
     
 
Cash dividends per share
  $ .305     $ .300  
     
     
 
Weighted average shares outstanding:
               
 
Basic
    52,220       45,997  
     
     
 
 
Diluted
    52,617       45,997  
     
     
 

See accompanying notes to condensed consolidated financial statements

2


 

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

                       
Nine Months Ended
June 30

2004 2003


(Unaudited)
(In thousands, except
per share data)
Operating revenues
               
 
Utility segment
  $ 1,425,022     $ 1,342,527  
 
Natural gas marketing segment
    1,255,386       1,338,732  
 
Other nonutility segment
    20,492       16,242  
 
Intersegment eliminations
    (273,741 )     (334,457 )
     
     
 
      2,427,159       2,363,044  
Purchased gas cost
               
 
Utility segment
    1,003,977       934,649  
 
Natural gas marketing segment
    1,214,395       1,325,655  
 
Other nonutility segment
    9,158       1,475  
 
Intersegment eliminations
    (273,042 )     (333,933 )
     
     
 
      1,954,488       1,927,846  
     
     
 
Gross profit
    472,671       435,198  
Operating expenses
               
 
Operation and maintenance
    166,476       151,310  
 
Depreciation and amortization
    69,879       65,273  
 
Taxes, other than income
    45,901       44,057  
     
     
 
     
Total operating expenses
    282,256       260,640  
     
     
 
Operating income
    190,415       174,558  
Miscellaneous income
    7,850       3,321  
Interest charges
    49,506       47,679  
     
     
 
Income before income taxes and cumulative effect of accounting change
    148,759       130,200  
Income tax expense
    56,148       48,303  
     
     
 
Income before cumulative effect of accounting change
    92,611       81,897  
Cumulative effect of accounting change, net of income tax benefit
          (7,773 )
     
     
 
     
Net income
  $ 92,611     $ 74,124  
     
     
 
Per share data
               
 
Basic income per share:
               
   
Income before cumulative effect of accounting change
  $ 1.79     $ 1.83  
   
Cumulative effect of accounting change, net of income tax benefit
          (.17 )
     
     
 
   
Net income
  $ 1.79     $ 1.66  
     
     
 
 
Diluted income per share:
               
   
Income before cumulative effect of accounting change
  $ 1.78     $ 1.82  
   
Cumulative effect of accounting change, net of income tax benefit
          (.17 )
     
     
 
   
Net income
  $ 1.78     $ 1.65  
     
     
 
Cash dividends per share
  $ .915     $ .900  
     
     
 
Weighted average shares outstanding:
               
 
Basic
    51,788       44,679  
     
     
 
 
Diluted
    52,166       44,879  
     
     
 

See accompanying notes to condensed consolidated financial statements

3


 

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

                       
Nine Months Ended
June 30

2004 2003


(Unaudited)
(In thousands)
Cash Flows from Operating Activities
               
 
Net income
  $ 92,611     $ 74,124  
 
Adjustments to reconcile net income to net cash provided by operating activities:
               
   
Cumulative effect of accounting change, net of income tax benefit
          7,773  
   
Gain on sales of assets
    (6,700 )      
   
Depreciation and amortization:
               
     
Charged to depreciation and amortization
    69,879       65,273  
     
Charged to other accounts
    1,270       1,676  
   
Deferred income taxes
    5,750       9,148  
   
Other
    (1,405 )     (5,403 )
   
Net assets/ liabilities from risk management activities
    4,469       (4,200 )
   
Net change in operating assets and liabilities
    193,388       (31,099 )
     
     
 
     
Net cash provided by operating activities
    359,262       117,292  
Cash Flows from Investing Activities
               
 
Capital expenditures
    (129,508 )     (113,637 )
 
Proceeds from sales of assets
    27,919        
 
Retirements of property, plant and equipment, net
    (505 )     315  
 
Acquisitions
    (1,957 )     (74,650 )
     
     
 
     
Net cash used in investing activities
    (104,051 )     (187,972 )
Cash Flows from Financing Activities
               
 
Net decrease in short-term debt
    (118,595 )     (145,091 )
 
Cash dividends paid
    (47,615 )     (39,893 )
 
Repayment of long-term debt
    (9,079 )     (72,333 )
 
Net proceeds from issuance of long-term debt
    5,000       253,267  
 
Issuance of common stock
    26,290       19,336  
 
Repayment of Mississippi Valley Gas debt
          (70,938 )
 
Proceeds from bridge loan
          147,000  
 
Repayment of bridge loan
          (147,000 )
 
Net proceeds from equity offering
          96,826  
     
     
 
     
Net cash provided (used) by financing activities
    (143,999 )     41,174  
     
     
 
Net increase (decrease) in cash and cash equivalents
    111,212       (29,506 )
Cash and cash equivalents at beginning of period
    15,683       46,827  
     
     
 
Cash and cash equivalents at end of period
  $ 126,895     $ 17,321  
     
     
 

See accompanying notes to condensed consolidated financial statements

4


ATMOS ENERGY CORPORATION  

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
June 30, 2004

1.     Nature of Business

      Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. Through our natural gas utility business, we distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public-authority and industrial customers through our six regulated natural gas utility divisions, which cover the following service areas:

 
     
Division Service Area


Atmos Energy Colorado-Kansas Division
  Colorado, Kansas, Missouri (2)
Atmos Energy Kentucky Division
  Kentucky
Atmos Energy Louisiana Division
  Louisiana
Atmos Energy Mid-States Division
  Georgia (2) , Illinois (2) , Iowa (2) , Missouri (2) , Tennessee, Virginia (2)
Atmos Energy Texas Division
  Texas
Mississippi Valley Gas Company Division (1)
  Mississippi


(1)   Acquired in December 2002.
 
(2)   Denotes locations where we have more limited service areas.

      In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the utility divisions operate. Our shared-services division is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas, and Metairie, Louisiana.

      As further described in Note 3, on June 17, 2004, we entered into a definitive agreement with TXU Gas Company (TXU Gas) to acquire the natural gas distribution and pipeline operations of TXU Gas. The acquisition would increase the number of customers we serve in our natural gas utility business to over 3.1 million and make us one of the largest publicly-traded companies in the United States whose primary business is the transmission and distribution of natural gas and the provision of related services. It would also make us one of the largest intrastate pipeline operators in Texas.

      Our nonutility businesses are organized under Atmos Energy Holdings, Inc. (AEH), and have operations in 18 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly-owned subsidiaries, Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, LLC and Trans Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing, L.L.C., which was renamed Atmos Energy Marketing, LLC (AEM).

      AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers, primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative instruments.

      Our other nonutility businesses consist primarily of the operations of Atmos Pipeline and Storage, L.L.C., Atmos Power Systems, Inc. and Atmos Energy Services, LLC (AES), all of which are wholly-owned by

5


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

AEH. Through Atmos Pipeline and Storage, L.L.C., we own or have an interest in underground storage fields in Kentucky and Louisiana. Through Atmos Pipeline and Storage, L.L.C. we provide storage services to our customers for a fee, as well as capture pricing arbitrage through the use of derivatives. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants. Through AES, we provide natural gas management services. Prior to the third quarter of fiscal 2004, this entity conducted limited operations. However, beginning April 1, 2004, AES began providing natural gas supply management services to our utility operations in a limited number of states. We expect to expand these services to substantially all of our utility service areas before the end of fiscal 2004.

      Prior to January 20, 2004, United Cities Propane Gas, Inc., a wholly owned subsidiary of AEH, owned an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with three other utility companies. Through our ownership in USP, we owned an approximate 5 percent indirect interest in Heritage Propane Partners, L.P. On January 20, 2004, we and our partners in USP completed the sale of our general and limited partnership interests in USP for $130.0 million. We received cash proceeds of approximately $24.7 million and recorded a $4.9 million pretax book gain in the second quarter of fiscal 2004. In June 2004, we received cash proceeds of $1.9 million attributable to the final sale of all remaining Heritage Propane Partners, L.P. limited partnership units formerly owned by USP and recognized a $1.0 million pretax book gain. With these transactions, we no longer have an interest in the propane industry.

 
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 and notes are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation (“Atmos” or “the Company”) in its Annual Report on Form 10-K for the fiscal year ended September 30, 2003. Because of seasonal and other factors, the results of operations for the three- and nine-month periods ended June 30, 2004, are not indicative of expected results of operations for the fiscal year ending September 30, 2004.

 
Significant Accounting Policies

      Our accounting policies are described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2003. As described in our Annual Report on Form 10-K, our utility depreciation rates approved by the various regulatory commissions included a component that allowed us to recover the cost of removing our assets. Historically, we recorded the associated obligation as a component of accumulated depreciation. This classification was consistent with others in the industry. Beginning in the second quarter of fiscal 2004, we are classifying our regulatory cost of removal obligation as a regulatory liability on the balance sheet. Additionally, for purposes of our September 30, 2003 information presented in this report, we reclassified from accumulated depreciation to regulatory liabilities a total of $108.4 million in regulatory cost of removal accruals at September 30, 2003, of which $102.4 million was a long-term regulatory liability. These reclassifications do not impact our financial position, results of operations, cash flows or ability to satisfy our financial covenants contained in our various credit agreements as of June 30, 2004 and September 30, 2003.

      Effective April 1, 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales. As a result, we ceased marking the fixed-price forward contracts to market. We have designated the offsetting derivative contracts as cash flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on these open derivative contracts are now recorded as a component of accumulated other comprehensive income and are recognized in earnings when the hedged volumes are sold.

6


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

This designation is expected to partially reduce the amount of volatility in our condensed consolidated income statement and better reflect the economics of this type of transaction.

 
Stock-based Compensation Plans

      We have two stock-based compensation plans that provide for the granting of incentive stock options, nonqualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to officers and key employees: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. Nonemployee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.

      As permitted by Statement of Financial Accounting Standard (SFAS) 123, Accounting for Stock-Based Compensation, we account for these plans under the intrinsic-value method described in Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. Under this method, no compensation cost for stock options is recognized for stock-option awards granted at or above fair-market value.

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

      Had compensation expense for our stock options issued under the Long-Term Incentive Plan been recognized based on the fair value on the grant date under the methodology prescribed by SFAS 123, our net income (loss) and earnings (loss) per share for the three months and nine months ended June 30, 2004 and 2003 would have been impacted as shown in the following table:

                                   
 
Three Months Nine Months Ended
Ended June 30 June 30


2004 2003 2004 2003




(In thousands, except per share data)
Net income (loss) — as reported
  $ 4,765     $ (201 )   $ 92,611     $ 74,124  
Restricted stock compensation expense included in income, net of tax
    384       14       580       187  
Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of taxes
    (651 )     (271 )     (1,428 )     (884 )
     
     
     
     
 
Net income (loss) — pro forma
  $ 4,498     $ (458 )   $ 91,763     $ 73,427  
     
     
     
     
 
Earnings per share:
                               
 
Basic earnings per share — as reported
  $ 0.09     $ (0.00 )   $ 1.79     $ 1.66  
     
     
     
     
 
 
Basic earnings per share — pro forma
  $ 0.09     $ (0.01 )   $ 1.77     $ 1.64  
     
     
     
     
 
 
Diluted earnings per share — as reported
  $ 0.09     $ (0.00 )   $ 1.78     $ 1.65  
     
     
     
     
 
 
Diluted earnings per share — pro forma
  $ 0.09     $ (0.01 )   $ 1.76     $ 1.64  
     
     
     
     
 

      No option grants have occurred under the Long-Term Stock Plan for the Mid-States Division since that entity was acquired in 1997. Due to the limited activities of that plan, the pro forma effect of applying SFAS 123 would have had less than a $0.01 per diluted share effect on earnings per share for the three and

7


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nine months ended June 30, 2004 and 2003, or $160 and $416 for the three months ended June 30, 2004 and 2003 and $922 and $1,922 for the nine months ended June 30, 2004 and 2003.

 
Regulatory Assets and Liabilities

      We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of June 30, 2004 and September 30, 2003 included the following:

                   
 
June 30, September 30,
2004 2003


(In thousands)
Regulatory assets:
               
 
Deferred gas costs
  $     $ 308  
 
Merger and integration costs, net
    17,536       23,380  
 
Deferred MVG operating expenses
    5,806       4,645  
 
Environmental costs
    4,056       4,057  
 
Other
    3,511       2,509  
     
     
 
    $ 30,909     $ 34,899  
     
     
 
Regulatory liabilities:
               
 
Regulatory cost of removal obligation
  $ 110,363     $ 108,405  
 
Deferred gas costs
    33,523        
 
Deferred income taxes, net
    1,883       1,883  
     
     
 
    $ 145,769     $ 110,288  
     
     
 

      Currently authorized rates do not include a return on our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are amortized on a straight-line basis over estimated useful lives ranging from 7 to 20 years. These costs will have been substantially amortized by December 2004. Certain environmental costs have been deferred to future rate filings in accordance with rulings received from various regulatory commissions.

8


 

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Comprehensive Income

      The following table presents the components of comprehensive income, net of related tax, for the three- and nine-month periods ended June 30, 2004 and 2003:

                                 
Three Months Ended Nine Months Ended
June 30 June 30


2004 2003 2004 2003




(In thousands)
Net income (loss)
  $ 4,765     $ (201 )   $ 92,611     $ 74,124  
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(270) and $808 for the three months ended June 30, 2004 and 2003 and net of tax expense of $654 and $319 for the nine months ended June 30, 2004 and 2003
    (441 )     1,318       1,067       519  
Unrealized gains on commodity hedging transactions, net of tax expense of $829 for the three and nine months ended June 30, 2004
    1,353             1,353        
Unrealized losses on interest rate hedging transactions, net of tax benefit of $2,684 for the three and nine months ended June 30, 2004
    (4,377 )           (4,377 )      
     
     
     
     
 
Comprehensive income
  $ 1,300     $ 1,117     $ 90,654     $ 74,643  
     
     
     
     
 

      Accumulated other comprehensive income consists of unrealized holding gains and losses associated with certain available-for-sale investments and unrealized gains and losses associated with commodity and interest rate hedging transactions. In connection with the pending acquisition of the TXU Gas operations, the Company entered into Treasury interest rate locks associated with $675.0 million of long-term debt to be issued in connection with the acquisition (see Note 5).

 
Recent Accounting Developments

      In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when to consolidate and which business enterprises should consolidate the VIE. The adoption of this interpretation did not have a material impact on our financial position, results of operations or net cash flows because we are not currently a beneficiary of a VIE.

      During 2003, the Emerging Issues Task Force (the Task Force) added to its agenda Emerging Issues Task Force (EITF) Issue 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, to address the meaning of “other-than-temporary” impairment and its application to certain investments carried at cost. In November 2003, the Task Force developed new disclosure requirements concerning unrealized losses on available-for-sale debt and equity securities accounted for under SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, which will be applicable to us beginning with our fiscal 2004 Annual Report on Form 10-K.

      In December 2003, the FASB issued SFAS 132 (revised), Employers’ Disclosures about Pensions and Other Postretirement Benefits. These revisions require additional disclosures in annual reports on Form 10-K concerning the assets, obligations, cash flows and net periodic-benefit cost of defined-benefit pension plans and other defined-benefit postretirement plans. Additionally, the statement now requires interim-period disclosures regarding net periodic pension cost and employer contributions. The annual disclosures will become fully

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ATMOS ENERGY CORPORATION

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effective for fiscal years ending after June 15, 2004, and the interim-period disclosures were effective for interim periods beginning after December 15, 2003. We have adopted the interim-period disclosures, which are contained in Note 8, and will adopt the annual disclosures beginning with our fiscal 2004 Annual Report on Form 10-K.

      In January 2004, the FASB issued FASB Staff Position FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which permits a plan sponsor to defer recognizing the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) in accounting for its plan under SFAS 106 and in providing disclosures related to the plan required by SFAS 132 (revised). We elected to recognize the provisions of the Act, beginning with the second quarter of fiscal 2004, which reduced our accumulated postretirement benefit obligation and our net postretirement benefit obligation costs by $4.1 million based upon calculations prepared by our independent actuaries. The total income statement impact for fiscal 2004 will approximate $2.3 million, as a portion of this benefit will be capitalized.

3.     Acquisitions

 
TXU Gas Company

      On June 17, 2004, we entered into a definitive agreement with TXU Gas Company (TXU Gas) to acquire the natural gas distribution and pipeline operations of TXU Gas.

      The TXU Gas operations we are acquiring are regulated businesses engaged in the purchase, transmission, storage, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. TXU Gas provides gas distribution services to over 1.4 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. TXU Gas owns and operates a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas. The acquisition would increase the number of customers we serve in our distribution business to over 3.1 million.

      The purchase price, excluding transaction costs, for the acquisition is $1.925 billion, which is payable in cash. The price is subject to adjustment if at the time of closing the working capital of TXU Gas is less or more than approximately $121 million. The price is also subject to increase by the amount of any capital expenditures made by TXU Gas prior to closing that exceed its budgeted amounts. We are not assuming any indebtedness in the transaction. TXU Gas has agreed to repay or redeem all of its existing indebtedness and its preferred stock and to retain or pay certain other liabilities under the terms of the acquisition agreement.

      We have received a commitment from a third party financial institution, subject to customary conditions, to provide a senior unsecured credit facility in the amount of $1.925 billion to finance, or backstop the issuance of commercial paper to finance, this acquisition. The bridge financing facility will mature 364 days after the closing date of the acquisition. The commitment is subject to the absence of a material adverse effect on our business and assets, after giving effect to the acquisition, the absence of any new adverse information affecting us, TXU Gas or the acquisition that would materially impair the syndication of the bridge financing facility and other specified conditions. The amount of the bridge financing facility will be reduced to the extent we obtain acquisition financing prior to the closing of the acquisition. As further described in Note 12, in July 2004, we sold 9,939,393 common shares, which generated net proceeds of $236.2 million before legal, accounting and other offering costs, that will be used to reduce the amount we intend to borrow under this facility. We intend to seek long-term debt and additional common equity financings to refinance the bridge financing facility.

      We expect the acquisition to close by the end of the calendar year 2004; however, this acquisition is subject to the satisfaction of several conditions, including regulatory approvals in three states and clearance by antitrust authorities. The 30-day waiting period under the Hart-Scott-Rodino Act expired August 2, 2004 with

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

no inquiries from the Justice Department or Federal Trade Commission. In addition, the Virginia State Corporation Commission issued an order on August 6, 2004 approving the short-term debt financing for the acquisition, while regulatory approvals from the state regulatory commissions in Iowa and Missouri are pending. If we have not obtained our three state regulatory approvals by December 31, 2004 and the other conditions to closing have been satisfied, TXU Gas may terminate the agreement and require us to pay $15 million in full satisfaction of our obligations under the agreement. In addition, we or TXU Gas may terminate the agreement if the applicable closing conditions are not satisfied or waived by December 31, 2004. The closing date may be extended for up to 90 days to the extent required for TXU Gas to repair any material casualty loss incurred before closing.

 
ComFurT Gas Inc.

      Effective March 1, 2004, we completed the acquisition of the natural gas distribution assets of ComFurT Gas Inc., a privately held natural gas utility and propane distributor based in Buena Vista, Colorado, for approximately $2.0 million in cash. This company served approximately 1,800 natural gas utility customers. The acquisition enabled us to expand our contiguous service area in our Colorado-Kansas division. Unaudited pro forma results of the Company and ComFurT have not been presented as the acquisition was not material to our financial position or results of operations.

 
4. Goodwill and Intangible Assets

      Goodwill and intangible assets are comprised of the following as of June 30, 2004 and September 30, 2003.

                 
 
June 30, September 30,
2004 2003


(In thousands)
Goodwill
  $ 271,467     $ 268,469  
Intangible assets
    4,377       5,030  
     
     
 
Total
  $ 275,844     $ 273,499  
     
     
 

      The following presents our goodwill balance allocated by segment and changes in our balance for the nine months ended June 30, 2004:

                                 
 
Natural Gas Other
Utility Marketing Nonutility
Segment Segment Segment Total




(In thousands)
Balance as of September 30, 2003
  $ 233,741     $ 22,600     $ 12,128     $ 268,469  
Acquisition
    1,250                   1,250  
Refinements to purchase price
    2,644       (896 )           1,748  
     
     
     
     
 
Balance as of June 30, 2004
  $ 237,635     $ 21,704     $ 12,128     $ 271,467  
     
     
     
     
 

      During the second quarter of fiscal 2004, we completed our annual goodwill impairment assessment. Based upon the assessment performed, our goodwill was not considered to be impaired.

 
5. Derivative Instruments and Hedging Activities

      We conduct risk management activities through both our utility and natural gas marketing segments. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent 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

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

      The following table shows the fair values of our risk management assets and liabilities by segment at June 30, 2004 and September 30, 2003:

                         
 
Natural Gas
Utility Marketing Total



(In thousands)
June 30, 2004:
                       
Assets from risk management activities, current
  $ 789     $ 8,764     $ 9,553  
Assets from risk management activities, noncurrent
          732       732  
Liabilities from risk management activities, current
    (8,227 )     (7,403 )     (15,630 )
Liabilities from risk management activities, noncurrent
          (1,598 )     (1,598 )
     
     
     
 
Net assets (liabilities)
  $ (7,438 )   $ 495     $ (6,943 )
     
     
     
 
September 30, 2003:
                       
Assets from risk management activities, current
  $ 202     $ 22,057     $ 22,259  
Assets from risk management activities, noncurrent
          1,699       1,699  
Liabilities from risk management activities, current
    (7,941 )     (12,849 )     (20,790 )
Liabilities from risk management activities, noncurrent
          (763 )     (763 )
     
     
     
 
Net assets (liabilities)
  $ (7,739 )   $ 10,144     $ 2,405  
     
     
     
 
 
Utility Hedging Activities

      We use a combination of storage, fixed-price physical contracts and fixed-price financial contracts to protect us and our customers against unusually large winter-period gas price increases. For the 2003-2004 heating season, we hedged between 50 and 55 percent of our winter flowing gas requirements at a weighted average cost of approximately $5.36 per MCF. These derivative financial instruments are marked to market pursuant to SFAS 133, Accounting for Derivative Financial Instruments and Hedging Activities. Because these costs will ultimately be recovered through our rates, current-period changes in the assets and liabilities from risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71 and recognized in purchased gas cost in the income statement when the related costs are recovered through our rates. Accordingly, there is no earnings impact as a result of the use of these financial instruments in our utility segment.

      In June 2001, we purchased a three-year weather-insurance policy with an option to cancel the third year of coverage. The insurance covered our Texas and Louisiana operations to protect against weather that was at least 7 percent warmer than normal for the entire heating season of October through March, beginning with the 2001-2002 heating season. The prepaid cost of the three-year policy was $13.2 million and was amortized over the appropriate heating seasons based on heating degree days. In the third quarter of fiscal 2003, we cancelled this policy, primarily as a result of rate relief in Louisiana and prospects for weather normalization adjustments in Texas. During the three months and nine months ended June 30, 2003, we recognized amortization expense of $0.6 million and $5.0 million. However, we did not collect under this policy because weather was not at least 7 percent warmer than normal.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Nonutility Hedging Activities

      Our natural gas marketing hedging 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 storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. The use of these contracts is subject to our risk management policies, which are monitored for compliance on a daily basis.

      We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase or sell physical natural gas and then sell or purchase financial contracts at a price sufficient to cover our carrying costs and provide a gross profit margin. Through the use of transportation and storage services and derivatives, we are able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

      Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market on a monthly basis using the inside FERC (iFERC) price at the end of each month. Changes in fair value are recognized as unrealized gains and losses in the period of change. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenue and the carrying value of the inventory as an associated purchased gas cost in our condensed consolidated statement of income when we sell the gas and deliver it out of the storage facility.

      Derivatives associated with our storage gas contracts 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 difference in the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

      Similar to our inventory position, we attempt to mitigate substantially all of the commodity price risk associated with our fixed-price contracts with minimum volume requirements through the use of various offsetting derivatives. Prior to April 1, 2004, these derivatives were not designated as hedges under SFAS 133 because they naturally locked in the economic gross profit margin at the time we enter into the contract. The fixed-price forward and offsetting derivative contracts were marked to market each month with changes in fair value recognized as unrealized gains and losses in our condensed consolidated statement of income. The unrealized gains and losses are realized in the period in which we fulfill the requirements of the fixed-price contract and the derivatives are settled. To the extent that the unrealized gains and losses of the fixed-price forward contracts and the offsetting derivatives do not offset exactly, our earnings will experience some volatility. At delivery, the gains and losses on the fixed-price contracts were offset by gains and losses on the derivatives, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

      Effective April 1, 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales. As a result, we ceased marking the fixed-price forward contracts to market. We have designated the offsetting derivative contracts as cash flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on these open derivative contracts are now recorded as a component of accumulated other comprehensive income and are recognized in earnings when the hedged volumes are sold.

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This designation is expected to partially reduce the amount of volatility in our condensed consolidated income statement and more accurately reflect the economics of this type of transaction.

      For the three and nine months ended June 30, 2004, the increase in the deferred hedging gain in accumulated other comprehensive income was attributable to the initiation of cash flow hedge accounting treatment described above and increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, partially offset by the reclassification of $2.6 million in net deferred hedge gains to net income as derivatives matured according to their terms. The net deferred hedge losses associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. The deferred hedging gain as of June 30, 2004 is expected to be substantially recognized within the next six months.

      Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on June 30, 2004, AEH had a net open position (including existing storage) of 0.4 Bcf.

      On January 1, 2003, we recorded a cumulative effect of a change in accounting principle to reflect a change in the way we account for our storage and transportation contracts. Previously we accounted for those contracts under EITF 98-10, Accounting for Energy Trading and Risk Management Activities , which required us to record estimated future gains on our storage and transportation contracts at the time we entered into the contracts and to mark those contracts to market value each month. Effective January 1, 2003, we no longer marked those contracts to market. As a result, we expensed $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle.

 
Treasury Activities

      In June 2004, we entered into two Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the anticipated issuance of $675 million of long-term debt. This long-term debt will be used to refinance a portion of the 364-day bridge financing facility that will be used to finance the TXU Gas acquisition on an interim basis, as described in Note 3. The Treasury locks are scheduled to terminate on December 31, 2004; however, we have the ability to terminate the locks at our discretion within 60 days of December 31, 2004.

      We have designated these Treasury locks as cash flow hedges of an anticipated transaction. Accordingly, to the extent effective, unrealized gains and losses associated with the Treasury locks will be recorded as a component of accumulated other comprehensive income. Unrealized gains will be recorded when interest rates increase and unrealized losses will be recorded when interest rates decline. Upon termination of the Treasury lock agreements, the unrealized gain or loss will be recognized over the life of the related financing arrangement. Any gains or losses arising from ineffectiveness will be recognized into earnings as incurred. At June 30, 2004, we recorded deferred hedging losses of $4.4 million, net of tax, as a component of accumulated other comprehensive income related to these Treasury locks due to a decline in the 5 and 10 year Treasury rates between the inception of the Treasury locks and June 30, 2004.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
6. Debt
 
 
Long-Term Debt

      Long-term debt at June 30, 2004 and September 30, 2003 consisted of the following:

                     
June 30, September 30,
2004 2003


(In thousands)
Unsecured 10% Notes, due 2011
  $ 2,303     $ 2,303  
Unsecured 7.375% Senior Notes, due 2011
    350,000       350,000  
Unsecured 5.125% Senior Notes, due 2013
    250,000       250,000  
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 J, 9.40% due 2021
    17,000       17,000  
 
Series P, 10.43% due 2013
    11,250       13,750  
 
Series Q, 9.75% due 2020
    16,000       17,000  
 
Series R, 11.32% due 2004
          2,160  
 
Series T, 9.32% due 2021
    18,000       18,000  
 
Series U, 8.77% due 2022
    20,000       20,000  
 
Series V, 7.50% due 2007
    4,167       6,733  
Rental property, propane and other term notes due in installments through 2013
    10,464       6,317  
     
     
 
   
Total long-term debt
    869,184       873,263  
Less current maturities
    (5,918 )     (9,345 )
     
     
 
    $ 863,266     $ 863,918  
     
     
 

      Most of the First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1988, may not exceed the sum of accumulated net income for periods after December 31, 1988, plus $15.0 million. At June 30, 2004, approximately $129.1 million of retained earnings were unrestricted with respect to the payment of dividends. We were in compliance with all of our debt covenants as of June 30, 2004.

 
Short-Term Debt

      At June 30, 2004, there were no short-term amounts outstanding under our commercial paper program or bank credit facilities. At September 30, 2003, short-term debt consisted of $118.6 million of commercial paper. No amounts were outstanding under our bank credit facilities at September 30, 2003.

      Credit Facilities

      We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the bank. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

 
Committed Credit Facilities

      We have two short-term committed credit facilities totaling $368.0 million, one of which is an unsecured facility for $350.0 million that bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our commercial paper program. In July 2004, we renewed this facility on substantially the same terms as those of the existing facility, and it will expire in January 2005. We expect that this facility will be resized and renewed following the closing of the acquisition of the TXU Gas operations. We have a second unsecured facility in place for $18.0 million that bears interest at the Fed Funds rate plus 0.5 percent and is used for working-capital purposes. At June 30, 2004, there were no amounts outstanding under these credit facilities. These credit facilities are negotiated at least annually. On April 1, 2004, the $18.0 million working-capital credit facility was renewed for an additional 12 months on terms substantially similar to those of the prior facility.

      The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our $350.0 million credit facility to maintain a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2004, our total-debt-to-total-capitalization ratio, as defined, was 50 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under our $350.0 million credit facility are subject to adjustment depending upon our credit ratings. We and our lead bank plan to amend this facility’s terms prior to closing the TXU Gas acquisition to accommodate the expected increase in our debt to capital ratio that will result from the acquisition.

 
Uncommitted Credit Facilities

      AEM has a $250.0 million uncommitted-demand working capital credit facility that bears interest at the Eurodollar rate plus 2.5 percent and expires on March 31, 2005. Effective October 1, 2003, with the reorganization of our natural gas marketing segment, AEM became the borrower under the credit facility, and AEH became the sole guarantor of the facility. At June 30, 2004, no amounts were outstanding under this credit facility. AEM letters of credit totaling $74.2 million reduced the amount available in accordance with the terms of the facility. 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 $57.8 million at June 30, 2004.

      We also have an unsecured short-term uncommitted credit line for $25.0 million that is used for working-capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at June 30, 2004, but Atmos Energy Corporation (AEC) letters of credit reduced the amount available by $3.5 million. This uncommitted line is renewed or renegotiated at least annually with varying terms, and we pay no fee for the availability of the line. Borrowings under this line are made on a when- and as-available basis at the discretion of the bank.

      In addition, AEM has a $100.0 million intercompany credit facility with AEC through AEH for its nonutility business which bears interest at the Eurodollar rate plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $250.0 million uncommitted-demand credit facility described above. This facility is used to supplement AEM’s $250.0 million credit facility. This credit facility was renewed effective July 1, 2004 on substantially the same terms as those of the existing facility and has been approved by our state regulators through December 31, 2004. However, there is no assurance that our

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

regulators will approve our use of this credit facility after that time. At June 30, 2004, $20.0 million was outstanding under this facility.

 
7. Earnings Per Share

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

                                   
 
For the Three Months For the Nine Months
Ended June 30 Ended June 30


2004 2003 2004 2003




(In thousands, except per share amounts)
Income (loss) before cumulative effect of accounting change
  $ 4,765     $ (201 )   $ 92,611     $ 81,897  
Cumulative effect of accounting change, net of income tax benefit
                      (7,773 )
     
     
     
     
 
Net income (loss)
  $ 4,765     $ (201 )   $ 92,611     $ 74,124  
     
     
     
     
 
Denominator for basic income per share — weighted average common shares
    52,220       45,997       51,788       44,679  
Effect of dilutive securities:
                               
 
Restricted stock
    258             258       122  
 
Stock options
    139             120       78  
     
     
     
     
 
Denominator for diluted income per share — weighted average common shares
    52,617       45,997       52,166       44,879  
     
     
     
     
 
Income (loss) per share — basic:
                               
 
Before cumulative effect of accounting change
  $ 0.09     $ (0.00 )   $ 1.79     $ 1.83  
 
Cumulative effect of accounting change, net of income tax benefit
                      (.17 )
     
     
     
     
 
 
Net income (loss) per share
  $ 0.09     $ (0.00 )   $ 1.79     $ 1.66  
     
     
     
     
 
Income (loss) per share — diluted:
                               
 
Before cumulative effect of accounting change
  $ 0.09     $ (0.00 )   $ 1.78     $ 1.82  
 
Cumulative effect of accounting change, net of income tax benefit
                      (.17 )
     
     
     
     
 
Net income (loss) per share
  $ 0.09     $ (0.00 )   $ 1.78     $ 1.65  
     
     
     
     
 

      There were approximately 84,000 options and approximately 122,000 shares of restricted stock as of June 30, 2003 that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2003 as their inclusion in the computation would be anti-dilutive.

      There were no options excluded from the computation of diluted earnings per share for the three months ended June 30, 2004 as the exercise price for all options was less than the average market price of the common stock during that period. There were 577,500 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended June 30, 2003 as their exercise price was greater than the average market price of the common stock during that period.

      There were 3,000 and 577,500 out-of-the-money options excluded from the computation of diluted earnings per share for the nine months ended June 30, 2004 and 2003 as their exercise price was greater than the average market price of the common stock during that period.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
8. 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 months ended June 30, 2004 and 2003 are presented below. The 2004 amounts reflect the impact of adopting the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) beginning in the second quarter of fiscal 2004.

                                     
 
Pension Benefits Other Benefits


2004 2003 2004 2003




(In thousands)
Components of net periodic pension cost:
                               
 
Service cost
  $ 2,433     $ 2,060     $ 1,405     $ 1,476  
 
Interest cost
    6,004       5,834       1,751       2,269  
 
Expected return on assets
    (7,524 )     (5,988 )     (396 )     (253 )
 
Amortization of transition asset
    24       24       378       378  
 
Amortization of prior service cost
    (2 )     35       96       92  
 
Amortization of actuarial loss
    2,018       632             444  
     
     
     
     
 
   
Net periodic pension cost
  $ 2,953     $ 2,597     $ 3,234     $ 4,406  
     
     
     
     
 

      The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the nine months ended June 30, 2004 and 2003 are as follows:

                                     
 
Pension Benefits Other Benefits


2004 2003 2004 2003




(In thousands)
Components of net periodic pension cost:
                               
 
Service cost
  $ 7,299     $ 6,180     $ 4,535     $ 4,428  
 
Interest cost
    18,012       17,502       5,605       6,807  
 
Expected return on assets
    (22,572 )     (17,964 )     (1,127 )     (759 )
 
Amortization of transition asset
    72       72       1,134       1,134  
 
Amortization of prior service cost
    (6 )     105       288       276  
 
Amortization of actuarial loss
    6,054       1,896       635       1,332  
     
     
     
     
 
   
Net periodic pension cost
  $ 8,859     $ 7,791     $ 11,070     $ 13,218  
     
     
     
     
 

      A portion of these costs is capitalized into our utility rate base, as these costs are recoverable through our gas utility rates. Costs that are not capitalized are recorded as a component of operating expense.

      The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2004 and 2003 are as follows:

                                 
 
Pension Benefits Other Benefits


2004 2003 2004 2003




Discount rate
    6.00%       6.00%       6.00%       6.00%  
Rate of compensation increase
    4.00%       4.00%       4.00%       4.00%  
Expected return on plan assets
    9.00%       9.00%       5.30%       5.30%  

      In our Annual Report on Form 10-K for the year ended September 30, 2003, we disclosed that anticipated additional voluntary contributions ranging from $0 to $15 million during fiscal 2004 may be necessary to keep the Atmos Energy Corporation Pension Account Plan (the Pension Account Plan) 100 percent funded on an accumulated benefit obligation (ABO) basis. We did not contribute to our pension

18


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

plan during the nine months ended June 30, 2004 and we do not anticipate voluntarily contributing to the Pension Account Plan during the remainder of fiscal 2004.

 
9. Commitments and Contingencies
 
Litigation
 
Colorado-Kansas Division

      On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto against more than 200 companies in the natural gas industry, including us and our Colorado-Kansas Division. The plaintiffs, who purport to represent a class consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, allege that the defendants have underpaid royalties on gas taken from wells situated on nonfederal and non-Indian lands throughout the United States and offshore waters, predicated upon allegations that the defendants’ gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. On April 10, 2000, this case was consolidated for pretrial proceedings with other similar pending litigation in federal court in Wyoming in which we are also a defendant, along with more than 200 other defendants, in the case of In Re Natural Gas Royalties Qui Tam Litigation. In January 2001, the federal court elected to remand this case to the Kansas state court. A reconsideration of remand was filed, but it was denied. The state court now has jurisdiction over this proceeding and has issued a preliminary case management order. On April 10, 2003, the court denied the plaintiffs’ motion to certify this proceeding as a class action, which ruling was appealed by the plaintiffs. The court did allow the plaintiffs to file an amended complaint, which is somewhat narrower in scope than the original complaint. There have since been no material developments in this case. We continue to believe that the plaintiffs’ claims are lacking in merit, and we intend to continue to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

 
Texas Division

      On February 13, 2002, a suit was filed in the 287th District Court of Parmer County, Texas, by Anderson Brothers, a Partnership, against Atmos Energy Corporation, et al. The plaintiffs’ claims arise out of an alleged breach of contract by us and by a number of our divisions and subsidiaries concerning the sale of natural gas used in irrigation activities since 1998 and an alleged violation of the Texas Agricultural Gas Users Act of 1985. We have reached a tentative settlement with the plaintiffs’ attorneys in this case. A fairness hearing will be held on the proposed settlement agreement on August 24, 2004. The settlement agreement must be approved by the court and then by the plaintiffs as a class, which is expected by the end of October 2004. We believe the final outcome of this litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      We are a plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc., and ONEOK Energy Marketing and Trading Company II, filed in December 2001, pending in the District Court of Lubbock County, Texas, 72nd Judicial District. In this case, we are seeking to collect our receivable related to approximately 5.0 Bcf of natural gas that we believe was not delivered. We have settled a portion of our claims with the parties and will continue to pursue recovery of the remaining claims, which we believe are fully recoverable. We are proceeding with discovery in this case, which has been set for trial in 2005.

19


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
United Cities Propane Gas, Inc.

      United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a party to an action filed in June 2000 that is pending in the Circuit Court of Sevier County, Tennessee. The plaintiffs’ claims arise out of injuries alleged to have been caused by a low-level propane explosion. The plaintiffs seek to recover damages of $13.0 million. Discovery activities continue in this case. We have denied any liability, and we intend to vigorously defend against the plaintiffs’ claims. This case has been set for trial on November 1, 2004. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

      We are a party to other litigation and claims that arise in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims will not have a material adverse effect on our financial condition, results of operations or net cash flows.

 
Environmental Matters
 
Manufactured Gas Plant Sites

      We are the owner or previous owner of manufactured gas plant sites in Johnson City and Bristol, Tennessee, and Hannibal, Missouri, which were used to supply gas prior to the availability of natural gas. The gas manufacturing process resulted in certain byproducts and residual materials, including coal tar. The manufacturing process used by our predecessors was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, we may be responsible for response actions with respect to such materials if response actions are necessary.

      United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of fiscal 1997, which we continued through June 30, 2004. The investigative phase of the work at the site has been completed, and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We have completed a risk assessment report that has been approved by the TDEC. Finally, we have completed a feasibility study for this site, which was submitted to the TDEC in October 2003. The feasibility study recommends a remedial action that will limit the use of and access to the impacted soil, cap the site with the addition of a clay fill and geosynthetic liner, and groundwater monitoring for a period of up to 30 years. The estimated cost of the proposed remedial action is $1.5 million, which is comprised primarily of operating and maintenance costs that would be associated with a groundwater monitoring project. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements.

      In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site, which we completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site, and we have proposed performing a focused removal action to remove any such residuals. The TDEC has requested that the focused removal action be conducted pursuant to a voluntary agreement. On April 13, 2004, we entered into a voluntary consent agreement with the TDEC for the performance of the removal action and anticipate completing such removal action later this year.

      On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources to address the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action and a subsequent site evaluation and to reimburse the response costs incurred by the

20


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site-evaluation field work was conducted in August 1999. A risk assessment for the site has been approved by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site-use limitations, including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water. In addition, we intend to grade the site and install a geosynthetic liner over the surface of the site by the end of calendar 2004.

      In 1995, United Cities Gas Company entered into an agreement with a third party to resolve its share of the costs of additional investigations and environmental-response actions for soil contamination at a former manufactured gas plant in Keokuk, Iowa. However, the extent of groundwater contamination at the site, if any, which is not covered by the agreement, has yet to be determined.

      As of June 30, 2004, we had incurred costs of approximately $1.7 million for the investigations of the Johnson City and Bristol, Tennessee, and Hannibal, Missouri, sites and had a remaining accrual relating to these sites of $0.2 million, which is recorded as a component of other current liabilities.

      We are a party to other environmental matters and claims that arise out of our ordinary business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows because we believe that the expenditures related to such response actions will be recovered through rates, shared with other parties or adequately covered by insurance.

 
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, 2004, AEM is committed to purchase 48.8 Bcf within one year and 1.1 Bcf within one to three years under indexed contracts. AEM is committed to purchase 0.6 Bcf within one year under fixed-price contracts, with prices ranging from $4.08 to $6.47. Purchases under these contracts totaled $283.5 million and $320.0 million for the three months ended June 30, 2004 and 2003 and $981.5 and $1,118.6 million for the nine months ended June 30, 2004 and 2003.

      Our utility segment maintains supply contracts with several vendors, generally for 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.

 
Other

      During fiscal 2003, the Internal Revenue Service initiated a routine examination of our fiscal 1999, 2000 and 2001 tax returns. We believe all material tax items have been accrued related to the years under audit.

 
10. Concentration of Credit Risk

      Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the utility segment is mitigated by the large number of individual customers and diversity in customer base. Due to minimal receivables, the credit risk for our other nonutility segment is not significant.

21


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      This diversification in AEM’s customers helps mitigate its credit exposure. AEM maintains credit policies with respect to its counterparties that it believes minimizes overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. AEM also monitors the financial condition of existing counterparties on an ongoing basis. Customers not meeting minimum standards are required to provide adequate assurance of financial performance.

      AEM maintains a provision for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of counterparty nonperformance.

      AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable, (2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by the credit department, but are primarily based on external ratings provided by Moody’s Investor Service Inc. and/or Standard & Poor’s Rating Service, a Division of the McGraw-Hill Companies, Inc. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrials and commercials is non-investment grade. The table below shows the percentages related to the investment ratings as of June 30, 2004 and September 30, 2003. As indicated below, a majority of AEM’s customers are rated as investment grade.

                   
 
June 30, September 30,
2004 2003


Investment grade
    53%       59%  
Non-investment grade
    47%       41%  
     
     
 
 
Total
    100%       100%  
     
     
 

      The following table presents our derivative counterparty credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of June 30, 2004. Investment grade counterparties have minimum credit ratings of BBB-, assigned by Standard & Poor’s Rating Group; or Baa3, assigned by Moody’s Investor Service. Non-investment grade counterparties are composed of counterparties that are below investment grade or that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is composed of numerous smaller counterparties, none of which is individually significant.

                                 
 
At June 30, 2004

Natural Gas Other
Utility Marketing Nonutility
Segment (1) Segment Segment Consolidated




(In thousands)
Investment grade counterparties
  $ 789     $ 9,147     $     $ 9,936  
Non-investment grade counterparties
          349             349  
     
     
     
     
 
    $ 789     $ 9,496     $     $ 10,285  
     
     
     
     
 


(1)   Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers.

22


ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
11. Segment Information

      Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. We distribute natural gas through sales and transportation arrangements to approximately 1.7 million residential, commercial, public-authority and industrial customers through our six regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

      Through our nonutility businesses, we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. Finally, we construct electric power-generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers.

      Our operations are divided into three segments:

  •  The utility segment, which includes our regulated natural gas distribution and sales operations,
 
  •  The natural gas marketing segment, which includes a variety of natural gas management services and
 
  •  The other nonutility segment, which includes all of our other nonutility operations.

      Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. The accounting policies of the segments are the same as those described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2003. We evaluate performance based on net income or loss of the respective operating units. Summarized income statements by segment are shown in the following tables.

                                             
 
For the Three Months Ended June 30, 2004

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
Operating revenues from external parties
  $ 255,986     $ 288,809     $ 1,263     $     $ 546,058  
Intersegment revenues
    266       75,530       4,947       (80,743 )      
     
     
     
     
     
 
      256,252       364,339       6,210       (80,743 )     546,058  
Purchased gas cost
    163,093       352,708       3,150       (80,385 )     438,566  
     
     
     
     
     
 
 
Gross profit
    93,159       11,631       3,060       (358 )     107,492  
Operating expenses
    79,967       4,784       1,639       (358 )     86,032  
     
     
     
     
     
 
Operating income
    13,192       6,847       1,421             21,460  
Miscellaneous income (expense)
    1,668       178       1,637       (1,296 )     2,187  
Interest charges
    16,119       411       777       (1,296 )     16,011  
     
     
     
     
     
 
Income (loss) before income taxes
    (1,259 )     6,614       2,281             7,636  
Income tax expense (benefit)
    (711 )     2,664       918             2,871  
     
     
     
     
     
 
   
Net income (loss)
  $ (548 )   $ 3,950     $ 1,363     $     $ 4,765  
     
     
     
     
     
 

23


 

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                             
For the Three Months Ended June 30, 2003

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
Operating revenues from external parties
  $ 245,741     $ 240,760     $ 1,969     $     $ 488,470  
Intersegment revenues
    257       134,072       1,716       (136,045 )      
     
     
     
     
     
 
      245,998       374,832       3,685       (136,045 )     488,470  
Purchased gas cost
    161,426       367,395       467       (135,882 )     393,406  
     
     
     
     
     
 
 
Gross profit
    84,572       7,437       3,218       (163 )     95,064  
Operating expenses
    78,306       1,375       1,490       (163 )     81,008  
     
     
     
     
     
 
Operating income
    6,266       6,062       1,728             14,056  
Miscellaneous income (expense)
    1,347       430       662       (1,753 )     686  
Interest charges
    16,235       662       898       (1,753 )     16,042  
     
     
     
     
     
 
Income (loss) before income taxes
    (8,622 )     5,830       1,492             (1,300 )
Income tax expense (benefit)
    (4,005 )     2,314       592             (1,099 )
     
     
     
     
     
 
   
Net income (loss)
  $ (4,617 )   $ 3,516     $ 900     $     $ (201 )
     
     
     
     
     
 
                                             
 
For the Nine Months Ended June 30, 2004

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
Operating revenues from external parties
  $ 1,424,180     $ 999,135     $ 3,844     $     $ 2,427,159  
Intersegment revenues
    842       256,251       16,648       (273,741 )      
     
     
     
     
     
 
      1,425,022       1,255,386       20,492       (273,741 )     2,427,159  
Purchased gas cost
    1,003,977       1,214,395       9,158       (273,042 )     1,954,488  
     
     
     
     
     
 
 
Gross profit
    421,045       40,991       11,334       (699 )     472,671  
Operating expenses
    263,004       14,262       5,689       (699 )     282,256  
     
     
     
     
     
 
Operating income
    158,041       26,729       5,645             190,415  
Miscellaneous income (expense)
    4,001       530       7,771       (4,452 )     7,850  
Interest charges
    49,285       2,284       2,389       (4,452 )     49,506  
     
     
     
     
     
 
Income before income taxes
    112,757       24,975       11,027             148,759  
Income tax expense
    41,636       10,067       4,445             56,148  
     
     
     
     
     
 
   
Net income
  $ 71,121     $ 14,908     $ 6,582     $     $ 92,611  
     
     
     
     
     
 

24


 

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                             
For the Nine Months Ended June 30, 2003

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
Operating revenues from external parties
  $ 1,341,558     $ 1,013,426     $ 8,060     $     $ 2,363,044  
Intersegment revenues
    969       325,306       8,182       (334,457 )      
     
     
     
     
     
 
      1,342,527       1,338,732       16,242       (334,457 )     2,363,044  
Purchased gas cost
    934,649       1,325,655       1,475       (333,933 )     1,927,846  
     
     
     
     
     
 
 
Gross profit
    407,878       13,077       14,767       (524 )     435,198  
Operating expenses
    248,485       7,366       5,313       (524 )     260,640  
     
     
     
     
     
 
Operating income
    159,393       5,711       9,454             174,558  
Miscellaneous income (expense)
    (872 )     1,703       6,067       (3,577 )     3,321  
Interest charges
    47,231       2,090       1,935       (3,577 )     47,679  
     
     
     
     
     
 
Income before income taxes and cumulative effect of accounting change
    111,290       5,324       13,586             130,200  
Income tax expense
    40,796       2,114       5,393             48,303  
     
     
     
     
     
 
Income before cumulative effect of accounting change
    70,494       3,210       8,193             81,897  
Cumulative effect of accounting change, net of income tax benefit
          (7,773 )                 (7,773 )
     
     
     
     
     
 
   
Net income (loss)
  $ 70,494     $ (4,563 )   $ 8,193     $     $ 74,124  
     
     
     
     
     
 

25


 

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Balance sheet information at June 30, 2004 and September 30, 2003, by segment, is presented in the following tables:

                                             
At June 30, 2004

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
ASSETS
Property, plant and equipment, net
  $ 1,631,190     $ 7,981     $ 45,575     $     $ 1,684,746  
Investment in subsidiaries
    156,428       (1,413 )           (155,015 )      
Current assets
                                       
 
Cash and cash equivalents
    108,758       17,263       874             126,895  
 
Assets from risk management activities
    789       13,136             (4,372 )     9,553  
 
Other current assets
    164,163       187,366       33,623       (42,135 )     343,017  
 
Intercompany receivables
                12,781       (12,781 )      
     
     
     
     
     
 
   
Total current assets
    273,710       217,765       47,278       (59,288 )     479,465  
Intangible assets
          4,377                   4,377  
Goodwill
    237,635       21,704       12,128             271,467  
Noncurrent assets from risk management activities
          905             (173 )     732  
Deferred charges and other assets
    214,724       1,777       23,244             239,745  
     
     
     
     
     
 
    $ 2,513,687     $ 253,096     $ 128,225     $ (214,476 )   $ 2,680,532  
     
     
     
     
     
 
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
  $ 926,846     $ 90,666     $ 65,762     $ (156,428 )   $ 926,846  
Long-term debt
    854,803             8,463             863,266  
     
     
     
     
     
 
   
Total capitalization
    1,781,649       90,666       74,225       (156,428 )     1,790,112  
Current liabilities
                                       
 
Current maturities of long-term debt
    3,917             2,001             5,918  
 
Short-term debt
                             
 
Liabilities from risk management activities
    8,227       12,370             (4,967 )     15,630  
 
Other current liabilities
    256,430       146,552       32,732       (39,462 )     396,252  
 
Intercompany payables
    4,081       8,700             (12,781 )      
     
     
     
     
     
 
   
Total current liabilities
    272,655       167,622       34,733       (57,210 )     417,800  
Deferred income taxes
    225,632       (8,669 )     11,080       (144 )     227,899  
Noncurrent liabilities from risk management activities
          2,292             (694 )     1,598  
Regulatory cost of removal obligation
    105,059                         105,059  
Deferred credits and other liabilities
    128,692       1,185       8,187             138,064  
     
     
     
     
     
 
    $ 2,513,687     $ 253,096     $ 128,225     $ (214,476 )   $ 2,680,532  
     
     
     
     
     
 

26


 

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                             
At September 30, 2003

Natural Gas Other
Utility Marketing Nonutility Eliminations Consolidated





(In thousands)
ASSETS
Property, plant and equipment, net
  $ 1,555,381     $ 9,288     $ 59,725     $     $ 1,624,394  
Investment in subsidiaries
    133,586       (2,662 )           (130,924 )      
Current assets
                                       
 
Cash and cash equivalents
          14,880       803             15,683  
 
Assets from risk management activities
    202       22,941             (884 )     22,259  
 
Other current assets
    230,609       197,239       85,119       (92,912 )     420,055  
 
Intercompany receivables
    114,550                   (114,550 )      
     
     
     
     
     
 
   
Total current assets
    345,361       235,060