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  • 10-Q (Aug 6, 2014)
  • 10-Q (May 7, 2014)
  • 10-Q (Feb 4, 2014)
  • 10-Q (Aug 7, 2013)
  • 10-Q (May 2, 2013)
  • 10-Q (Feb 7, 2013)

 
8-K

 
Other

Atmos Energy 10-Q 2006

Documents found in this filing:

  1. 10-Q
  2. Ex-12
  3. Ex-15
  4. Ex-31
  5. Ex-32
  6. Ex-32
e10vq
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
     
(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, 2006
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
 
 
     
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)
 
 
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, or a non-accelerated filer. See definition of “Accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o
 
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, 2006.
 
     
Class
 
Shares Outstanding
 
No Par Value
  81,595,723
 


TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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
SIGNATURES
EXHIBITS INDEX
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

 
 
     
AEH
  Atmos Energy Holdings, Inc.
AEM
  Atmos Energy Marketing, LLC
AES
  Atmos Energy Services, LLC
APB
  Accounting Principles Board
APS
  Atmos Pipeline and Storage, LLC
Bcf
  Billion cubic feet
EITF
  Emerging Issues Task Force
FASB
  Financial Accounting Standards Board
FERC
  Federal Energy Regulatory Commission
FIN
  FASB Interpretation
Fitch
  Fitch Ratings, Ltd.
GPSC
  Georgia Public Service Commission
GRIP
  Gas Reliability Infrastructure Program
KPSC
  Kentucky Public Service Commission
LGS
  Louisiana Gas Service Company and LGS Natural Gas Company, which were acquired July 1, 2001
LPSC
  Louisiana Public Service Commission
Mcf
  Thousand cubic feet
MMcf
  Million cubic feet
Moody’s
  Moody’s Investors Services, Inc.
MPSC
  Mississippi Public Service Commission
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
TLGP
  Trans Louisiana Gas Pipeline
TRA
  Tennessee Regulatory Authority
TXU Gas
  TXU Gas Company, which was acquired on October 1, 2004
WNA
  Weather Normalization Adjustment


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Table of Contents

 
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    June 30,
    September 30,
 
    2006     2005  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
               
Property, plant and equipment
  $ 4,993,093     $ 4,765,610  
Less accumulated depreciation and amortization
    1,414,010       1,391,243  
                 
Net property, plant and equipment
    3,579,083       3,374,367  
Current assets
               
Cash and cash equivalents
    26,849       40,116  
Cash held on deposit in margin account
    58,176       80,956  
Accounts receivable, net
    409,087       454,313  
Gas stored underground
    437,069       450,807  
Other current assets
    118,990       238,238  
                 
Total current assets
    1,050,171       1,264,430  
Goodwill and intangible assets
    737,349       737,787  
Deferred charges and other assets
    249,874       276,943  
                 
    $ 5,616,477     $ 5,653,527  
                 
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, 2006 — 81,538,149 shares;
September 30, 2005 — 80,539,401 shares
  $ 408     $ 403  
Additional paid-in capital
    1,456,032       1,426,523  
Retained earnings
    243,956       178,837  
Accumulated other comprehensive loss
    (35,840 )     (3,341 )
                 
Shareholders’ equity
    1,664,556       1,602,422  
Long-term debt
    2,180,752       2,183,104  
                 
Total capitalization
    3,845,308       3,785,526  
Current liabilities
               
Accounts payable and accrued liabilities
    306,805       461,314  
Other current liabilities
    407,575       503,368  
Short-term debt
    297,087       144,809  
Current maturities of long-term debt
    3,331       3,264  
                 
Total current liabilities
    1,014,798       1,112,755  
Deferred income taxes
    283,757       292,207  
Regulatory cost of removal obligation
    275,955       263,424  
Deferred credits and other liabilities
    196,659       199,615  
                 
    $ 5,616,477     $ 5,653,527  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    June 30  
    2006     2005  
    (Unaudited)
 
    (In thousands, except
 
    per share data)
 
 
Operating revenues
               
Utility segment
  $ 402,044     $ 501,735  
Natural gas marketing segment
    562,447       466,835  
Pipeline and storage segment
    35,862       33,449  
Other nonutility segment
    1,413       1,421  
Intersegment eliminations
    (138,523 )     (96,563 )
                 
      863,243       906,877  
Purchased gas cost
               
Utility segment
    232,192       326,502  
Natural gas marketing segment
    563,333       456,440  
Pipeline and storage segment
    379       (1,733 )
Other nonutility segment
           
Intersegment eliminations
    (137,161 )     (95,606 )
                 
      658,743       685,603  
                 
Gross profit
    204,500       221,274  
Operating expenses
               
Operation and maintenance
    104,380       91,443  
Depreciation and amortization
    46,838       43,448  
Taxes, other than income
    48,479       46,915  
                 
Total operating expenses
    199,697       181,806  
                 
Operating income
    4,803       39,468  
Miscellaneous income
    963       1,524  
Interest charges
    35,944       33,689  
                 
Income (loss) before income taxes
    (30,178 )     7,303  
Income tax expense (benefit)
    (12,033 )     2,817  
                 
Net income (loss)
  $ (18,145 )   $ 4,486  
                 
Basic net income (loss) per share
  $ (0.22 )   $ 0.06  
                 
Diluted net income (loss) per share
  $ (0.22 )   $ 0.06  
                 
Cash dividends per share
  $ 0.315     $ 0.310  
                 
Weighted average shares outstanding:
               
Basic
    80,840       79,683  
                 
Diluted
    80,840       80,144  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Nine Months Ended
 
    June 30  
    2006     2005  
    (Unaudited)
 
    (In thousands, except
 
    per share data)
 
 
Operating revenues
               
Utility segment
  $ 3,254,674     $ 2,650,793  
Natural gas marketing segment
    2,482,921       1,473,527  
Pipeline and storage segment
    121,057       122,685  
Other nonutility segment
    4,500       4,058  
Intersegment eliminations
    (682,243 )     (290,477 )
                 
      5,180,909       3,960,586  
Purchased gas cost
               
Utility segment
    2,488,906       1,895,181  
Natural gas marketing segment
    2,413,511       1,425,128  
Pipeline and storage segment
    590       8,895  
Other nonutility segment
           
Intersegment eliminations
    (678,591 )     (287,889 )
                 
      4,224,416       3,041,315  
                 
Gross profit
    956,493       919,271  
Operating expenses
               
Operation and maintenance
    325,295       305,640  
Depreciation and amortization
    137,174       132,771  
Taxes, other than income
    158,691       140,537  
                 
Total operating expenses
    621,160       578,948  
                 
Operating income
    335,333       340,323  
Miscellaneous income (expense)
    (1,028 )     2,867  
Interest charges
    107,625       99,304  
                 
Income before income taxes
    226,680       243,886  
Income tax expense
    85,002       91,299  
                 
Net income
  $ 141,678     $ 152,587  
                 
Basic net income per share
  $ 1.76     $ 1.96  
                 
Diluted net income per share
  $ 1.75     $ 1.94  
                 
Cash dividends per share
  $ 0.945     $ 0.930  
                 
Weighted average shares outstanding:
               
Basic
    80,520       78,009  
                 
Diluted
    81,013       78,478  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
 
                 
    Nine Months Ended
 
    June 30  
    2006     2005  
    (Unaudited)
 
    (In thousands)
 
 
Cash Flows From Operating Activities
               
Net income
  $ 141,678     $ 152,587  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    137,174       132,771  
Charged to other accounts
    359       634  
Deferred income taxes
    36,160       17,703  
Other
    12,063       7,593  
Net assets / liabilities from risk management activities
    (3,940 )     14,276  
Net change in operating assets and liabilities
    (100,051 )     61,846  
                 
Net cash provided by operating activities
    223,443       387,410  
Cash Flows From Investing Activities
               
Capital expenditures
    (322,691 )     (226,851 )
Acquisitions
          (1,916,654 )
Other, net
    (4,811 )     (1,648 )
                 
Net cash used in investing activities
    (327,502 )     (2,145,153 )
Cash Flows From Financing Activities
               
Net increase in short-term debt
    152,278        
Net proceeds from issuance of long-term debt
          1,385,847  
Repayment of long-term debt
    (2,618 )     (102,801 )
Settlement of Treasury lock agreements
          (43,770 )
Cash dividends paid
    (76,559 )     (74,048 )
Issuance of common stock
    17,691       32,206  
Net proceeds from equity offering
          382,014  
                 
Net cash provided by financing activities
    90,792       1,579,448  
                 
Net decrease in cash and cash equivalents
    (13,267 )     (178,295 )
Cash and cash equivalents at beginning of period
    40,116       201,932  
                 
Cash and cash equivalents at end of period
  $ 26,849     $ 23,637  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2006
 
1.   Nature of Business
 
Atmos Energy Corporation (“Atmos” or “the Company”) and its subsidiaries are engaged primarily in the natural gas utility business as well as other natural gas nonutility businesses. Our natural gas utility business distributes natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated natural gas utility divisions, in the service areas described below:
 
     
Division   Service Area
 
Atmos Energy Colorado-Kansas Division   Colorado, Kansas, Missouri(1)
Atmos Energy Kentucky Division   Kentucky
Atmos Energy Louisiana Division   Louisiana
Atmos Energy Mid-States Division   Georgia(1), Illinois(1), Iowa(1),
Missouri(1), Tennessee, Virginia(1)
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 locations where we have more limited service areas.
 
Our nonutility businesses operate in 22 states and include our natural gas marketing operations, pipeline and storage operations and other nonutility operations. These operations are either organized under or managed by Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by the Company.
 
Our natural gas marketing operations are managed by Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas customers, primarily in the southeastern and midwestern states and to our Kentucky, Louisiana and Mid-States utility divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative instruments.
 
Our pipeline and storage business includes the regulated operations of our Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and the nonregulated operations of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. The Atmos Pipeline — Texas Division transports natural gas to our Atmos Energy Mid-Tex Division and to third parties, as well as manages five underground storage reservoirs in Texas. Through APS, we own or have an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.
 
Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., which are each wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices in exchange for revenues that are equal to the costs incurred to provide these services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and have entered into agreements to lease these plants.


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
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 in its Annual Report on Form 10-K for the fiscal year ended September 30, 2005. Because of seasonal and other factors, the results of operations for the three and nine-month periods ended June 30, 2006 are not indicative of expected results of operations for the full 2006 fiscal year, which ends September 30, 2006.
 
 
Certain prior-period amounts have been reclassified to conform with the current year’s presentation.
 
 
Our accounting policies are described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2005. Except for the Company’s adoption of Statement of Financial Accounting Standards (SFAS) 123 (revised), Share-Based Payment, discussed below, there were no significant changes to our accounting policies during the nine months ended June 30, 2006.
 
Additionally, during the second quarter of fiscal 2006, we completed our annual goodwill impairment assessment. Based on the assessment performed, our goodwill was not considered to be impaired.
 
 
Our 1998 Long-Term Incentive Plan provides for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units to officers, division presidents and other key employees. Non-employee directors are also eligible to receive stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock.
 
On October 1, 2005, the Company adopted SFAS 123 (revised), Share-Based Payment (SFAS 123(R)). This standard revises SFAS 123, Accounting for Stock-Based Compensation and supersedes Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), the Company is required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award.
 
We adopted SFAS 123(R) using the modified prospective method. Under this transition method, stock-based compensation expense for the three and nine months ended June 30, 2006 included: (i) compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of October 1, 2005, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123; and (ii) compensation expense for all stock-based compensation awards granted subsequent to October 1, 2005, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123(R). We recognize compensation expense on a straight-line basis over the requisite service period of the award. The impact of adoption on total stock-based compensation expense included in our statement of income for the three and nine months ended June 30, 2006 was less than $0.1 million and $0.4 million and was recorded as a component of operation and maintenance expense. In accordance with the modified prospective method, financial results for prior periods have not been restated.
 
Prior to October 1, 2005, we accounted for these plans under the intrinsic-value method described in APB Opinion 25, as permitted by SFAS 123. Under this method, no compensation cost for stock options was recognized


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Table of Contents

 
ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for stock-option awards granted at or above fair-market value. Awards of restricted stock were valued at the market price of the Company’s common stock on the date of grant. The unearned compensation was amortized as a component of operation and maintenance expense over the vesting period of the restricted stock.
 
Total stock-based compensation expense for the three and nine months ended June 30, 2006 was $2.1 million and $4.3 million as compared to $0.9 million and $2.4 million for the three and nine months ended June 30, 2005. Had compensation expense for our stock-based awards been recognized as prescribed by SFAS 123, our net income and earnings per share for the three and nine months ended June 30, 2005 would have been impacted as shown in the following table:
 
                 
    Three Months Ended
    Nine Months Ended
 
    June 30, 2005     June 30, 2005  
    (In thousands, except per share data)  
 
Net income — as reported
  $ 4,486     $ 152,587  
Restricted stock compensation expense included in income, net of tax
    542       1,514  
Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of taxes
    (676 )     (2,114 )
                 
Net income — pro forma
  $ 4,352     $ 151,987  
                 
Earnings per share:
               
Basic earnings per share — as reported
  $ 0.06     $ 1.96  
                 
Basic earnings per share — pro forma
  $ 0.05     $ 1.95  
                 
Diluted earnings per share — as reported
  $ 0.06     $ 1.94  
                 
Diluted earnings per share — pro forma
  $ 0.05     $ 1.94  
                 
 
 
We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is separately reported.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Significant regulatory assets and liabilities as of June 30, 2006 and September 30, 2005 included the following:
 
                 
    June 30,
    September 30,
 
    2006     2005  
    (In thousands)  
 
Regulatory assets:
               
Merger and integration costs, net
  $ 8,895     $ 9,150  
Deferred gas cost
    24,645       38,173  
Environmental costs
    1,234       1,357  
Rate case costs
    8,986       11,314  
Deferred franchise fees
    1,202       6,710  
Other
    8,921       9,313  
                 
    $ 53,883     $ 76,017  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 69,542     $ 134,048  
Regulatory cost of removal obligation
    290,604       274,989  
Deferred income taxes, net
    3,185       3,185  
Other
    6,570       8,084  
                 
    $ 369,901     $ 420,306  
                 
 
Currently 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)

 
 
The following table presents the components of comprehensive income, net of related tax, for the three and nine-month periods ended June 30, 2006 and 2005:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2006     2005     2006     2005  
    (In thousands)  
 
Net income (loss)
  $ (18,145 )   $ 4,486     $ 141,678     $ 152,587  
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(187) and $(7) for the three months ended June 30, 2006 and 2005 and of $355 and $722 for the nine months ended June 30, 2006 and 2005
    (304 )     (11 )     580       1,178  
Amortization and unrealized losses on interest rate hedging transactions, net of tax expense (benefit) of $528 and $528 for the three months ended June 30, 2006 and 2005 and $1,583 and $(2,190) for the nine months ended June 30, 2006 and 2005
    860       860       2,581       (3,575 )
Net unrealized losses on commodity hedging transactions, net of tax benefit of $4,182 and $2,675 for the three months ended June 30, 2006 and 2005 and $21,858 and $2,672 for the nine months ended June 30, 2006 and 2005
    (6,821 )     (4,366 )     (35,660 )     (4,361 )
                                 
Comprehensive income (loss)
  $ (24,410 )   $ 969     $ 109,179     $ 145,829  
                                 
 
Accumulated other comprehensive loss, net of tax, as of June 30, 2006 and September 30, 2005 consisted of the following unrealized gains (losses):
 
                 
    June 30,
    September 30,
 
    2006     2005  
    (In thousands)  
 
Accumulated other comprehensive loss:
               
Unrealized holding gains on investments
  $ 1,264     $ 684  
Treasury lock agreements
    (21,401 )     (23,982 )
Cash flow hedges
    (15,703 )     19,957  
                 
    $ (35,840 )   $ (3,341 )
                 
 
Recent accounting pronouncements
 
In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred — generally upon acquisition, construction or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligation. We will be required to apply the provisions of FIN 47 by September 30, 2006. We are currently evaluating the impact that FIN 47 may have on our financial position, results of operations and cash flows.
 
In February 2006, the FASB issued SFAS 155, Accounting for Certain Hybrid Financial Instruments, which amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities and SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS 155 (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, (c) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and (e) amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS 155 is effective for all financial instruments acquired or issued by us after October 1, 2006 but is not expected to have a material impact on our financial position, results of operations and cash flows.
 
In March 2006, the FASB issued SFAS 156, Accounting for Servicing Financial Assets, which amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.  SFAS 156 (a) revises guidance on when a servicing asset and servicing liability should be recognized, (b) requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable, (c) permits an entity to choose to measure servicing assets and servicing liabilities under the amortization method or fair value measurement method, (d) at initial adoption, permits a one-time reclassification of available-for-sale securities to trading securities by entities with recognized servicing rights, without calling into question the treatment of other available-for-sale securities under SFAS 115, provided that the available-for-sale securities are identified as offsetting the exposure to changes in the fair value of servicing assets or liabilities that the servicer elects to subsequently measure at fair value and (e) requires separate presentation of servicing assets and servicing liabilities subsequently measured at fair value in the statement of financial position and additional footnote disclosure. We will be required to apply the provisions of SFAS 156 beginning October 1, 2006 but such application is not expected to have a material impact on our financial position, results of operations and cash flows.
 
In March 2006, the FASB issued the exposure draft Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). The exposure draft, if adopted in its current form, would make a significant change to the existing rules by requiring recognition in the balance sheet of the overfunded or underfunded positions of defined benefit pension and other postretirement plans, along with a corresponding noncash, after-tax adjustment to stockholders’ equity. The proposed standard, if adopted, will be effective for fiscal 2007. We are monitoring the status of the exposure draft and assessing the impact it will have on our financial position, results of operations and cash flows.
 
In June 2006, the Emerging Issues Task Force (EITF) ratified EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). The EITF reached a consensus that the scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include sales, use, value added, and some excise taxes. The EITF also reached a consensus that entities may present these taxes on either a gross or net basis. If the taxes are significant, an entity should disclose its policy of presenting taxes and the amounts of taxes that are recognized on a gross basis in interim and annual financial statements. We will be required to apply the provisions of EITF 06-3 beginning January 1, 2007. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.
 
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes by establishing standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. This interpretation also provides guidance on derecognition of income tax assets and


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties, accounting for income taxes in interim periods and income tax disclosures. We will be required to apply the provisions of FIN 48 beginning October 1, 2007. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.
 
3.   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 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. Effective October 1, 2005, the Company changed its mark to market measurement from Inside FERC to Gas Daily to better reflect the prices of our physical commodity. This change did not have a material impact on our financial position on the date of adoption.
 
The following table shows the fair values of our risk management assets and liabilities by segment at June 30, 2006 and September 30, 2005:
 
                         
          Natural Gas
       
    Utility     Marketing     Total  
    (In thousands)  
 
June 30, 2006:
                       
Assets from risk management activities, current
  $ 11,930     $ 4,589     $ 16,519  
Assets from risk management activities, noncurrent
          38       38  
Liabilities from risk management activities, current
    (4,299 )     (25,351 )     (29,650 )
Liabilities from risk management activities, noncurrent
          (9,073 )     (9,073 )
                         
Net assets (liabilities)
  $ 7,631     $ (29,797 )   $ (22,166 )
                         
September 30, 2005:
                       
Assets from risk management activities, current
  $ 93,310     $ 14,603     $ 107,913  
Assets from risk management activities, noncurrent
          735       735  
Liabilities from risk management activities, current
          (61,920 )     (61,920 )
Liabilities from risk management activities, noncurrent
          (15,316 )     (15,316 )
                         
Net assets (liabilities)
  $ 93,310     $ (61,898 )   $ 31,412  
                         
 
 
We use a combination of storage, fixed physical contracts and fixed financial contracts to partially insulate us and our customers against gas price volatility during the winter heating season. Because the gains or losses of financial derivatives used in our utility segment ultimately will be recovered through our rates, current period changes in the assets and liabilities from these risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. Our utility hedging activities also include the cost of our Treasury lock agreements which are described in further detail below.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
AEM manages its exposure to the risk of natural gas price changes through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our financial derivative activities include fair value hedges to offset changes in the fair value of our natural gas inventory and cash flow hedges to offset anticipated purchases and sales of gas in the future. AEM also utilizes basis swaps and other non-hedge derivative instruments to manage its exposure to market volatility.
 
For the three and nine-month periods ended June 30, 2006, the change in the deferred hedging position in accumulated other comprehensive loss was attributable to decreases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition for the nine months ended June 30, 2006 of $3.4 million in net deferred hedging gains ($4.8 million in net deferred hedging losses during the three months ended June 30, 2006) in net income when the derivative contracts matured according to their terms. The net deferred hedging loss associated with open cash flow hedges remains subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. The majority of the deferred hedging balance as of June 30, 2006 is expected to be recognized in net income in fiscal 2006 along with the corresponding hedged purchases and sales of natural gas. The remainder of the deferred hedging balance is expected to be recognized in net income in fiscal 2007 and beyond.
 
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 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, 2006, AEH had no net open positions (including existing storage).
 
 
During fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the then anticipated issuance of $875 million of long-term debt in October 2004. We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. This payment was recorded in accumulated other comprehensive loss and is being recognized as a component of interest expense over a period of five to ten years. During the three and nine-month periods ended June 30, 2006, we recognized approximately $1.4 million and $4.2 million of this amount as a component of interest expense.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
4.   Debt
 
 
Long-term debt at June 30, 2006 and September 30, 2005 consisted of the following:
 
                 
    June 30,
    September 30,
 
    2006     2005  
    (In thousands)  
 
Unsecured floating rate Senior Notes, due October 2007
  $ 300,000     $ 300,000  
Unsecured 4.00% Senior Notes, due 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 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 2013
    8,750       10,000  
Other term notes due in installments through 2013
    6,471       7,839  
                 
Total long-term debt
    2,187,524       2,190,142  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (3,441 )     (3,774 )
Current maturities
    (3,331 )     (3,264 )
                 
    $ 2,180,752     $ 2,183,104  
                 
 
Our unsecured floating rate debt bears interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At June 30, 2006, the interest rate on our floating rate debt was 5.452 percent.
 
 
At June 30, 2006 and September 30, 2005, there was $297.1 million and $144.8 million outstanding under our commercial paper program and bank credit facilities.
 
 
We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the banks. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder winter months. Our working capital needs can vary significantly due to changes in the price of natural gas and the increased gas supplies required to meet customers’ needs during periods of cold weather.
 
 
As of June 30, 2006, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a three-year unsecured facility, expiring October 2008, for $600 million that bears interest at a base rate or at the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings, and serves


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

as a backup liquidity facility for our $600 million commercial paper program. At June 30, 2006, there was $281.9 million outstanding under our commercial paper program.
 
We have a second unsecured facility in place which is a 364-day facility expiring November 2006, for $300 million that bears interest at a base rate or the LIBOR rate plus from 0.40 percent to 1.00 percent, based on the Company’s credit ratings. At June 30, 2006, there were no borrowings under this facility.
 
We have a third unsecured facility in place for $18 million that bears interest at the Federal Funds rate plus 0.5 percent. This facility expired on March 31, 2006 and was renewed effective April 1, 2006 for one year with no material changes to its terms and pricing. At June 30, 2006, there was $15.2 million outstanding 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 both our $600 million three-year credit facility and $300 million 364-day credit facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2006, our total-debt-to-total-capitalization ratio, as defined, was 62 percent. In addition, the fees that we pay on unused amounts under both the $600 million and $300 million credit facilities are subject to adjustment depending upon our credit ratings.
 
 
On November 28, 2005, AEM amended its $250 million uncommitted demand working capital credit facility to increase the amount of credit available from $250 million to a maximum of $580 million. On March 31, 2006, AEM amended and extended this uncommitted demand working capital credit facility to March 31, 2007.
 
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 0.50 percent per annum above the Federal Funds rate or 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 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 to maintain a maximum ratio of total liabilities to tangible net worth of 5 to 1, along with minimum levels of net working capital ranging from $20 million to $120 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $121 million, and must not have a maximum cumulative loss from March 30, 2005 exceeding $4 million to $23 million, depending on the total amount of borrowing elected from time to time by AEM. At June 30, 2006, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.00 to 1.
 
At June 30, 2006, there were no borrowings outstanding under this credit facility. However, at June 30, 2006, AEM letters of credit totaling $70.4 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 $129.6 million at June 30, 2006. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.
 
The Company also has an unsecured short-term uncommitted credit line for $25 million that is used for working-capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at June 30, 2006, but letters of credit reduced the amount available by $4.5 million. This uncommitted line is renewed


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

or renegotiated at least annually with varying terms, and we pay no fee for the availability of the line. Borrowings under this line are made on a when-and-as-available basis at the discretion of the bank.
 
AEH, the parent company of AEM, has a $100 million intercompany uncommitted demand credit facility with the Company which bears interest at LIBOR plus 2.75 percent. This facility has been approved by our state regulators through December 31, 2006. At June 30, 2006, $88.4 million was outstanding under this facility. On July 1, 2006, this facility was renewed for one year with no material changes to its terms.
 
In addition, AEM has a $120 million intercompany uncommitted demand credit facility with AEH for its nonutility business which bears interest at LIBOR plus 2.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility described above. This facility is used to supplement AEM’s $580 million credit facility. At June 30, 2006, $82.0 million was outstanding under this facility. On July 1, 2006, this facility was renewed for one year with no material changes to its terms.
 
 
We have other covenants in addition to those described above. Our Series P First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, after November 2007, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1985 may not exceed the sum of accumulated net income for periods after December 31, 1985 plus $9 million. At June 30, 2006 approximately $223.0 million of retained earnings was unrestricted with respect to the payment of dividends.
 
We were in compliance with all of our debt covenants as of June 30, 2006. 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 two public debt indentures relating to our senior notes and debentures, as well as our $600 million and $300 million revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. In addition, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.
 
Except as described above, we have no triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.
 
5.   Stock-Based Compensation
 
 
On August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by our shareholders. The Long-Term Incentive Plan is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units to certain employees and non-employee directors of Atmos and its subsidiaries. The objectives of this plan 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. We are authorized to grant awards for up to a maximum of four million shares of common stock under this plan subject to certain adjustment provisions. As of June 30, 2006, non-qualified stock options, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units had been issued


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

under this plan and 715,699 shares were available for issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years.
 
We used the Black-Scholes pricing model to estimate the fair value of each option granted with the following weighted average assumptions:
 
                 
    Nine Months Ended
 
    June 30  
Valuation Assumptions(1)
  2006     2005  
 
Expected Life (years)(2)
    7       7  
Interest rate(3)
    4.6 %     4.2 %
Volatility(4)
    20.3 %     21.3 %
Dividend yield
    4.8 %     4.8 %
 
 
(1) Beginning on the date of adoption of SFAS 123(R), forfeitures are estimated based on historical experience. Prior to the date of adoption, forfeitures were recorded as they occurred.
 
(2) The expected life of stock options is estimated based on historical experience.
 
(3) The interest rate is based on the U.S. Treasury constant maturity interest rate whose term is consistent with the expected life of the stock options.
 
(4) The volatility is estimated based on historical and current stock data for the Company.
 
A summary of option activity as of June 30, 2006, and changes during the nine months then ended, is presented below:
 
                                 
                Weighted-
       
          Weighted-
    Average
       
    Number
    Average
    Remaining
    Aggregate
 
    of
    Exercise
    Contractual
    Intrinsic
 
    Options     Price     Term     Value  
                (In years)     (In thousands)  
 
Outstanding at September 30, 2005
    964,704     $ 22.20                  
Granted
    93,196       26.19                  
Exercised
    (23,186 )     22.36                  
Forfeited
    (166 )     21.23                  
                                 
Outstanding at June 30, 2006
    1,034,548     $ 22.56       5.6     $ 3,764  
                                 
Exercisable at June 30, 2006
    1,009,174     $ 22.47       5.5     $ 3,665  
                                 
 
The stock options had a weighted-average fair value per share on the date of grant of $3.74 and $3.69 for the nine months ended June 30, 2006 and 2005. There were no stock options granted during the three months ended June 30, 2006 and 2005. Net cash proceeds from the exercise of stock options during the nine months ended June 30, 2006 and 2005 were $0.5 million and $10.1 million and during the three months ended June 30, 2006 and 2005 were $0.5 and $1.0 million. The associated income tax benefit from stock options exercised during the nine months ended June 30, 2006 and 2005 was less than $0.1 million and $1.1 million, and during the three months ended June 30, 2006 and 2005 was less than $0.1 million and $0.1 million. The total intrinsic value of options exercised during the nine months ended June 30, 2006 and 2005 was less than $0.1 million and $1.7 million, and during the three months ended June 30, 2006 and 2005 was less than $0.1 million and $0.2 million.
 
As of June 30, 2006, there was less than $0.1 million of total unrecognized compensation cost related to nonvested stock options. That cost is expected to be recognized over a weighted-average period of 1.5 years.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
As noted above, the 1998 Long-Term Incentive Plan provides for discretionary awards of time-lapse restricted stock and performance-based restricted stock units to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The associated expense is recognized ratably over the vesting period.
 
A summary of the status of the Company’s nonvested restricted shares as of June 30, 2006, and changes during the nine months then ended, is presented below:
 
                 
          Weighted-
 
    Number of
    Average
 
    Restricted
    Grant-Date
 
    Shares     Fair Value  
 
Nonvested at September 30, 2005
    592,490     $ 25.32  
Granted
    440,016       26.80  
Vested
    (110,347 )     22.66  
Forfeited
    (10,983 )     26.79  
                 
Nonvested at June 30, 2006
    911,176     $ 26.34  
                 
 
As of June 30, 2006, there was $16.0 million of total unrecognized compensation cost related to nonvested restricted shares granted under the 1998 Long-Term Incentive Plan. That cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of restricted stock vested during the nine months ended June 30, 2006 and 2005 was $2.5 million and $0.5 million, and during the three months ended June 30, 2006 was $0.9 million. There were no restricted stock grants that vested during the three months ended June 30, 2005.
 
6.   Earnings Per Share
 
Basic and diluted earnings per share for the three and nine months ended June 30, 2006 and 2005 are calculated as follows:
 
                                 
    For the
    For the
 
    Three Months
    Nine Months
 
    Ended
    Ended
 
    June 30     June 30  
    2006     2005     2006     2005  
    (In thousands, except per share amounts)  
 
Net income (loss)
  $ (18,145 )   $ 4,486     $ 141,678     $ 152,587  
                                 
Denominator for basic income per share — weighted average common shares
    80,840       79,683       80,520       78,009  
Effect of dilutive securities:
                               
Restricted and other shares
          330       394       325  
Stock options
          131       99       144  
                                 
Denominator for diluted income per share — weighted average common shares
    80,840       80,144       81,013       78,478  
                                 
Income (loss) per share — basic
  $ (0.22 )   $ 0.06     $ 1.76     $ 1.96  
                                 
Income (loss) per share — diluted
  $ (0.22 )   $ 0.06     $ 1.75     $ 1.94  
                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
There were approximately 396,000 restricted and other shares and approximately 102,000 stock options that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2006 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, 2006 and 2005 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, 2006 and 2005 are presented in the following tables. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
                                 
    Three Months Ended June 30  
    Pension Benefits     Other Benefits  
    2006     2005     2006     2005  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 4,117     $ 3,136     $ 3,271     $ 2,478  
Interest cost
    5,722       6,017       2,210       2,366  
Expected return on assets
    (6,400 )     (6,885 )     (547 )     (518 )
Amortization of transition asset
          1       378       378  
Amortization of prior service cost
    16       (2 )     90       96  
Amortization of actuarial loss
    3,299       1,891       320       151  
                                 
Net periodic pension cost
  $ 6,754     $ 4,158     $ 5,722     $ 4,951  
                                 
 
                                 
    Nine Months Ended June 30  
    Pension Benefits     Other Benefits  
    2006     2005     2006     2005  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 12,351     $ 9,408     $ 9,813     $ 7,434  
Interest cost
    17,166       18,051       6,630       7,098  
Expected return on assets
    (19,200 )     (20,655 )     (1,641 )     (1,554 )
Amortization of transition asset
          3       1,134       1,134  
Amortization of prior service cost
    48       (6 )     270       288  
Amortization of actuarial loss
    9,897       5,673       960       453  
                                 
Net periodic pension cost
  $ 20,262     $ 12,474     $ 17,166     $ 14,853  
                                 
 
The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2006 and 2005 are as follows:
 
                                 
    Pension Benefits     Other Benefits  
    2006     2005     2006     2005  
 
Discount rate
    5.00 %     6.25 %     5.00 %     6.25 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %
Expected return on plan assets
    8.50 %     8.75 %     5.30 %     5.30 %


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
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. During the nine months ended June 30, 2006, we contributed $2.8 million to the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. The current year contribution achieved a desired level of funding by satisfying the minimum funding requirements while maximizing the tax deductible contribution for this plan for plan year 2005. We anticipate making no additional contributions to our pension plans for the remainder of fiscal 2006. However, we contributed $7.9 million to our other postretirement plans, and we expect to contribute approximately $12 million to these plans during fiscal 2006.
 
8.   Commitments and Contingencies
 
 
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2005, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2006. 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 net 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 net cash flows.
 
 
AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2006, AEM was committed to purchase 64.8 Bcf within one year, 53.7 Bcf within one to three years and 3.1 Bcf after three years under indexed contracts. AEM is committed to purchase 2.7 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $5.45 to $12.00. Purchases under these contracts totaled $398.9 million and $294.0 million for the three months ended June 30, 2006 and 2005 and $1,718.4 million and $999.4 million for the nine months ended June 30, 2006 and 2005.
 
Our utility 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, 2006 are as follows (in thousands):
 
         
2006
  $ 70,864  
2007
    346,837  
2008
    115,004  
2009
    12,795  
2010
    12,479  
Thereafter
    39,812  
         
    $ 597,791  
         


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
 
In February 2005, the Attorney General of the State of Kentucky filed a complaint with the Kentucky Public Service Commission (KPSC) alleging that our rates were producing revenues in excess of reasonable levels. We answered the complaint and filed a Motion to Dismiss with the KPSC. On February 2, 2006, the KPSC issued an Order denying our Motion to Dismiss and on March 3, 2006 set a procedural schedule for the case. The Attorney General is currently conducting discovery. A hearing should be scheduled for early 2007. We believe that the Attorney General will not be able to demonstrate that our present rates are in excess of reasonable levels.
 
In May 2006, the Mid-Tex Division filed a Statement of Intent seeking incremental annual revenues of $60 million and several rate design changes including Weather Normalization Adjustment (WNA), revenue stabilization, and recovery of the gas cost component of bad debt. The Statement of Intent consolidated “show cause” resolutions that had been filed in approximately 80 cities served by the Mid-Tex Division, including the City of Dallas, which requires the Mid-Tex Division to demonstrate that existing distribution rates are just and reasonable.
 
In July 2006, the Mid-Tex Division and the Railroad Commission of Texas (RRC) agreed to implement WNA on both an interim and permanent basis, effective October 1, 2006. The agreement provided that the interim WNA will use 30 years of weather history, while the permanent WNA would allow the parties to contest the appropriate period of weather data to use in calculating normal weather. The permanent WNA would also be modified or adjusted to conform to the rate design that the RRC ultimately approves in the case, which is anticipated no later than the first quarter of calendar 2007. Any rate increase will be effective prospectively from the date of the final order; however, any rate decrease will be effective from May 31, 2006.
 
In November 2005, we received a notice from the Tennessee Regulatory Authority (TRA) that it was opening an investigation into allegations by the Consumer Advocate and Protection Division of the Tennessee Attorney General’s Office that we are overcharging customers in parts of Tennessee by approximately $10 million per year. We have responded to numerous data requests from the TRA Staff. On April 24, 2006, the TRA Staff filed a Report and Recommendation in which it recommended that the TRA convene a contested case procedure for the purpose of establishing a fair and reasonable return. The TRA convened to consider the Staff’s recommendation on May 15, 2006 and set a procedural schedule. All parties filed direct testimony on July 17, 2006, with rebuttal due August 18, 2006. A hearing is scheduled for August 29, 2006. We believe that the Consumer Advocate and Protection Division will not be able to demonstrate that our present rates are in excess of reasonable levels.
 
In January 2006, the Lubbock, Texas City Council passed a resolution requiring Atmos to submit copies of all documentation necessary for the city to review the rates of Atmos’ West Texas Division to ensure they are just and reasonable. Information was provided to the city on February 28, 2006. We believe that we will be able to ultimately demonstrate to the City of Lubbock that our rates are just and reasonable.
 
In May 2006, Atmos began receiving “show cause” ordinances from several of the cities in the West Texas Division. The ordinances request a filing to be made no later than September 15, 2006. We believe that we will be able to ultimately demonstrate to the West Texas cities that our rates are just and reasonable.
 
Other
 
On November 30, 2005, we entered into an agreement with a third party to jointly construct, own and operate a 45-mile large diameter natural gas pipeline in the northern portion of the Dallas/Fort Worth Metroplex (North Side Loop). Under the terms of the agreement, we are responsible for contributing no more than $42.5 million to the construction costs of the pipeline. We are also responsible for 50 percent of the costs of the compression facilities. The North Side Loop was fully placed into service in May 2006. As of June 30, 2006, we had spent $46.1 million for the North Side Loop project and expect to spend approximately $5.3 million in the remainder of fiscal 2006 for this project.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
During the third quarter of fiscal 2005, we entered into two agreements with third parties to transport natural gas through our Texas intrastate pipeline system beginning in fiscal 2006. To handle the increased volumes for these projects, we installed compression equipment and other pipeline infrastructure. We have spent approximately $30 million in fiscal 2006 for these projects, which were placed in service at the end of the third quarter of fiscal 2006.
 
On August 29, 2005, Hurricane Katrina struck the Gulf Coast, inflicting significant damage to our eastern Louisiana operations. The hardest hit areas in our service territory were in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes. In total, approximately 230,000 of our natural gas customers were affected in these areas. Although service has been restored for many of our customers, a significant number of customers will not require gas service for some time because of sustained damages. We cannot predict with certainty how many of these customers will return to these service areas and over what time period they may return. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. We are implementing new rates, subject to refund, in August 2006 that reflect the reduced customer count and enable us to recoup costs attributable to Hurricane Katrina.
 
In May 2006, we announced plans to form a joint venture with a local natural gas producer to construct a natural gas gathering system in Eastern Kentucky that will originate in Floyd County, Kentucky, and extend north approximately 65 miles to interconnect with the Tennessee Gas Pipeline in Carter County, Kentucky. Tennessee Gas Pipeline’s interstate system delivers natural gas to the northeastern United States, including New York City and Boston. The new system is expected to relieve severe gas gathering and transportation constraints that historically have burdened natural gas producers in the area and should improve delivery reliability to natural gas customers. More than a dozen other producers have signed memoranda of understanding to commit gas volumes to the new system and to enter into agreements on commercially reasonable terms.
 
The project is expected to cost between $75 million to $80 million. Upon receiving all required regulatory approvals, construction is expected to begin in the first half of fiscal 2007, with operations expected to begin in fiscal 2008. Final terms of the joint venture are still under negotiation; however, we anticipate that we will have the ability to consolidate the joint venture.
 
9.   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 our customer base.
 
Customer diversification also helps mitigate AEM’s exposure to credit risk. AEM maintains credit policies with respect to its counterparties that it believes minimizes overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. AEM also monitors the financial condition of existing counterparties on an ongoing basis. Customers not meeting minimum standards are required to provide adequate assurance of financial performance.
 
AEM maintains a provision for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.
 
AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable,


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by AEM’s credit department, but are primarily based on external ratings provided by Moody’s Investors Service Inc. (Moody’s) and/or Standard & Poor’s Corporation (S&P). For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrial and commercial customers is non-investment grade. The following table shows the percentages related to the investment ratings as of June 30, 2006 and September 30, 2005.
 
                 
    June 30,
    September 30,
 
    2006     2005  
 
Investment grade
    41 %     49 %
Non-investment grade
    59 %     51 %
                 
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, 2006. Investment grade counterparties have minimum credit ratings of BBB-, assigned by S&P; or Baa3, assigned by Moody’s. 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.
 
                         
    June 30, 2006  
          Natural Gas
       
    Utility
    Marketing
       
    Segment(1)     Segment     Consolidated  
    (In thousands)  
 
Investment grade counterparties
  $ 11,930     $ 843     $ 12,773  
Non-investment grade counterparties
          3,784       3,784  
                         
    $ 11,930     $ 4,627     $ 16,557  
                         
 
 
(1) Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers.
 
10.   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 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonutility businesses we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 22 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.
 
Our operations are divided into four segments:
 
  •  the utility segment, which includes our regulated natural gas distribution and related sales operations,
 
  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services,


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
  •  the pipeline and storage segment, which includes our regulated and nonregulated natural gas transmission and storage services and
 
  •  the other nonutility segment, which includes all of our other nonregulated 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. Although our utility segment operations are geographically dispersed, they are reported as a single segment as each utility division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our annual report on Form 10-K for the fiscal year ended September 30, 2005. We evaluate performance based on net income or loss of the respective operating units.
 
Income statements for the three and nine-month periods ended June 30, 2006 and 2005 by segment are presented in the following tables:
 
                                                 
    Three Months Ended June 30, 2006  
                Pipeline
                   
          Natural Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 401,896     $ 441,418     $ 19,597     $ 332     $     $ 863,243  
Intersegment revenues
    148       121,029       16,265       1,081       (138,523 )      
                                                 
      402,044       562,447       35,862       1,413       (138,523 )     863,243  
Purchased gas cost
    232,192       563,333       379             (137,161 )     658,743  
                                                 
Gross profit
    169,852       (886 )     35,483       1,413       (1,362 )     204,500  
Operating expenses
                                               
Operation and maintenance
    85,372       5,725       13,485       1,227       (1,429 )     104,380  
Depreciation and amortization
    41,537       466       4,807       28             46,838  
Taxes, other than income
    45,853       273       2,272       81             48,479  
                                                 
Total operating expenses
    172,762       6,464       20,564       1,336       (1,429 )     199,697  
                                                 
Operating income (loss)
    (2,910 )     (7,350 )     14,919       77       67       4,803  
Miscellaneous income
    3,022       556       309       1,372       (4,296 )     963  
Interest charges
    30,892       1,716       6,384       1,181       (4,229 )     35,944  
                                                 
Income (loss) before income taxes
    (30,780 )     (8,510 )     8,844       268             (30,178 )
Income tax expense (benefit)
    (11,809 )     (3,341 )     3,012       105             (12,033 )
                                                 
Net income (loss)
  $ (18,971 )   $ (5,169 )   $ 5,832     $ 163     $     $ (18,145 )
                                                 
Capital expenditures
  $ 75,973     $ 500     $ 32,988     $     $     $ 109,461  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
                                                 
    Three Months Ended June 30, 2005  
          Natural Gas
    Pipeline
    Other
             
    Utility     Marketing     and Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 501,481     $ 387,999     $ 16,854     $ 543     $     $ 906,877  
Intersegment revenues
    254       78,836       16,595       878       (96,563 )      
                                                 
      501,735       466,835       33,449       1,421       (96,563 )     906,877  
Purchased gas cost
    326,502       456,440       (1,733 )           (95,606 )     685,603  
                                                 
Gross profit
    175,233       10,395       35,182       1,421       (957 )     221,274  
Operating expenses
                                               
Operation and maintenance
    76,862       4,948       9,573       1,067       (1,007 )     91,443  
Depreciation and amortization
    38,775       458       4,189       26             43,448  
Taxes, other than income
    44,555       242       2,064       54             46,915  
                                                 
Total operating expenses
    160,192       5,648       15,826       1,147       (1,007 )     181,806  
                                                 
Operating income
    15,041       4,747       19,356       274       50       39,468  
Miscellaneous income
    3,122       153       613       578       (2,942 )     1,524  
Interest charges
    28,520       957       6,169       935       (2,892 )     33,689  
                                                 
Income (loss) before income taxes
    (10,357 )     3,943       13,800       (83 )           7,303  
Income tax expense (benefit)
    (3,689 )     1,583       4,958       (35 )           2,817  
                                                 
Net income (loss)
  $ (6,668 )   $ 2,360     $ 8,842     $ (48 )   $     $ 4,486  
                                                 
Capital expenditures
  $ 80,336     $ 219     $ 8,830     $     $     $ 89,385  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
                                                 
    Nine Months Ended June 30, 2006  
          Natural Gas
    Pipeline
    Other
             
    Utility     Marketing     and Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 3,254,078     $ 1,866,768     $ 58,716     $ 1,347     $     $ 5,180,909  
Intersegment revenues
    596       616,153       62,341       3,153       (682,243 )      
                                                 
      3,254,674       2,482,921       121,057       4,500       (682,243 )     5,180,909  
Purchased gas cost
    2,488,906       2,413,511       590             (678,591 )     4,224,416  
                                                 
Gross profit
    765,768       69,410       120,467       4,500       (3,652 )     956,493  
Operating expenses
                                               
Operation and maintenance
    272,501       15,898       36,846       3,853       (3,803 )     325,295  
Depreciation and amortization
    121,708       1,411       13,978       77             137,174  
Taxes, other than income
    150,456       864       7,086       285             158,691  
                                                 
Total operating expenses
    544,665       18,173       57,910       4,215       (3,803 )     621,160  
                                                 
Operating income
    221,103       51,237       62,557       285       151       335,333  
Miscellaneous income (expense)
    6,014       1,754       1,846       3,216       (13,858 )     (1,028 )
Interest charges
    92,783       6,575       18,978       2,996       (13,707 )     107,625  
                                                 
Income before income taxes
    134,334       46,416       45,425       505             226,680  
Income tax expense
    50,264       18,201       16,339       198             85,002  
                                                 
Net income
  $ 84,070     $ 28,215     $ 29,086     $ 307     $     $ 141,678  
                                                 
Capital expenditures
  $ 232,137     $ 1,067     $ 89,487     $     $     $ 322,691  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
                                                 
    Nine Months Ended June 30, 2005  
          Natural Gas
    Pipeline
    Other
             
    Utility     Marketing     and Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,649,979     $ 1,250,507     $ 58,433     $ 1,667     $     $ 3,960,586  
Intersegment revenues
    814       223,020       64,252       2,391       (290,477 )      
                                                 
      2,650,793       1,473,527       122,685       4,058       (290,477 )     3,960,586  
Purchased gas cost
    1,895,181       1,425,128       8,895             (287,889 )     3,041,315  
                                                 
Gross profit
    755,612       48,399       113,790       4,058       (2,588 )     919,271  
Operating expenses
                                               
Operation and maintenance
    259,884       12,410       33,077       3,007       (2,738 )     305,640  
Depreciation and amortization
    119,007       1,436       12,244       84             132,771  
Taxes, other than income
    133,395       412       6,510       220             140,537  
                                                 
Total operating expenses
    512,286       14,258       51,831       3,311       (2,738 )     578,948  
                                                 
Operating income
    243,326       34,141       61,959       747       150       340,323  
Miscellaneous income
    6,068       600       1,220       1,787       (6,808 )     2,867  
Interest charges
    83,841       2,037       18,568       1,516       (6,658 )     99,304  
                                                 
Income before income taxes
    165,553       32,704       44,611       1,018             243,886  
Income tax expense
    61,547       13,291       16,047       414             91,299  
                                                 
Net income
  $ 104,006     $ 19,413     $ 28,564     $ 604     $     $ 152,587  
                                                 
Capital expenditures
  $ 209,392     $ 586     $ 16,873     $     $     $ 226,851  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Balance sheet information at June 30, 2006 and September 30, 2005 by segment is presented in the following tables:
 
                                                 
    June 30, 2006  
          Natural
    Pipeline
                   
          Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
                                               
Property, plant and equipment, net
  $ 3,055,306     $ 7,381     $ 515,076     $ 1,320     $     $ 3,579,083  
Investment in subsidiaries
    253,289       (2,092 )                 (251,197 )      
Current assets
                                               
Cash and cash equivalents
    8,865       17,456             528             26,849  
Cash held on deposit in margin account
          58,176                         58,176  
Assets from risk management activities
    11,930       10,388       2,698             (8,497 )     16,519  
Other current assets
    661,342       356,506       37,974       86,003       (193,198 )     948,627  
Intercompany receivables
    555,423                   30,437       (585,860 )      
                                                 
Total current assets
    1,237,560       442,526       40,672       116,968       (787,555 )     1,050,171  
Intangible assets
          3,069                         3,069  
Goodwill
    566,800       24,282       143,198                   734,280  
Noncurrent assets from risk management activities
          38       2,405             (2,405 )     38  
Deferred charges and other assets
    225,647       1,334       5,232       17,623             249,836  
                                                 
    $ 5,338,602     $ 476,538     $ 706,583     $ 135,911     $ (1,041,157 )   $ 5,616,477  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 1,664,556     $ 127,682     $ 92,210     $ 33,397     $ (253,289 )   $ 1,664,556  
Long-term debt
    2,176,362                   4,390             2,180,752  
                                                 
Total capitalization
    3,840,918       127,682       92,210       37,787       (253,289 )     3,845,308  
Current liabilities
                                               
Current maturities of long-term debt
    1,250                   2,081             3,331  
Short-term debt
    297,087       82,000             88,407       (170,407 )     297,087  
Liabilities from risk management activities
    4,299       28,049       5,795             (8,493 )     29,650  
Other current liabilities
    460,479       181,275       63,386       293       (20,703 )     684,730  
Intercompany payables
          61,236       524,624             (585,860 )      
                                                 
Total current liabilities
    763,115       352,560       593,805       90,781       (785,463 )     1,014,798  
Deferred income taxes
    280,987       (15,434 )     16,178       2,026             283,757  
Noncurrent liabilities from risk management activities
          11,478                   (2,405 )     9,073  
Regulatory cost of removal obligation
    275,955                               275,955  
Deferred credits and other liabilities
    177,627       252       4,390       5,317             187,586  
                                                 
    $ 5,338,602     $ 476,538     $ 706,583     $ 135,911     $ (1,041,157 )   $ 5,616,477  
                                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
                                                 
    September 30, 2005  
          Natural
    Pipeline
                   
          Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
                                               
Property, plant and equipment, net
  $ 2,926,096     $ 7,278     $ 439,574     $ 1,419     $     $ 3,374,367  
Investment in subsidiaries
    231,342       (1,896 )                 (229,446 )      
Current assets
                                               
Cash and cash equivalents
    10,663       28,949             504             40,116  
Cash held on deposit in margin account
    4,170       76,786                         80,956  
Assets from risk management activities
    93,310       39,528       1,739             (26,664 )     107,913  
Other current assets
    666,081       421,777       36,208       63,820       (152,441 )     1,035,445  
Intercompany receivables
    505,728                   20,133       (525,861 )      
                                                 
Total current assets
    1,279,952       567,040       37,947       84,457       (704,966 )     1,264,430  
Intangible assets
          3,507                         3,507  
Goodwill
    566,800       24,282       143,198                   734,280  
Noncurrent assets from risk management activities
          2,073       1,338             (2,676 )     735  
Deferred charges and other assets
    249,179       1,461       5,737       19,831             276,208  
                                                 
    $ 5,253,369     $ 603,745     $ 627,794     $ 105,707     $ (937,088 )   $ 5,653,527  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 1,602,422     $ 144,827     $ 53,426     $ 33,089     $ (231,342 )   $ 1,602,422  
Long-term debt
    2,177,279                   5,825             2,183,104  
                                                 
Total capitalization
    3,779,701       144,827       53,426       38,914       (231,342 )     3,785,526  
Current liabilities
                                               
Current maturities of long-term debt
    1,250                   2,014             3,264  
Short-term debt
    144,809       60,000             51,320       (111,320 )     144,809  
Liabilities from risk management activities
          63,936       25,038             (27,054 )     61,920  
Other current liabilities
    623,300       217,777       95,557       4,963       (38,835 )     902,762  
Intercompany payables
          87,968       437,893             (525,861 )      
                                                 
Total current liabilities
    769,359       429,681       558,488       58,297       (703,070 )     1,112,755  
Deferred income taxes
    268,108       12,369       9,563       2,167             292,207  
Noncurrent liabilities from risk management activities
          16,654       1,338             (2,676 )     15,316  
Regulatory cost of removal obligation
    263,424                               263,424  
Deferred credits and other liabilities
    172,777       214       4,979       6,329             184,299  
                                                 
    $ 5,253,369     $ 603,745     $ 627,794     $ 105,707     $ (937,088 )   $ 5,653,527  
                                                 


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The Board of Directors
Atmos Energy Corporation
 
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of June 30, 2006, and the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2006 and 2005, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2006 and 2005. 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, 2005, 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 16, 2005, 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, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
Ernst & Young LLP
 
Dallas, Texas
August 7, 2006


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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
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, 2005.
 
 
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 the Company 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 the Company’s documents or oral presentations, the words “anticipate”, “believe”, “expect”, “estimate”, “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 the Company’s strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions, such as warmer than normal weather in the Company’s gas utility service territories or colder than normal weather that could adversely affect our natural gas marketing activities; 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 and counterparty creditworthiness; national, regional and local economic conditions; the Company’s 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; increased competition from energy suppliers and alternative forms of energy; risks relating to the acquisition of the TXU Gas operations, including without limitation, the Company’s increased indebtedness resulting from the acquisition of the TXU Gas operations; the impact of recent natural disasters on our operations, especially Hurricane Katrina; and other uncertainties, which may be discussed herein, all of which are difficult to predict and many of which are beyond the control of the Company. A more detailed discussion of these risks and uncertainties may be found in the Company’s Form 10-K for the year ended September 30, 2005. Accordingly, while the Company believes 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, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.
 
 
Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our seven regulated utility divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonutility businesses we provide natural gas management, transportation, storage and marketing services to industrial customers, municipalities and other local distribution companies located in 22 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.
 
Our operations are divided into four segments:
 
  •  the utility segment, which includes our regulated natural gas distribution and related sales operations,


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  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services,
 
  •  the pipeline and storage segment, which includes our regulated and nonregulated natural gas transmission and storage services and
 
  •  the other nonutility segment, which includes all of our other nonregulated nonutility operations.
 
The following summarizes the results of our operations and other significant events for the nine months ended June 30, 2006:
 
  •  Our utility segment net income decreased by $19.9 million during the nine months ended June 30, 2006 compared with the nine months ended June 30, 2005. The decrease reflects the impact of weather, as adjusted for jurisdictions with weather-normalized rates, that was three percent warmer than the prior-year period and 13 percent warmer than normal, coupled with higher operating expenses.
 
  •  In May 2006, the Louisiana Public Service Commission (LPSC) approved a settlement that provides for, among other things, a modified Weather Normalization Adjustment (WNA) which provides a partial decoupling mechanism to stabilize margins and renewal of the Rate Stabilization Clause (RSC) with provisions that will reduce regulatory lag. The settlement also allowed the recognition of $6.2 million of margin that had been previously deferred as it was subject to refund.
 
  •  In May 2006, the Mid-Tex Division filed a Statement of Intent seeking incremental annual revenues of $60 million and several rate design changes including WNA, revenue stabilization, and recovery of the gas cost component of bad debt. In July 2006, the Railroad Commission of Texas (RRC) approved an interim WNA, effective October 1, 2006.
 
  •  Our natural gas marketing segment net income increased $8.8 million during the nine months ended June 30, 2006 compared with the nine months ended June 30, 2005. The increase in natural gas marketing net income primarily reflects our ability to capture higher margins in a volatile natural gas market. These increases were partially offset by a $28.2 million increase in unrealized losses reflected in this segment’s gross profit, increased operating expenses and increased interest charges resulting from increased short-term borrowings to fund working capital needs.
 
  •  Our pipeline and storage segment net income increased $0.5 million during the nine months ended June 30, 2006 compared with the nine months ended June 30, 2005. Increased gross profit margin resulting from higher transportation and related services margins coupled with increased throughput on our Atmos Pipeline-Texas system and Atmos Pipeline & Storage, LLC’s ability to capture more favorable arbitrage spreads in its asset management contracts were essentially offset by higher operating expenses.
 
  •  Our total-debt-to-capitalization ratio at June 30, 2006 was 59.9 percent compared with 59.3 percent at September 30, 2005 reflecting the impact of increased short-term debt borrowings to fund working capital needs partially offset by current-year net income.
 
  •  For the nine months ended June 30, 2006, we generated $223.4 million in operating cash flow compared with $387.4 million for the nine months ended June 30, 2005, reflecting the adverse impact of high natural gas costs on our working capital.
 
  •  Capital expenditures increased to $322.7 million in the nine months ended June 30, 2006 from $226.9 million in the prior-year period, primarily reflecting increased capital spending for various pipeline expansion projects in our Atmos Pipeline — Texas Division, all of which were completed during the third quarter of fiscal 2006.
 
 
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


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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, 2005 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 on a quarterly basis. There have been no significant changes to these critical accounting policies during the nine months ended June 30, 2006.
 
RESULTS OF OPERATIONS
 
The following table presents our financial highlights for the three-month and nine-month periods ended June 30, 2006 and 2005:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2006     2005     2006     2005  
    (In thousands, unless otherwise noted)  
 
Operating revenues
  $ 863,243     $ 906,877     $ 5,180,909     $ 3,960,586  
Gross profit
    204,500       221,274       956,493       919,271  
Operating expenses
    199,697       181,806       621,160       578,948  
Operating income
    4,803       39,468       335,333       340,323  
Miscellaneous income (expense)
    963       1,524       (1,028 )     2,867  
Interest charges
    35,944       33,689       107,625       99,304  
Income (loss) before income taxes
    (30,178 )     7,303       226,680       243,886  
Income tax expense (benefit)
    (12,033 )     2,817       85,002       91,299  
Net income (loss)
  $ (18,145 )   $ 4,486     $ 141,678     $ 152,587  
                 
Utility sales volumes — MMcf
    32,653       43,925       239,562       263,077  
Utility transportation volumes — MMcf
    29,630       28,753       91,384       88,635  
                                 
Total utility throughput — MMcf
    62,283       72,678       330,946       351,712  
                                 
Natural gas marketing sales volumes — MMcf
    66,472       52,739       207,418       179,679  
                                 
Pipeline transportation volumes — MMcf
    104,680       97,567       277,721       254,528  
                                 
Heating degree days(1)
                               
Actual (weighted average)
    119       167       2,507       2,580  
Percent of normal
    69 %     97 %     87 %     89 %
Consolidated utility average transportation revenue per Mcf
  $ 0.46     $ 0.48     $ 0.53     $ 0.53  
Consolidated utility average cost of gas per Mcf sold
  $ 7.11     $ 7.43     $ 10.39     $ 7.20  
 
 
(1) Adjusted for service areas that have weather-normalized operations.


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The following table shows our operating income by segment for the three-month and nine-month periods ended June 30, 2006 and 2005. The presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                                 
    Three Months Ended June 30  
    2006     2005  
    Operating
    Heating Degree Days
    Operating
    Heating Degree Days
 
    Income     Percent of Normal(1)     Income     Percent of Normal(1)  
    (In thousands, except degree day information)  
 
Colorado-Kansas
  $ 163       87 %   $ 2,451       105 %
Kentucky
    (371 )     101 %     1,260       105 %
Louisiana
    8,715       14 %     4,358       63 %
Mid-States
    (2,734 )     85 %     1,600       99 %
Mid-Tex
    (12,819 )     7 %     2,432       87 %
Mississippi
    (1,265 )     115 %     (2,455 )     100 %
West Texas
    4,383       98 %     4,992       100 %
Other
    1,018             403        
                                 
Utility segment
    (2,910 )     69 %     15,041       97 %
Natural gas marketing segment
    (7,350 )           4,747        
Pipeline and storage segment
    14,919             19,356        
Other nonutility segment and other
    144             324        
                                 
Consolidated operating income
  $ 4,803       69 %   $ 39,468       97 %
                                 
 
                                 
    Nine Months Ended June 30  
    2006     2005  
    Operating
    Heating Degree Days
    Operating
    Heating Degree Days
 
    Income     Percent of Normal(1)     Income     Percent of Normal(1)  
    (In thousands, except degree day information)  
 
Colorado-Kansas
  $ 23,423       98 %   $ 26,934       99 %
Kentucky
    14,876       100 %     17,863       98 %
Louisiana
    25,202       78 %     26,941       78 %
Mid-States
    36,459       95 %     37,443       94 %
Mid-Tex
    67,423       72 %     82,002       80 %
Mississippi
    25,480       102 %     24,661       96 %
West Texas
    24,053       100 %     26,080       100 %
Other
    4,187             1,402        
                                 
Utility segment
    221,103       87 %     243,326       89 %
Natural gas marketing segment
    51,237             34,141        
Pipeline and storage segment
    62,557             61,959        
Other nonutility segment and other
    436             897        
                                 
Consolidated operating income
  $ 335,333       87 %   $ 340,323       89 %
                                 
 
 
(1) Adjusted for service areas that have weather-normalized operations.


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Three Months Ended June 30, 2006 compared with Three Months Ended June 30, 2005
 
 
Our utility segment has historically contributed 65 to 85 percent of our consolidated net income. The primary factors that impact the results of our utility operations are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas sales to residential, commercial and public authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Accordingly, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 67 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. Additionally, we typically experience higher levels of accounts receivable, accounts payable, gas stored underground and short-term debt balances during the winter heating season due to the seasonal nature of our revenues and the need to purchase and store gas to support these operations. Utility sales to industrial customers are much less weather sensitive. Utility sales to agricultural customers, which typically use natural gas to power irrigation pumps during the period from March through September, are primarily affected by rainfall amounts and the price of natural gas.
 
Changes in the cost of gas impact revenue but do not directly affect our gross profit from utility operations because the fluctuations in gas prices are passed through to our customers. Accordingly, we believe gross profit margin is a better indicator of our financial performance than revenues. However, higher gas costs may cause customers to conserve, or, in the case of industrial customers, to use alternative energy sources. Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense.
 
The effects of weather that is above or below normal are partially offset through weather normalization adjustments, or WNA, in certain of our service areas. WNA allows us to increase the base rate portion of customers’ bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. As of June 30, 2006, we had, or received regulatory approvals for, WNA covering approximately 1.3 million customer meters in the following service areas for the following periods.
 
         
Georgia
    October – May  
Kansas
    October – May  
Kentucky
    November – April  
Louisiana(1)
    December – March  
Mississippi
    November – April  
Tennessee
    November – April  
Amarillo, Texas
    October – May  
West Texas
    October – May  
Lubbock, Texas
    October – May  
Virginia
    January – December  
 
 
(1) Effective beginning for the 2006-2007 winter heating season.
 
Our Mid-Tex Division did not have WNA as of June 30, 2006. However, its operations benefited from a rate structure that combined a monthly customer charge with a declining block rate schedule to partially mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provided for the recovery of most of our fixed costs for such operations under most weather conditions. However, this rate structure was not as beneficial during periods where weather was significantly warmer than normal.
 
In July 2006, the RRC approved an interim WNA, effective October 1, 2006 for the Mid-Tex Division. The approved WNA period will be October through May. After we filed our May 2006 Statement of Intent, the parties to the case reached an agreement to implement WNA on both an interim and permanent basis. The agreement provided that the interim WNA will use 30 years of weather history, while the permanent WNA will allow the parties to


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contest the appropriate period of weather data to use in calculating normal weather. The permanent WNA will also be modified or adjusted to conform to the rate design that the RRC ultimately approves in the case. With the addition of this interim settlement in the Mid-Tex Division and the LPSC’s May 2006 settlement to authorize our Louisiana Division to implement WNA, we will have weather protection for over 90 percent of our residential and commercial meters for the 2006-2007 winter heating season.
 
Operating income
 
Utility gross profit margin decreased $5.3 million to $169.9 million for the three months ended June 30, 2006 from $175.2 million for the three months ended June 30, 2005. Total throughput for our utility business was 62.3 billion cubic feet (Bcf) during the current-year period compared to 72.7 Bcf in the prior-year period.
 
The decrease in utility gross profit margin and throughput primarily reflects continued warmer-than-normal weather, as adjusted for jurisdictions with weather-normalized rates, primarily in our Mid-Tex and Louisiana divisions, where we did not have weather-normalized rates during the third quarter. Although the heating load is typically smaller during the third fiscal quarter, warmer-than-normal weather can still adversely affect gross profit. Weather was 29 percent warmer than the prior-year quarter and 31 percent warmer than normal. The impact of warmer weather resulted in a $16.2 million reduction in gross profit margin compared with the prior-year quarter. Additionally, our Louisiana division experienced a $1.3 million reduction in gross profit margin during the current-year quarter due to the impact of Hurricane Katrina compared with the prior-year quarter. Finally, continued customer conservation contributed to the decrease. These decreases were partially offset by a $3.9 million increase arising from the Company’s fiscal 2005 and fiscal 2004 filings under Texas’s Gas Reliability Infrastructure Program (GRIP) and the recognition of $6.2 million that had been previously deferred in Louisiana following the LPSC’s ratification of our 2003 RSC in May 2006.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $172.8 million for the three months ended June 30, 2006 from $160.2 million for the three months ended June 30, 2005.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, increased $10.4 million primarily due to higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party, higher medical and dental claims and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Increased line locate and facilities costs also contributed to the increase. These increases were partially offset by lower third-party costs associated with formerly outsourced administrative and meter reading functions that were in-sourced during the first quarter of fiscal 2006 and the reversal of a $2.0 million charge for Hurricane Katrina losses that was originally recorded during the first quarter of fiscal 2006. The accrual was reversed based upon the improved outlook to fully recover our losses from insurance recoveries and from increased rates that we are implementing, subject to refund, in August 2006.
 
The provision for doubtful accounts decreased $1.9 million to $2.1 million for the three months ended June 30, 2006. The decrease primarily was attributable to lower revenues than the prior-year quarter coupled with solid customer account collection efforts. In the utility segment, the average cost of natural gas for the three months ended June 30, 2006 was $7.11 per thousand cubic feet (Mcf), compared with $7.43 per Mcf for the three months ended June 30, 2005.
 
As a result of the aforementioned factors, our utility segment incurred an operating loss of $2.9 million for the three months ended June 30, 2006 compared to operating income of $15.0 million for the three months ended June 30, 2005.
 
Interest charges
 
Interest charges allocated to the utility segment for the three months ended June 30, 2006 increased to $30.9 million from $28.5 million for the three months ended June 30, 2005. The increase was attributable to higher average outstanding short-term debt balances to fund natural gas purchases at significantly higher prices coupled with a 200 basis point increase in the interest rate on our $300 million unsecured floating rate Senior Notes due 2007


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due to an increase in the three-month LIBOR rate. These increases were partially offset by $1.2 million of interest savings arising from the early payoff of $72.5 million of our First Mortgage Bonds in June 2005.
 
 
Our natural gas marketing segment 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 derivative products. 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 for services we deliver.
 
To optimize the storage and transportation capacity we own or control, we 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. Additionally, we engage 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 contracts at advantageous prices to lock in a gross profit margin. Through the use of transportation and storage services and derivative contracts, 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.
 
Operating income
 
Gross profit margin for our natural gas marketing segment consists primarily of storage activities, which are comprised of the optimization of our managed proprietary and third party storage and transportation assets and marketing activities, which represent the utilization of proprietary and customer-owned transportation and storage assets to provide the various services our customers request.
 
Our natural gas marketing segment’s gross profit margin for the three months ended June 30, 2006 and 2005 is summarized as follows:
 
                 
    Three Months Ended
 
    June 30  
    2006     2005  
    (In thousands, except physical position)  
 
Storage Activities
               
Realized margin
  $ 7,717     $ (1,777 )
Unrealized margin
    (21,873 )     961  
                 
Total Storage Activities
    (14,156 )     (816 )
Marketing Activities
               
Realized margin
    12,691       12,347  
Unrealized margin
    579       (1,136 )
                 
Total Marketing Activities
    13,270       11,211  
                 
Gross profit
  $ (886 )   $ 10,395  
                 
Net physical position (Bcf)
    19.0       14.1  
                 
 
Our natural gas marketing segment’s gross profit margin was a loss of $0.9 million for the three months ended June 30, 2006 compared to gross profit of $10.4 million for the three months ended June 30, 2005. Gross profit margin from our natural gas marketing segment for the three months ended June 30, 2006 included an unrealized loss of $21.3 million compared with an unrealized loss of $0.2 million in the prior-year period. Natural gas


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marketing sales volumes were 79.9 Bcf during the three months ended June 30, 2006 compared with 62.8 Bcf for the prior-year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 66.5 Bcf during the current-year period compared with 52.7 Bcf in the prior-year period. The increase in consolidated natural gas marketing sales volumes primarily was attributable to successfully executed marketing strategies into new market areas.
 
Our storage activities incurred a loss of $14.2 million for the three months ended June 30, 2006 compared to a loss of $0.8 million for the three months ended June 30, 2005. Our marketing activities generated $13.3 million for the three months ended June 30, 2006 compared with $11.2 million for the three months ended June 30, 2005. Higher unrealized losses primarily were attributable to unfavorable movements in market prices used to value our physical storage. These unrealized losses were offset by higher realized storage activities due to captured spread arbitrage opportunities that were realized during the current-year quarter.
 
The $11.3 million decrease in our natural gas marketing gross profit margin was primarily due to unfavorable movements during the three months ended June 30, 2006 in the forward natural gas prices used to value the financial hedges designated against our physical inventory and our fixed-price forward contracts. These results in our storage operations were magnified by a 4.9 Bcf increase in our net physical position at June 30, 2006 compared to the prior-year quarter. We have elected to exclude the forward/spot differential from our hedge effectiveness assessment. Subsequent to the hurricanes, which occurred in the fall of 2005, the forward/spot differential has been volatile and may continue to cause material volatility in our unrealized margin. However, the economic gross profit we have captured in the original transactions will remain essentially unchanged.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $6.5 million for the three months ended June 30, 2006 from $5.6 million for the three months ended June 30, 2005. The increase in operating expense primarily was attributable to an increase in personnel costs due to increased headcount and an increase in regulatory compliance costs.
 
The decrease in gross profit margin, combined with higher operating expenses, resulted in a decrease in our natural gas marketing segment operating income to a loss of $7.4 million for the three months ended June 30, 2006 compared with operating income of $4.7 million for the three months ended June 30, 2005.
 
Interest charges
 
Interest charges allocated to the natural gas marketing segment for the three months ended June 30, 2006 increased to $1.7 million from $1.0 million for the three months ended June 30, 2005. The increase was attributable to higher average outstanding debt balances to fund natural gas purchases at significantly higher prices.
 
 
Our pipeline and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC. 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 in the pipeline industry including parking arrangements, blending and sales of inventory on hand. These operations represent one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are believed to contain a substantial portion of the nation’s remaining onshore natural gas reserves. This pipeline system provides access to all of these basins.
 
Atmos Pipeline and Storage, LLC, owns or has an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.
 
Similar to our utility segment, our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas transportation


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requirements are affected by the winter heating season requirements of our customers. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Further, as the Atmos Pipeline — Texas Division operations provide all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of this division.
 
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.
 
Operating income
 
Pipeline and storage gross profit increased to $35.5 million for the three months ended June 30, 2006 from $35.2 million for the three months ended June 30, 2005. Total pipeline transportation volumes were 133.3 Bcf during the three months ended June 30, 2006 compared with 128.5 Bcf for the prior-year quarter. Excluding intersegment transportation volumes, total pipeline transportation volumes were 104.7 Bcf during the current year quarter compared with 97.6 Bcf in the prior-year quarter. The increase was primarily attributable to higher transportation and related services margins in our Atmos Pipeline-Texas Division partially offset by higher unrealized losses recorded by Atmos Pipeline & Storage, LLC.
 
Operating expenses increased to $20.6 million for the three months ended June 30, 2006 from $15.8 million for the three months ended June 30, 2005 due to higher employee benefit costs associated with an increase in headcount, higher medical and dental claims and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Higher pipeline integrity and facilities costs also contributed to the increased level of operating expenses.
 
As a result of the aforementioned factors, our pipeline and storage segment operating income for the three months ended June 30, 2006 decreased to $14.9 million from $19.4 million for the three months ended June 30, 2005.
 
 
Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC (AES), and Atmos Power Systems, Inc. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices in exchange for revenues that 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 have entered into agreements to lease these plants.
 
Operating income for this segment primarily reflects the leasing income associated with two sales-type lease transactions completed in 2001 and 2002 and was essentially unchanged for the three months ended June 30, 2006 compared with the prior-year quarter.
 
  Nine Months Ended June 30, 2006 compared with Nine Months Ended June 30, 2005
 
 
Operating income
 
Utility gross profit increased $10.2 million to $765.8 million for the nine months ended June 30, 2006 from $755.6 million for the nine months ended June 30, 2005. Total throughput for our utility business was 330.9 billion cubic feet (Bcf) during the current-year period compared to 351.7 Bcf in the prior-year period.
 
The increase in utility gross profit, despite lower throughput, primarily reflects higher franchise fees and state gross receipts taxes, which are paid by utility customers and have no permanent effect on net income. Additionally, margins increased $8.3 million due to rate increases received from the Company’s fiscal 2005 and fiscal 2004 GRIP filings and the recognition of $6.2 million that had been previously deferred in Louisiana following the LPSC’s ratification of our agreement in May 2006. These increases were partially offset by an approximate $4.8 million


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decrease in the Louisiana Division due to the impact of Hurricane Katrina compared with the prior-year period. For the nine months ended June 30, 2006, weather was 13 percent warmer than normal, as adjusted for jurisdictions with weather-normalized operations and three percent warmer than the prior-year period. In the Mid-Tex and Louisiana Divisions, which did not have weather-normalized rates during the 2005-2006 winter heating season, weather was 28 percent and 22 percent warmer than normal. The impact of the warmer weather resulted in a $22.1 million reduction in gross profit margin compared with the prior-year period.
 
Operating expenses increased to $544.7 million for the nine months ended June 30, 2006 from $512.3 million for the nine months ended June 30, 2005. The increase reflects a $17.1 million increase in taxes, primarily related to franchise fees and state gross receipts taxes, both of which are calculated as a percentage of revenue, and are paid by our customers as a component of their monthly bills. Although these amounts are included as a component of revenue in accordance with our tariffs, timing differences between when these amounts are billed to our customers and when we recognize the associated expense may affect net income favorably or unfavorably on a temporary basis. However, there is no permanent effect on net income.
 
Operation and maintenance expense, excluding the provision for bad debt, increased $8.4 million primarily due to higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party, higher medical and dental claims and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Increased line locate and facilities costs also contributed to the overall increase. These increases were partially offset by a reduction in third-party costs for outsourced administrative and meter reading functions that were in-sourced during fiscal 2006. Operation and maintenance expense for the nine months ended June 30, 2006 was also favorably impacted by the absence of $2.1 million of United Cities merger and integration cost amortization, as these costs were fully amortized by December 2004.
 
The provision for doubtful accounts increased $4.2 million to $17.5 million for the nine months ended June 30, 2006, compared with $13.3 million in the prior-year period. The increase was primarily attributable to increased collection risk associated with higher natural gas prices. In the utility segment, the average cost of natural gas for the nine months ended June 30, 2006 was $10.39 per Mcf, compared with $7.20 per Mcf for the nine months ended June 30, 2005.
 
Additionally, during the first quarter of fiscal 2006, the Mississippi Public Service Commission, in connection with the modification of our rate design described below under Recent Ratemaking Activity, decided to allow $2.8 million of deferred costs, which it had originally disallowed in its September 2004 decision. This ruling decreased our depreciation expense during the nine months ended June 30, 2006. This decrease was offset by increased depreciation expense associated with the placement of various capital projects into service during the fiscal year.
 
As a result of the aforementioned factors, our utility segment operating income for the nine months ended June 30, 2006 decreased to $221.1 million from $243.3 million for the nine months ended June 30, 2005.
 
Interest charges
 
Interest charges allocated to the utility segment for the nine months ended June 30, 2006 increased to $92.8 million from $83.8 million for the nine months ended June 30, 2005. The increase was attributable to higher average outstanding short-term debt balances to fund natural gas purchases at significantly higher prices coupled with a 200 basis point increase in the interest rate on our $300 million unsecured floating rate Senior Notes due 2007 due to an increase in the three-month LIBOR rate. These increases were partially offset by $3.6 million of interest savings arising from the early payoff of $72.5 million of our First Mortgage Bonds in June 2005.
 
Miscellaneous income
 
Miscellaneous income for the nine months ended June 30, 2006 remained essentially unchanged at $6.0 million compared to $6.1 million for the nine months ended June 30, 2005. However, during the fiscal 2006 second quarter, we recorded a $3.3 million charge associated with an adverse ruling in Tennessee related to the calculation of a performance-based rate mechanism associated with gas purchases. This charge was offset by increased interest


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income associated with intercompany borrowings to our natural gas marketing segment to fund its working capital needs.
 
 
Operating income
 
Our natural gas marketing segment’s gross profit margin for the nine months ended June 30, 2006 and 2005 is summarized as follows:
 
                 
    Nine Months Ended
 
    June 30  
    2006     2005  
    (In thousands, except physical position)  
 
Storage Activities
               
Realized margin
  $ 44,600     $ 15,482  
Unrealized margin
    (42,924 )     (7,065 )
                 
Total Storage Activities
    1,676       8,417  
Marketing Activities
               
Realized margin
    63,263       43,182  
Unrealized margin
    4,471       (3,200 )
                 
Total Marketing Activities
    67,734       39,982  
                 
Gross profit
  $ 69,410     $ 48,399  
                 
Net physical position (Bcf)
    19.0       14.1  
                 
 
Our natural gas marketing segment’s gross profit margin was $69.4 million for the nine months ended June 30, 2006 compared to gross profit of $48.4 million for the nine months ended June 30, 2005. Gross profit margin from our natural gas marketing segment for the nine months ended June 30, 2006 included an unrealized loss of $38.5 million compared with an unrealized loss of $10.3 million in the prior-year period. Natural gas marketing sales volumes were 250.1 Bcf during the nine months ended June 30, 2006 compared with 203.8 Bcf for the prior-year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 207.4 Bcf during the current-year period compared with 179.7 Bcf in the prior-year period. The increase in consolidated natural gas marketing sales volumes was primarily due to focusing our marketing efforts on higher margin opportunities partially offset by warmer-than-normal weather across our market areas.
 
Our storage activities generated $1.7 million in gross profit margin for the nine months ended June 30, 2006 compared to $8.4 million for the nine months ended June 30, 2005. Increased realized margins in our storage operations were primarily due to our ability to capture more favorable arbitrage spreads that arose from increased market volatility. These increases were offset by an increase in the unrealized loss associated with these operations due to an unfavorable movement during the nine months ended June 30, 2006 in the forward natural gas prices used to value the financial hedges designated against our physical inventory and our fixed-price forward contracts. These results were magnified by a 4.9 Bcf increase in our net physical position at June 30, 2006 compared to the prior-year period. As noted above, we have elected to exclude this forward/spot differential from our hedge effectiveness assessment. We continually seek opportunities to increase the amount of our storage capacity. To the extent we obtain and utilize new capacity and experience price volatility, the amount of our unrealized storage contribution could increase in future periods.
 
Our marketing activities generated $67.7 million for the nine months ended June 30, 2006 compared with $40.0 million for the nine months ended June 30, 2005. This increase reflects increased realized margins coupled with a favorable unrealized margin variance compared with the prior-year period. The increase in our realized marketing operations was primarily attributable to successfully capturing increased margins in certain market areas that experienced higher market volatility. The favorable unrealized margin variance was primarily due to favorable


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movement during the nine months ended June 30, 2006 in the forward natural gas prices associated with financial derivatives used in these activities.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $18.2 million for the nine months ended June 30, 2006 from $14.3 million for the nine months ended June 30, 2005. The increase in operating expense primarily was attributable to an increase in personnel costs due to increased headcount and an increase in regulatory compliance costs.
 
The improved gross profit margin partially offset by higher operating expenses resulted in an increase in our natural gas marketing segment operating income to $51.2 million for the nine months ended June 30, 2006 compared with operating income of $34.1 million for the nine months ended June 30, 2005.
 
Interest charges
 
Interest charges allocated to the natural gas marketing segment for the nine months ended June 30, 2006 increased to $6.6 million from $2.0 million for the nine months ended June 30, 2005. The increase was attributable to higher average outstanding debt balances to fund natural gas purchases at significantly higher prices.
 
 
Operating income
 
Pipeline and storage gross profit increased to $120.5 million for the nine months ended June 30, 2006 from $113.8 million for the nine months ended June 30, 2005. Total pipeline transportation volumes were 431.2 Bcf during the nine months ended June 30, 2006 compared with 417.4 Bcf for the prior-year period. Excluding intersegment transportation volumes, total pipeline transportation volumes were 277.7 Bcf during the current year period compared with 254.5 Bcf in the prior-year period. The increase in gross profit was primarily attributable to higher transportation and related services margins coupled with increased throughput on our Atmos Pipeline-Texas system and Atmos Pipeline & Storage, LLC’s ability to capture more favorable arbitrage spreads in its asset management contracts. These increases were partially offset by the absence of inventory sales of $3.0 million realized in the prior-year period.
 
Operating expenses increased to $57.9 million for the nine months ended June 30, 2006 from $51.8 million for the nine months ended June 30, 2005 due to higher employee benefit costs associated with the increase in headcount, increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs and higher facilities costs.
 
As a result of the aforementioned factors, our pipeline and storage segment operating income for the nine months ended June 30, 2006 increased to $62.6 million from $62.0 million for the nine months ended June 30, 2005.
 
 
Operating income for this segment primarily reflects the leasing income associated with two sales-type lease transactions completed in 2001 and 2002 and was essentially unchanged for the nine months ended June 30, 2006 compared with the prior-year period.
 
 
Our working capital and liquidity for capital expenditures and other cash needs are provided from internally generated funds, borrowings under our credit facilities and commercial paper program. We believe that these sources of funds will provide the necessary working capital and liquidity for capital expenditures and other cash needs for the remainder of fiscal 2006. Additionally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.


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The following table presents our capitalization as of June 30, 2006 and September 30, 2005:
 
                                 
    June 30, 2006     September 30, 2005  
    (In thousands, except percentages)  
 
Short-term debt
  $ 297,087       7.2 %   $ 144,809       3.7 %
Long-term debt
    2,184,083       52.7 %     2,186,368       55.6 %
Shareholders’ equity
    1,664,556       40.1 %     1,602,422       40.7 %
                                 
Total capitalization, including short-term debt
  $ 4,145,726       100.0 %   $ 3,933,599       100.0 %
                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 59.9 percent at June 30, 2006, and 59.3 percent at September 30, 2005. The increase in the debt to capitalization ratio was primarily attributable to an increase in our short-term debt borrowings to fund our working capital needs partially offset by current-year net income. Our ratio of total debt to capitalization is typically greater during the winter heating season as we make additional short-term borrowings to fund natural gas purchases and meet our working capital requirements. Within two to four years, we intend to reduce our capitalization ratio to 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, access to the equity capital markets and reduced annual maintenance and capital expenditures.
 
 
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.
 
 
Period-over-period changes in our operating cash flows primarily are attributable to changes in net income, working capital changes, particularly within our utility segment resulting from the impact of weather, the 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, 2006, we generated operating cash flow of $223.4 million from operating activities compared with $387.4 million for the nine months ended June 30, 2005. Period over period, our operating cash flow was adversely impacted by significantly higher natural gas prices, which have increased the levels of accounts payable and undercollected deferred gas costs recorded on our balance sheet as of June 30, 2006. However, we are beginning to see the adverse impact of this situation decline somewhat as declines in accounts receivable and natural gas inventories improved operating cash flow by $79.7 million compared with the prior-year period. Additionally, favorable movements in the market indices used to value our natural gas marketing segment risk management assets and liabilities reduced the amount that we were required to deposit in a margin account and therefore favorably affected operating cash flow by $45.4 million. However, these improvements in cash flow were offset by an unfavorable timing of payments for accounts payable and other accrued liabilities ($251.4 million) and unfavorable timing differences between when we purchase our natural gas and the period in which we can include this cost in our gas rates ($54.3 million). Finally, other working capital and other changes increased operating cash flow by $16.6 million.
 
 
During the last three years, a substantial portion of our cash resources was used to fund acquisitions, 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, to expand our natural gas distribution services into new markets, to enhance the integrity of our pipelines and, more recently, to expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to


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jurisdictions that permit us to earn a return on our investment timely. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas utility 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 having to file a rate case.
 
Capital expenditures for fiscal 2006 are expected to range from $400 million to $415 million. For the nine months ended June 30, 2006, we incurred $322.7 million for capital expenditures compared with $226.9 million for the nine months ended June 30, 2005. The increase in capital expenditures primarily reflects increased spending associated with our Dallas/Fort Worth Metroplex North Side Loop project and other pipeline expansion projects in our Atmos Pipeline — Texas Division, which were completed during the fiscal 2006 third quarter. Increased capital spending in our Mid-Tex Division for various projects contributed to the increase in our capital expenditures.
 
 
For the nine months ended June 30, 2006, our financing activities provided $90.8 million in cash compared with $1.6 billion provided in the prior-year period. Our significant financing activities for the nine months ended June 30, 2006 and 2005 are summarized as follows. The adoption of SFAS 123(R) did not materially affect our cash flows from financing activities.
 
  •  In October 2004, we sold 16.1 million shares of common stock, including the underwriters’ exercise of their overallotment option of 2.1 million shares, under a new shelf registration statement declared effective in September 2004, generating net proceeds of $382 million. Additionally, we issued $1.39 billion of senior unsecured debt under our shelf registration statement. The net proceeds from these issuances, combined with the net proceeds from our July 2004 offering were used to finance the acquisition of our Mid-Tex and Atmos Pipeline — Texas divisions and settle Treasury lock agreements, into which we entered to fix the Treasury yield component of the interest cost of financing associated with $875 million of the $1.39 billion long-term debt we issued in October 2004 to fund the acquisition.
 
  •  During the nine months ended June 30, 2006 we increased our borrowings under our credit facilities by $152.3 million. All amounts borrowed under our credit facilities were repaid during the nine months ended June 30, 2005. The increase reflects borrowings to fund natural gas purchases and other working capital needs.
 
  •  We repaid $2.6 million of long-term debt during the nine months ended June 30, 2006 compared with $102.8 million during the nine months ended June 30, 2005. The prior-year payments reflect the repayment of $72.5 million on our First Mortgage Bonds and a $25.0 million make-whole premium in accordance with the terms of the agreements.
 
  •  During the nine months ended June 30, 2006 we paid $76.6 million in cash dividends compared with dividend payments of $74 million for the nine months ended June 30, 2005. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.930 per share during the nine months ended June 30, 2005 to $0.945 per share during the nine months ended June 30, 2006 combined with new share issuances under our various plans.


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  •  During the nine months ended June 30, 2006 we issued 0.7 million shares of common stock which generated net proceeds of $17.7 million. In addition, we granted 0.3 million shares of common stock under our Long-Term Incentive Plan. The following table summarizes the issuances for the nine months ended June 30, 2006 and 2005.
 
                 
    Nine Months Ended
 
    June 30  
    2006     2005  
 
Shares issued:
               
Retirement Savings Plan
    344,573       338,520  
Direct Stock Purchase Plan
    302,501       353,512  
Outside Directors Stock-for-Fee Plan
    1,865       1,769  
Long-Term Incentive Plan
    349,509       655,684  
Long-Term Stock Plan for Mid-States Division
    300        
Public Offering
          16,100,000  
                 
Total shares issued
    998,748       17,449,485  
                 
 
   Shelf Registration
 
In August 2004, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $2.2 billion in new common stock and/or debt, which became effective on September 15, 2004. In October 2004, we sold 16.1 million common shares and issued $1.4 billion in unsecured senior notes to partially finance the acquisition of our Mid-Tex and Atmos Pipeline — Texas divisions. After these issuances, we have approximately $401.5 million of availability remaining under the registration statement.
 
   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 charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather. Our cash needs for working capital have increased substantially as a result of the significant increase in the price of natural gas.
 
In October 2005, our $600 million 364-day committed credit facility expired and was replaced with a new $600 million three-year revolving credit facility that became effective October 18, 2005. In addition, on November 10, 2005, we entered into a new $300 million 364-day revolving credit facility with substantially the same terms as our $600 million credit facility.
 
On November 28, 2005, AEM amended its uncommitted demand working capital credit facility to increase the amount of credit available from $250 million to a maximum of $580 million. On March 31, 2006, AEM amended and extended this uncommitted demand working capital credit facility to March 31, 2007. At June 30, 2006, there were no borrowings outstanding under this facility.
 
On April 1, 2006, our $18 million committed unsecured credit facility was renewed for one year with no material changes to its terms and pricing. At June 30, 2006, there was $15.2 million outstanding under this facility.
 
As of June 30, 2006, the amount available to us under our credit facilities, net of outstanding letters of credit, was $770.6 million. We believe these credit facilities, combined with our operating cash flows will be sufficient to fund our increased working capital needs. These facilities are described in further detail in Note 4 to the condensed consolidated financial statements.


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   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, 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 utility and nonutility 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: