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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 March 31, 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 April 28, 2006.
 
     
Class
 
Shares Outstanding
 
No Par Value   81,151,592
 


 
TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART 1. 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 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits
SIGNATURES
EXHIBITS INDEX
Computation of Ratio of Earnings to Fixed Charges
Letter Regarding Unaudited Interim Financial Information
Certification Pursuant to Rule 13a-14(a)/15d-14(a)
Certification Pursuant to Section 1350


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
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
TRA
  Tennessee Regulatory Authority
TXU Gas
  TXU Gas Company, which was acquired on October 1, 2004
WNA
  Weather Normalization Adjustment


1


Table of Contents

 
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    March 31,
    September 30,
 
    2006     2005  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 4,943,329     $ 4,765,610  
Less accumulated depreciation and amortization
    1,432,287       1,391,243  
                 
Net property, plant and equipment
    3,511,042       3,374,367  
Current assets
               
Cash and cash equivalents
    48,899       40,116  
Cash held on deposit in margin account
    13,537       80,956  
Accounts receivable, net
    793,019       454,313  
Gas stored underground
    440,946       450,807  
Other current assets
    195,412       238,238  
                 
Total current assets
    1,491,813       1,264,430  
Goodwill and intangible assets
    737,495       737,787  
Deferred charges and other assets
    256,701       276,943  
                 
    $ 5,997,051     $ 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:
March 31, 2006 — 81,077,197 shares;
September 30, 2005 — 80,539,401 shares
  $ 405     $ 403  
Additional paid-in capital
    1,447,734       1,426,523  
Retained earnings
    287,727       178,837  
Accumulated other comprehensive loss
    (29,575 )     (3,341 )
                 
Shareholders’ equity
    1,706,291       1,602,422  
Long-term debt
    2,181,120       2,183,104  
                 
Total capitalization
    3,887,411       3,785,526  
Current liabilities
               
Accounts payable and accrued liabilities
    708,134       461,314  
Other current liabilities
    380,026       503,368  
Short-term debt
    262,315       144,809  
Current maturities of long-term debt
    3,308       3,264  
                 
Total current liabilities
    1,353,783       1,112,755  
Deferred income taxes
    287,841       292,207  
Regulatory cost of removal obligation
    275,209       263,424  
Deferred credits and other liabilities
    192,807       199,615  
                 
    $ 5,997,051     $ 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
 
    March 31  
    2006     2005  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Utility segment
  $ 1,447,620     $ 1,235,377  
Natural gas marketing segment
    818,629       512,891  
Pipeline and storage segment
    45,483       45,546  
Other nonutility segment
    1,595       1,278  
Intersegment eliminations
    (279,481 )     (110,007 )
                 
      2,033,846       1,685,085  
Purchased gas cost
               
Utility segment
    1,131,885       912,309  
Natural gas marketing segment
    774,652       501,731  
Pipeline and storage segment
    211       4,407  
Other nonutility segment
           
Intersegment eliminations
    (278,305 )     (109,256 )
                 
      1,628,443       1,309,191  
                 
Gross profit
    405,403       375,894  
Operating expenses
               
Operation and maintenance
    112,698       103,420  
Depreciation and amortization
    47,076       45,326  
Taxes, other than income
    64,796       54,967  
                 
Total operating expenses
    224,570       203,713  
                 
Operating income
    180,833       172,181  
Miscellaneous (expense) income
    (2,439 )     958  
Interest charges
    35,492       33,073  
                 
Income before income taxes
    142,902       140,066  
Income tax expense
    54,106       51,564  
                 
Net income
  $ 88,796     $ 88,502  
                 
Basic net income per share
  $ 1.10     $ 1.12  
                 
Diluted net income per share
  $ 1.10     $ 1.11  
                 
Cash dividends per share
  $ 0.315     $ 0.310  
                 
Weighted average shares outstanding:
               
Basic
    80,573       79,270  
                 
Diluted
    81,040       79,760  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Six Months Ended
 
    March 31  
    2006     2005  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Utility segment
  $ 2,852,630     $ 2,149,058  
Natural gas marketing segment
    1,920,474       1,006,692  
Pipeline and storage segment
    85,195       89,236  
Other nonutility segment
    3,087       2,637  
Intersegment eliminations
    (543,720 )     (193,914 )
                 
      4,317,666       3,053,709  
Purchased gas cost
               
Utility segment
    2,256,714       1,568,679  
Natural gas marketing segment
    1,850,178       968,688  
Pipeline and storage segment
    211       10,628  
Other nonutility segment
           
Intersegment eliminations
    (541,430 )     (192,283 )
                 
      3,565,673       2,355,712  
                 
Gross profit
    751,993       697,997  
Operating expenses
               
Operation and maintenance
    220,915       214,197  
Depreciation and amortization
    90,336       89,323  
Taxes, other than income
    110,212       93,622  
                 
Total operating expenses
    421,463       397,142  
                 
Operating income
    330,530       300,855  
Miscellaneous (expense) income
    (1,991 )     1,343  
Interest charges
    71,681       65,615  
                 
Income before income taxes
    256,858       236,583  
Income tax expense
    97,035       88,482  
                 
Net income
  $ 159,823     $ 148,101  
                 
Basic net income per share
  $ 1.99     $ 1.92  
                 
Diluted net income per share
  $ 1.98     $ 1.90  
                 
Cash dividends per share
  $ 0.63     $ 0.62  
                 
Weighted average shares outstanding:
               
Basic
    80,444       77,290  
                 
Diluted
    80,911       77,769  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
 
                 
    Six Months Ended
 
    March 31  
    2006     2005  
    (Unaudited)
 
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 159,823     $ 148,101  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    90,336       89,323  
Charged to other accounts
    334       477  
Deferred income taxes
    58,199       42,605  
Other
    7,587       3,315  
Net assets/liabilities from risk management activities
    (24,041 )     20,247  
Net change in operating assets and liabilities
    (143,847 )     96,025  
                 
Net cash provided by operating activities
    148,391       400,093  
Cash Flows From Investing Activities
               
Capital expenditures
    (213,230 )     (137,466 )
Acquisitions
          (1,912,532 )
Other, net
    (2,842 )     (1,957 )
                 
Net cash used in investing activities
    (216,072 )     (2,051,955 )
Cash Flows From Financing Activities
               
Net increase in short-term debt
    117,506        
Net proceeds from issuance of long-term debt
          1,385,847  
Repayment of long-term debt
    (2,162 )     (3,849 )
Settlement of Treasury lock agreements
          (43,770 )
Cash dividends paid
    (50,933 )     (49,211 )
Issuance of common stock
    12,053       26,025  
Net proceeds from equity offering
          382,014  
                 
Net cash provided by financing activities
    76,464       1,697,056  
                 
Net increase in cash and cash equivalents
    8,783       45,194  
Cash and cash equivalents at beginning of period
    40,116       201,932  
                 
Cash and cash equivalents at end of period
  $ 48,899     $ 247,126  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 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 construct gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell 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 six-month periods ended March 31, 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 six months ended March 31, 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 and 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 six months ended March 31, 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 six months ended March 31, 2006 was $0.3 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 six months ended March 31, 2006 was $0.8 million and $2.2 million as compared to $0.7 million and $1.5 million for the three and six months ended March 31, 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 six months ended March 31, 2005 would have been impacted as shown in the following table:
 
                 
    Three Months Ended
    Six Months Ended
 
    March 31, 2005     March 31, 2005  
    (In thousands, except per share data)  
 
Net income — as reported
  $ 88,502     $ 148,101  
Restricted stock compensation expense included in income, net of tax
    469       962  
Total stock-based employee compensation expense determined under fair-value- based method for all awards, net of taxes
    (684 )     (1,427 )
                 
Net income — pro forma
  $ 88,287     $ 147,636  
                 
Earnings per share:
               
Basic earnings per share — as reported
  $ 1.12     $ 1.92  
                 
Basic earnings per share — pro forma
  $ 1.11     $ 1.91  
                 
Diluted earnings per share — as reported
  $ 1.11     $ 1.90  
                 
Diluted earnings per share — pro forma
  $ 1.11     $ 1.90  
                 
 
 
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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Table of Contents

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

 
Significant regulatory assets and liabilities as of March 31, 2006 and September 30, 2005 included the following:
 
                 
    March 31,
    September 30,
 
    2006     2005  
    (In thousands)  
 
Regulatory assets:
               
Merger and integration costs, net
  $ 8,980     $ 9,150  
Deferred gas cost
    108,130       38,173  
Environmental costs
    1,268       1,357  
Rate case costs
    9,256       11,314  
Deferred franchise fees
    142       6,710  
Other
    9,019       9,313  
                 
    $ 136,795     $ 76,017  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 29,258     $ 134,048  
Regulatory cost of removal obligation
    286,894       274,989  
Deferred income taxes, net
    3,185       3,185  
Other
    7,075       8,084  
                 
    $ 326,412     $ 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 regulatory commissions.


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Table of Contents

 
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 six-month periods ended March 31, 2006 and 2005:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2006     2005     2006     2005  
    (In thousands)  
 
Net income
  $ 88,796     $ 88,502     $ 159,823     $ 148,101  
Unrealized holding gains on investments, net of tax expense of $294 and $80 for the three months ended March 31, 2006 and 2005 and of $542 and $729 for the six months ended March 31, 2006 and 2005
    479       132       884       1,189  
Amortization and unrealized losses on interest rate hedging transactions, net of tax expense (benefit) of $527 and $527 for the three months ended March 31, 2006 and 2005 and $1,055 and $(2,718) for the six months ended March 31, 2006 and 2005
    861       861       1,721       (4,435 )
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $(2,927) and $7,915 for the three months ended March 31, 2006 and 2005 and $(17,676) and $3 for the six months ended March 31, 2006 and 2005
    (4,776 )     12,913       (28,839 )     5  
                                 
Comprehensive income
  $ 85,360     $ 102,408     $ 133,589     $ 144,860  
                                 
 
Accumulated other comprehensive loss, net of tax, as of March 31, 2006 and September 30, 2005 consisted of the following unrealized gains (losses):
 
                 
    March 31,
    September 30,
 
    2006     2005  
    (In thousands)  
 
Accumulated other comprehensive loss:
               
Unrealized holding gains on investments
  $ 1,568     $ 684  
Treasury lock agreements
    (22,261 )     (23,982 )
Cash flow hedges
    (8,882 )     19,957  
                 
    $ (29,575 )   $ (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 and 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 for securities which 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.
 
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.


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

 
The following table shows the fair values of our risk management assets and liabilities by segment at March 31, 2006 and September 30, 2005:
 
                         
          Natural Gas
       
    Utility     Marketing     Total  
    (In thousands)  
 
March 31, 2006:
                       
Assets from risk management activities, current
  $ 13,419     $ 15,977     $ 29,396  
Assets from risk management activities, noncurrent
                 
Liabilities from risk management activities, current
    (1,067 )     (17,530 )     (18,597 )
Liabilities from risk management activities, noncurrent
          (1,861 )     (1,861 )
                         
Net assets (liabilities)
  $ 12,352     $ (3,414 )   $ 8,938  
                         
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.
 
 
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 six-month periods ended March 31, 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 six months ended March 31, 2006 of $8.2 million in net deferred hedging gains ($7.1 million in net deferred hedging losses during the three months ended March 31, 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. Substantially all of the deferred hedging balance as of March 31, 2006 is expected to be recognized in net income in fiscal 2006 along with the corresponding hedged purchases and sales of natural gas.
 
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


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

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 March 31, 2006, AEH had a net open position (including existing storage) of 0.3 Bcf.
 
 
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 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 six-month periods ended March 31, 2006, we recognized approximately $1.4 million and $2.8 million of this amount as a component of interest expense.
 
4.   Debt
 
 
Long-term debt at March 31, 2006 and September 30, 2005 consisted of the following:
 
                 
    March 31,
    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
    6,927       7,839  
                 
Total long-term debt
    2,187,980       2,190,142  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (3,552 )     (3,774 )
Current maturities
    (3,308 )     (3,264 )
                 
    $ 2,181,120     $ 2,183,104  
                 


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

 
Our unsecured floating rate debt bears interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At March 31, 2006, the interest rate on our floating rate debt was 4.975 percent.
 
 
At March 31, 2006 and September 30, 2005, there was $262.3 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 March 31, 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 as a backup liquidity facility for our $600 million commercial paper program. At March 31, 2006, there was $262.3 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 March 31, 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. There were no borrowings outstanding under this facility at March 31, 2006.
 
The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in 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 March 31, 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


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

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 March 31, 2006, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.21 to 1.
 
At March 31, 2006, there were no borrowings outstanding under this credit facility. However, at March 31, 2006, AEM letters of credit totaling $151.8 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 $174.2 million at March 31, 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 March 31, 2006, but letters of credit reduced the amount available by $4.5 million. This uncommitted line is renewed or renegotiated at least annually with varying terms, and we pay no fee for the availability of the line. Borrowings under this line are made on a when-and-as-available basis at the discretion of the bank.
 
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 March 31, 2006, $65.1 million was outstanding under this facility.
 
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 March 31, 2006, $62 million was outstanding under this facility.
 
 
We have other covenants in addition to those described above. Our Series P First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, 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 March 31, 2006 approximately $266.8 million of retained earnings was unrestricted with respect to the payment of dividends.
 
We were in compliance with all of our debt covenants as of March 31, 2006. If we do not comply with our debt covenants, we may 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


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

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 March 31, 2006, non-qualified stock options, bonus stock, time-lapse restricted stock, performance-based restricted stock units and stock units have been issued under this plan and 1,064,624 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:
 
                 
    Six Months Ended
 
    March 31  
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.


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

 
A summary of option activity as of March 31, 2006, and changes during the six months then ended, is presented below:
 
                                 
                Weighted-
       
          Weighted-
    Average
       
          Average
    Remaining
    Aggregate
 
    Number 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
    (2,166 )     20.18                  
Forfeited
    (166 )     21.23                  
                                 
Outstanding at March 31, 2006
    1,055,568     $ 22.56       5.9     $ 3,840  
                                 
Exercisable at March 31, 2006
    1,028,794     $ 22.48       5.8     $ 3,741  
                                 
 
The stock options had a weighted-average fair value per share on the date of grant of $3.74 and $3.69 for the six months ended March 31, 2006 and 2005. There were no stock options granted during the three months ended March 31, 2006 and 2005. Net cash proceeds from the exercise of stock options during the six months ended March 31, 2006 and 2005 were less than $0.1 million and $9.1 million and during the three months ended March 31, 2006 and 2005 were less than $0.1 and $8 million. The associated income tax benefit from stock options exercised during the six months ended March 31, 2006 and 2005 was less than $0.1 million and $1 million, and during the three months ended March 31, 2006 and 2005 was less than $0.1 million and $0.9 million. The total intrinsic value of options exercised during the six months ended March 31, 2006 and 2005 was less than $0.1 million and $1.5 million, and during the three months ended March 31, 2006 and 2005 was less than $0.1 million and $1.3 million.
 
As of March 31, 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 1.7 years.
 
 
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 March 31, 2006, and changes during the six 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
    83,941       26.19  
Vested
    (76,190 )     21.33  
Forfeited
    (1,428 )     25.55  
                 
Nonvested at March 31, 2006
    598,813     $ 25.95  
                 


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

 
As of March 31, 2006, there was $8.8 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 1.7 years. The total fair value of restricted stock vested during the six months ended March 31, 2006 and 2005 was $1.6 million and $0.5 million, and during the three months ended March 31, 2006 was $1.2 million. There were no restricted stock grants that vested during the three months ended March 31, 2005.
 
6.   Earnings Per Share
 
Basic and diluted earnings per share for the three and six months ended March 31, 2006 and 2005 are calculated as follows:
 
                                 
    For the
    For the
 
    Three Months
    Six Months
 
    Ended
    Ended
 
    March 31     March 31  
    2006     2005     2006     2005  
    (In thousands, except per share amounts)  
 
Net income
  $ 88,796     $ 88,502     $ 159,823     $ 148,101  
                                 
Denominator for basic income per share — weighted average common shares
    80,573       79,270       80,444       77,290  
Effect of dilutive securities:
                               
Restricted and other shares
    369       335       369       330  
Stock options
    98       155       98       149  
                                 
Denominator for diluted income per share — weighted average common shares
    81,040       79,760       80,911       77,769  
                                 
Income per share — basic
  $ 1.10     $ 1.12     $ 1.99     $ 1.92  
                                 
Income per share — diluted
  $ 1.10     $ 1.11     $ 1.98     $ 1.90  
                                 
 
There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2006 and 2005 as their exercise price was less than the average market price of the common stock during that period.


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

 
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 six months ended March 31, 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 March 31  
    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  
                                 
 
                                 
    Six Months Ended March 31  
    Pension Benefits     Other Benefits  
    2006     2005     2006     2005  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 8,234     $ 6,272     $ 6,542     $ 4,956  
Interest cost
    11,444       12,034       4,420       4,732  
Expected return on assets
    (12,800 )     (13,770 )     (1,094 )     (1,036 )
Amortization of transition asset
          2       756       756  
Amortization of prior service cost
    32       (4 )     180       192  
Amortization of actuarial loss
    6,598       3,782       640       302  
                                 
Net periodic pension cost
  $ 13,508     $ 8,316     $ 11,444     $ 9,902  
                                 
 
The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 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 %
 
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 six months ended March 31, 2006, we did not make a voluntary contribution to our pension plans. However, we contributed $5.3 million to our other postretirement plans and we expect to contribute approximately $12 million to these plans during fiscal 2006.


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

 
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 six months ended March 31, 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 March 31, 2006, AEM was committed to purchase 64.2 Bcf within one year, 33.1 Bcf within one to three years and 5.4 Bcf after three years under indexed contracts. AEM is committed to purchase 1.6 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $6.00 to $12.00. Purchases under these contracts totaled $531.8 million and $345.3 million for the three months ended March 31, 2006 and 2005 and $1,319.5 million and $705.4 million for the six months ended March 31, 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 March 31, 2006 are as follows (in thousands):
 
         
2006
  $ 136,543  
2007
    241,031  
2008
    121,079  
2009
    12,022  
2010
    11,263  
Thereafter
    37,616  
         
    $ 559,554  
         
 
 
In February 2005, the Attorney General of the State of Kentucky filed a complaint at the Kentucky Public Service Commission (KPSC) alleging that our present rates are 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.


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

 
In August 2005, we received a “show cause” order from the City of Dallas, which requires us to provide information that demonstrates good cause for showing that our existing distribution rates charged to customers in the City of Dallas should not be reduced. In addition, during the first quarter of fiscal 2006, approximately 80 other cities in the Mid-Tex Division passed resolutions requesting that we “show cause” why existing distribution rates are just and reasonable and required a filing by us on a system-wide basis. We filed our response to these orders during the first quarter of fiscal 2006. Discovery has been conducted by the City of Dallas and the other cities. The 80 cities that acted in the first quarter of fiscal year 2006 have begun adopting resolutions requiring a reduction in the Mid-Tex Division’s residential and commercial rates. We will be appealing these city actions to the Railroad Commission of Texas (RRC) where we believe that we will be able to demonstrate that our rates are just and reasonable.
 
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 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 is scheduled to consider the Staff’s recommendation on May 15, 2006. We believe that we are not overcharging our customers, and we intend to participate fully in the investigation.
 
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.
 
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 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. Approximately 21 miles of the pipeline was placed in service as of March 31, 2006. The remainder of the pipeline and the associated compressors are expected to be placed in service by the end of May 2006. As of March 31, 2006, we had spent $26.2 million for the North Side Loop project and expect to spend approximately $23.6 million in the remainder of fiscal 2006 for this project.
 
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 will install compression equipment and other pipeline infrastructure. We expect to spend approximately $32 million in fiscal 2006 for these projects, which are expected to be in service by the end of the fiscal year.
 
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. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. As of March 31, 2006, we believe adequate provision has been made for any losses that may not be fully recovered through insurance or for which we do not receive rate relief.


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

 
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, (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 March 31, 2006 and September 30, 2005.
 
                 
    March 31,
    September 30,
 
    2006     2005  
 
Investment grade
    42 %     49 %
Non-investment grade
    58 %     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 March 31, 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.
 
                         
    March 31, 2006  
          Natural Gas
       
    Utility
    Marketing
       
    Segment(1)     Segment     Consolidated  
    (In thousands)  
 
Investment grade counterparties
  $ 13,419     $ 11,232     $ 24,651  
Non-investment grade counterparties
          4,745       4,745  
                         
    $ 13,419     $ 15,977     $ 29,396  
                         
 
 
(1) Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers.


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

 
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,
 
  •  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.


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

 
Income statements for the three and six-month periods ended March 31, 2006 and 2005 by segment are presented in the following tables:
 
                                                 
    Three Months Ended March 31, 2006  
                Pipeline
                   
          Natural Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,447,376     $ 564,737     $ 21,238     $ 495     $     $ 2,033,846  
Intersegment revenues
    244       253,892       24,245       1,100       (279,481 )      
                                                 
      1,447,620       818,629       45,483       1,595       (279,481 )     2,033,846  
Purchased gas cost
    1,131,885       774,652       211             (278,305 )     1,628,443  
                                                 
Gross profit
    315,735       43,977       45,272       1,595       (1,176 )     405,403  
Operating expenses
                                               
Operation and maintenance
    94,363       5,821       12,363       1,361       (1,210 )     112,698  
Depreciation and amortization
    41,907       475       4,669       25             47,076  
Taxes, other than income
    61,701       348       2,654       93             64,796  
                                                 
Total operating expenses
    197,971       6,644       19,686       1,479       (1,210 )     224,570  
                                                 
Operating income
    117,764       37,333       25,586       116       34       180,833  
Miscellaneous income (expense)
    155       608       132       1,183       (4,517 )     (2,439 )
Interest charges
    30,303       1,997       6,621       1,054       (4,483 )     35,492  
                                                 
Income before income taxes
    87,616       35,944       19,097       245             142,902  
Income tax expense
    32,988       14,012       7,010       96             54,106  
                                                 
Net income
  $ 54,628     $ 21,932     $ 12,087     $ 149     $     $ 88,796  
                                                 
Capital expenditures
  $ 83,749     $ 235     $ 26,781     $     $     $ 110,765  
                                                 
 


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

                                                 
    Three Months Ended March 31, 2005  
                Pipeline
                   
          Natural Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,235,092     $ 429,598     $ 19,827     $ 568     $     $ 1,685,085  
Intersegment revenues
    285       83,293       25,719       710       (110,007 )      
                                                 
      1,235,377       512,891       45,546       1,278       (110,007 )     1,685,085  
Purchased gas cost
    912,309       501,731       4,407             (109,256 )     1,309,191  
                                                 
Gross profit
    323,068       11,160       41,139       1,278       (751 )     375,894  
Operating expenses
                                               
Operation and maintenance
    86,469       4,016       12,843       893       (801 )     103,420  
Depreciation and amortization
    41,181       474       3,642       29             45,326  
Taxes, other than income
    52,220       261       2,398       88             54,967  
                                                 
Total operating expenses
    179,870       4,751       18,883       1,010       (801 )     203,713  
                                                 
Operating income
    143,198       6,409       22,256       268       50       172,181  
Miscellaneous income
    1,974       201       292       616       (2,125 )     958  
Interest charges
    28,062       679       6,228       179       (2,075 )     33,073  
                                                 
Income before income taxes
    117,110       5,931       16,320       705             140,066  
Income tax expense
    43,459       2,140       5,682       283             51,564  
                                                 
Net income
  $ 73,651     $ 3,791     $ 10,638     $ 422     $     $ 88,502  
                                                 
Capital expenditures
  $ 63,129     $ 228     $ 6,908     $     $     $ 70,265  
                                                 
 

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

                                                 
    Six Months Ended March 31, 2006  
                Pipeline
                   
          Natural Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,852,182     $ 1,425,350     $ 39,119     $ 1,015     $     $ 4,317,666  
Intersegment revenues
    448       495,124       46,076       2,072       (543,720 )      
                                                 
      2,852,630       1,920,474       85,195       3,087       (543,720 )     4,317,666  
Purchased gas cost
    2,256,714       1,850,178       211             (541,430 )     3,565,673  
                                                 
Gross profit
    595,916       70,296       84,984       3,087       (2,290 )     751,993  
Operating expenses
                                               
Operation and maintenance
    187,129       10,173       23,361       2,626       (2,374 )     220,915  
Depreciation and amortization
    80,171       945       9,171       49             90,336  
Taxes, other than income
    104,603       591       4,814       204             110,212  
                                                 
Total operating expenses
    371,903       11,709       37,346       2,879       (2,374 )     421,463  
                                                 
Operating income
    224,013       58,587       47,638       208       84       330,530  
Miscellaneous income (expense)
    2,992       1,198       1,537       1,844       (9,562 )     (1,991 )
Interest charges
    61,891       4,859       12,594       1,815       (9,478 )     71,681  
                                                 
Income before income taxes
    165,114       54,926       36,581       237             256,858  
Income tax expense
    62,073       21,542       13,327       93             97,035  
                                                 
Net income
  $ 103,041     $ 33,384     $ 23,254     $ 144     $     $ 159,823  
                                                 
Capital expenditures
  $ 156,164     $ 567     $ 56,499     $     $     $ 213,230  
                                                 
 

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

                                                 
    Six Months Ended March 31, 2005  
                Pipeline
                   
          Natural Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,148,498     $ 862,508     $ 41,579     $ 1,124     $     $ 3,053,709  
Intersegment revenues
    560       144,184       47,657       1,513       (193,914 )      
                                                 
      2,149,058       1,006,692       89,236       2,637       (193,914 )     3,053,709  
Purchased gas cost
    1,568,679       968,688       10,628             (192,283 )     2,355,712  
                                                 
Gross profit
    580,379       38,004       78,608       2,637       (1,631 )     697,997  
Operating expenses
                                               
Operation and maintenance
    183,022       7,462       23,504       1,940       (1,731 )     214,197  
Depreciation and amortization
    80,232       978       8,055       58             89,323  
Taxes, other than income
    88,840       170       4,446       166             93,622  
                                                 
Total operating expenses
    352,094       8,610       36,005       2,164       (1,731 )     397,142  
                                                 
Operating income
    228,285       29,394       42,603       473       100       300,855  
Miscellaneous income
    2,946       447       607       1,209       (3,866 )     1,343  
Interest charges
    55,321       1,080       12,399       581       (3,766 )     65,615  
                                                 
Income before income taxes
    175,910       28,761       30,811       1,101             236,583  
Income tax expense
    65,236       11,708       11,089       449             88,482  
                                                 
Net income
  $ 110,674     $ 17,053     $ 19,722     $ 652     $     $ 148,101  
                                                 
Capital expenditures
  $ 129,056     $ 367     $ 8,043     $     $     $ 137,466  
                                                 

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

 
Balance sheet information at March 31, 2006 and September 30, 2005 by segment is presented in the following tables:
 
                                                 
    March 31, 2006  
          Natural
    Pipeline
                   
          Gas
    and
    Other
             
    Utility     Marketing     Storage     Nonutility     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
Property, plant and equipment, net
  $ 3,015,227     $ 7,203     $ 487,264     $ 1,348     $     $ 3,511,042  
Investment in subsidiaries
    259,284       (2,086 )                 (257,198 )      
Current assets
                                               
Cash and cash equivalents
    26,849       21,532             518             48,899  
Cash held on deposit in margin account
          13,537                         13,537  
Assets from risk management activities
    13,419       21,392       4,317             (9,732 )     29,396  
Other current assets
    1,014,883       420,241       44,985       66,200       (146,328 )     1,399,981  
Intercompany receivables
    534,920                   26,534       (561,454 )      
                                                 
Total current assets
    1,590,071       476,702       49,302       93,252       (717,514 )     1,491,813  
Intangible assets
          3,215                         3,215  
Goodwill
    566,800       24,282       143,198                   734,280  
Noncurrent assets from risk management activities
                                   
Deferred charges and other assets
    231,699       1,372       5,296       18,334             256,701  
                                                 
    $ 5,663,081     $ 510,688     $ 685,060     $ 112,934     $ (974,712 )   $ 5,997,051  
                                                 
 
CAPITALIZATION AND
LIABILITIES
Shareholders’ equity
  $ 1,706,291     $ 139,625     $ 86,425     $ 33,234     $ (259,284 )   $ 1,706,291  
Long-term debt
    2,176,251                   4,869             2,181,120  
                                                 
Total capitalization
    3,882,542       139,625       86,425       38,103       (259,284 )     3,887,411  
Current liabilities
                                               
Current maturities of long-term debt
    1,250                   2,058             3,308  
Short-term debt
    262,315       62,000             65,105       (127,105 )     262,315  
Liabilities from risk management activities
    1,067       21,847       5,421             (9,738 )     18,597  
Other current liabilities
    779,514       251,596       55,584             (17,131 )     1,069,563  
Intercompany payables
          44,801       516,653             (561,454 )      
                                                 
Total current liabilities
    1,044,146       380,244       577,658       67,163       (715,428 )     1,353,783  
Deferred income taxes
    280,746       (11,282 )     16,352       2,025             287,841  
Noncurrent liabilities from risk management activities
          1,861                         1,861  
Regulatory cost of removal obligation
    275,209                               275,209  
Deferred credits and other liabilities
    180,438       240       4,625       5,643             190,946  
                                                 
    $ 5,663,081     $ 510,688     $ 685,060     $ 112,934     $ (974,712 )   $ 5,997,051  
                                                 
 


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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 March 31, 2006, and the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2006 and 2005, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 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
May 2, 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.


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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,
 
  •  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 for the six months ended March 31, 2006:
 
  •  Our utility segment net income decreased by $7.6 million during the six months ended March 31, 2006. The decrease reflects the impact of weather, as adjusted for jurisdictions with weather-normalized rates, that was one percent warmer than the prior-year period and 12 percent warmer than normal, coupled with higher operating expenses.
 
  •  Our natural gas marketing segment net income increased $16.3 million during the six months ended March 31, 2006 compared with the six months ended March 31, 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 an unfavorable unrealized margin variance and an increase in interest charges resulting from increased short-term borrowings to fund working capital needs.
 
  •  Our pipeline and storage segment net income increased $3.5 million during the six months ended March 31, 2006 compared with the six months ended March 31, 2005, primarily reflecting Atmos Pipeline & Storage LLC’s ability to capture more favorable arbitrage spreads in connection with its asset management contracts coupled with increased throughput on the Atmos Pipeline — Texas system and higher transportation and related services margins.
 
  •  Our total-debt-to-capitalization ratio at March 31, 2006 was 58.9 percent compared with 59.3 percent at September 30, 2005 reflecting the impact of current-year net income partially offset by an increase in short-term debt borrowings to fund working capital needs.
 
  •  For the six months ended March 31, 2006, we generated $148.4 million in operating cash flow compared with $400.1 million for the six months ended March 31, 2005, reflecting the adverse impact of high natural gas costs on our working capital.
 
  •  Capital expenditures increased to $213.2 million in the six months ended March 31, 2006 from $137.5 million in the prior-year period primarily reflecting increased capital spending for various pipeline expansion projects in our Atmos Pipeline — Texas Division.
 
 
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.


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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 six months ended March 31, 2006.
 
RESULTS OF OPERATIONS
 
The following table presents our financial highlights for the three-month and six-month periods ended March 31, 2006 and 2005:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2006     2005     2006     2005  
    (In thousands, unless otherwise noted)  
 
Operating revenues
  $ 2,033,846     $ 1,685,085     $ 4,317,666     $ 3,053,709  
Gross profit
    405,403       375,894       751,993       697,997  
Operating expenses
    224,570       203,713       421,463       397,142  
Operating income
    180,833       172,181       330,530       300,855  
Miscellaneous income (expense)
    (2,439 )     958       (1,991 )     1,343  
Interest charges
    35,492       33,073       71,681       65,615  
Income before income taxes
    142,902       140,066       256,858       236,583  
Income tax expense
    54,106       51,564       97,035       88,482  
Net income
  $ 88,796     $ 88,502     $ 159,823     $ 148,101  
                 
Utility sales volumes — MMcf
    111,721       128,195       206,909       219,152  
Utility transportation volumes — MMcf
    31,152       31,904       61,754       59,882  
                                 
Total utility throughput — MMcf
    142,873       160,099       268,663       279,034  
                                 
Natural gas marketing sales volumes — MMcf
    69,450       66,644       140,946       126,940  
                                 
Pipeline transportation volumes — MMcf
    83,428       84,208       173,041       156,961  
                                 
Heating degree days(1) 
                               
Actual (weighted average)
    1,330       1,422       2,387       2,415  
Percent of normal
    84 %     90 %     88 %     89 %
Consolidated utility average transportation revenue per Mcf
  $ 0.61     $ 0.53     $ 0.56     $ 0.55  
Consolidated utility average cost of gas per Mcf sold
  $ 10.13     $ 7.12     $ 10.91     $ 7.16  
 
 
(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 six-month periods ended March 31, 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 March 31  
    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
  $ 14,650       100 %   $ 16,248       97 %
Kentucky
    9,055       100 %     10,758       100 %
Louisiana
    8,596       70 %     16,250       74 %
Mid-States
    24,895       93 %     24,705       95 %
Mid-Tex
    29,455       68 %     41,022       82 %
Mississippi
    16,752       100 %     18,509       100 %
West Texas
    13,539       100 %     15,302       99 %
Other
    822             404        
                                 
Utility segment
    117,764       84 %     143,198       90 %
Natural gas marketing segment
    37,333             6,409        
Pipeline and storage segment
    25,586             22,256        
Other nonutility segment and other
    150             318        
                                 
Consolidated operating income
  $ 180,833       84 %   $ 172,181       90 %
                                 
 
                                 
    Six Months Ended March 31  
    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
  $ 23,260       100 %   $ 24,483       98 %
Kentucky
    15,247       100 %     16,603       98 %
Louisiana
    16,487       80 %     22,583       78 %
Mid-States
    39,193       96 %     35,843       93 %
Mid-Tex
    80,242       74 %     79,570       80 %
Mississippi
    26,745       101 %     27,116       95 %
West Texas
    19,670       100 %     21,088       100 %
Other
    3,169             999        
                                 
Utility segment
    224,013       88 %     228,285       89 %
Natural gas marketing segment
    58,587             29,394        
Pipeline and storage segment
    47,638             42,603        
Other nonutility segment and other
    292             573        
                                 
Consolidated operating income
  $ 330,530       88 %   $ 300,855       89 %
                                 
 
 
(1) Adjusted for service areas that have weather-normalized operations.


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  Three Months Ended March 31, 2006 compared with Three Months Ended March 31, 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 March 31, 2006, WNA covered approximately 1.1 million customer meters in the following service areas for the following periods.
 
     
Georgia
  October – May
Kansas
  October – May
Kentucky
  November – April
Mississippi
  November – April
Tennessee
  November – April
Amarillo, Texas
  October – May
West Texas
  October – May
Lubbock, Texas
  October – May
Virginia
  January – December
 
Our Mid-Tex Division does not have WNA. However, its operations benefit from a rate structure that combines 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 provides for the recovery of most of our fixed costs for such operations under most weather conditions. However, this rate structure is not as beneficial during periods where weather is significantly warmer than normal.
 
Operating income
 
Utility gross profit margin decreased $7.4 million to $315.7 million for the three months ended March 31, 2006 from $323.1 million for the three months ended March 31, 2005. Total throughput for our utility business was 142.9 billion cubic feet (Bcf) during the current-year period compared to 160.1 Bcf in the prior-year period.
 
The decrease in utility gross profit margin and throughput primarily reflects weather, as adjusted for jurisdictions with weather-normalized rates, that was six percent warmer than the prior-year quarter and 16 percent


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warmer than normal. Weather in our Mid-Tex and Louisiana divisions, where we currently do not have weather-normalized rates, was approximately 30 percent warmer than normal during the quarter. During the three months ended March 31, 2006, our Mid-Tex and Louisiana divisions were 17 and four percent warmer than the prior-year quarter. The impact of warmer weather resulted in a $14.7 million reduction in gross profit margin compared with the prior-year quarter. Additionally, our Louisiana division experienced a $1.4 million reduction in gross profit margin during the current-year quarter due to the impact of Hurricane Katrina compared with the prior-year quarter. These decreases were partially offset by a $2.9 million increase arising from the Company’s fiscal 2004 and fiscal 2005 filings under Texas’s Gas Reliability Infrastructure Program (GRIP).
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $198 million for the three months ended March 31, 2006 from $179.9 million for the three months ended March 31, 2005. The increase reflects a $9.5 million increase in taxes, primarily related to franchise fees and state gross receipts taxes, both of which are calculated as a percentage of revenue, which 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 doubtful accounts, increased $3 million primarily due to higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. 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.
 
The provision for doubtful accounts increased $4.9 million to $7.1 million for the three months ended March 31, 2006. 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 three months ended March 31, 2006 was $10.13 per thousand cubic feet (Mcf), compared with $7.12 per Mcf for the three months ended March 31, 2005.
 
As a result of the aforementioned factors, our utility segment operating income for the three months ended March 31, 2006 decreased to $117.8 million from $143.2 million for the three months ended March 31, 2005.
 
Interest charges
 
Interest charges allocated to the utility segment for the three months ended March 31, 2006 increased to $30.3 million from $28.1 million for the three months ended March 31, 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 $1.2 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 three months ended March 31, 2006 decreased to $0.2 million compared to $2 million for the three months ended March 31, 2005. The $1.8 million decrease was primarily due to a $3.3 million charge recorded during the quarter associated with an adverse regulatory ruling in our Mid-States Division related to the calculation of a performance-based rate mechanism in Tennessee. Under the performance-based rate program, we and our customers jointly share in any actual gas cost savings achieved when compared to pre-determined benchmarks.
 
 
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


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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 March 31, 2006 and 2005 is summarized as follows:
 
                 
    Three Months Ended
 
    March 31  
    2006     2005  
    (In thousands, except physical position)  
 
Storage Activities
               
Realized margin
  $ 10,611     $ 14,669  
Unrealized margin
    2,741       (20,545 )
                 
Total Storage Activities
    13,352       (5,876 )
Marketing Activities
               
Realized margin
    21,005       17,236  
Unrealized margin
    9,620       (200 )
                 
Total Marketing Activities
    30,625       17,036  
                 
Gross profit
  $ 43,977     $ 11,160  
                 
Net physical position (Bcf)
    23.6       12.5  
                 
 
Our natural gas marketing segment’s gross profit margin was $44 million for the three months ended March 31, 2006 compared to gross profit of $11.2 million for the three months ended March 31, 2005. Gross profit margin from our natural gas marketing segment for the three months ended March 31, 2006 included an unrealized gain of $12.4 million compared with an unrealized loss of $20.7 million in the prior-year period. Natural gas marketing sales volumes were 82.4 Bcf during the three months ended March 31, 2006 compared with 74.8 Bcf for the prior-year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 69.5 Bcf during the current-year period compared with 66.6 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.


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Our storage activities generated $13.4 million in gross profit margin for the three months ended March 31, 2006 compared to incurring a loss of $5.9 million for the three months ended March 31, 2005. Our marketing activities generated $30.6 million for the three months ended March 31, 2006 compared with $17 million for the three months ended March 31, 2005. Higher realized marketing activities attributable to successfully capturing increased margins in certain market areas that experienced higher market volatility were offset by lower realized storage activities due to warmer weather during the current-year quarter, which resulted in fewer withdrawal opportunities than the prior-year quarter.
 
The $32.8 million increase in our natural gas marketing gross profit margin was primarily due to favorable movement during the three months ended March 31, 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 an 11.1 Bcf increase in our net physical position at March 31, 2006 compared to the prior-year quarter. We have elected to exclude this 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 $6.6 million for the three months ended March 31, 2006 from $4.8 million for the three months ended March 31, 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 increase in gross profit margin, partially offset by higher operating expenses, resulted in an increase in our natural gas marketing segment operating income to $37.3 million for the three months ended March 31, 2006 compared with operating income of $6.4 million for the three months ended March 31, 2005.
 
Interest charges
 
Interest charges allocated to the natural gas marketing segment for the three months ended March 31, 2006 increased to $2 million from $0.7 million for the three months ended March 31, 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 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


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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 $45.3 million for the three months ended March 31, 2006 from $41.1 million for the three months ended March 31, 2005. Total pipeline transportation volumes were 150.9 Bcf during the three months ended March 31, 2006 compared with 158.9 Bcf for the prior-year quarter. Excluding intersegment transportation volumes, total pipeline transportation volumes were 83.4 Bcf during the current year quarter compared with 84.2 Bcf in the prior-year quarter. The increase in pipeline and storage gross profit margin was primarily attributable to Atmos Pipeline & Storage, LLC capturing more favorable arbitrage spreads around its asset management contracts and higher transportation and related services margins in the Atmos Pipeline-Texas Division. These increases were partially offset by decreased throughput on the Atmos Pipeline — Texas system attributable to the warmer than normal weather in the Mid-Tex Division coupled with the absence of one-time inventory sales realized in the prior-year period of approximately $3 million.
 
Operating expenses increased to $19.7 million for the three months ended March 31, 2006 from $18.9 million for the three months ended March 31, 2005 due to higher employee benefit costs associated with the increase in headcount and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs.
 
As a result of the aforementioned factors, our pipeline and storage segment operating income for the three months ended March 31, 2006 increased to $25.6 million from $22.3 million for the three months ended March 31, 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 gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell 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 March 31, 2006 compared with the prior-year quarter.
 
Six Months Ended March 31, 2006 compared with Six Months Ended March 31, 2005
 
 
Operating income
 
Utility gross profit increased $15.5 million to $595.9 million for the six months ended March 31, 2006 from $580.4 million for the six months ended March 31, 2005. Total throughput for our utility business was 268.7 billion cubic feet (Bcf) during the current-year period compared to 279 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 $4.5 million due to rate increases received from the Company’s fiscal 2004 and fiscal 2005 GRIP filings. These increases were partially offset by an approximate $3.5 million decrease in the Louisiana Division due to the impact of Hurricane Katrina compared with the prior-year period. For the six months ended March 31, 2006, weather was 12 percent warmer than normal, as adjusted for jurisdictions with weather-normalized operations and


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one percent warmer than the prior-year period. In the Mid-Tex and Louisiana Divisions, which do not have weather-normalized rates, weather was 26 percent and 20 percent warmer than normal. The impact of the warmer weather resulted in a $5.9 million reduction in gross profit margin compared with the prior-year period.
 
Operating expenses increased to $371.9 million for the six months ended March 31, 2006 from $352.1 million for the six months ended March 31, 2005. The increase reflects a $15.8 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.
 
Partially offsetting these increases was a $2 million decrease in operation and maintenance expense, excluding the provision for bad debt. The decrease was primarily attributable to a reduction in third-party costs for outsourced administrative and meter reading functions that were in-sourced during fiscal 2006 combined with overall cost containment efforts across the utility divisions. These decreases were partially offset by higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Operation and maintenance expense for the six months ended March 31, 2006 reflects the absence of $2.1 million of United Cities Gas merger and integration cost amortization, as these costs were fully amortized by December 2004. However, this decrease was offset by a $2 million charge recorded during the first quarter for Hurricane Katrina-related losses.
 
The provision for doubtful accounts increased $6.1 million to $15.4 million for the six months ended March 31, 2006, compared with $9.3 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 six months ended March 31, 2006 was $10.91 per Mcf, compared with $7.16 per Mcf for the six months ended March 31, 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 six months ended March 31, 2006.
 
As a result of the aforementioned factors, our utility segment operating income for the six months ended March 31, 2006 decreased to $224 million from $228.3 million for the six months ended March 31, 2005.
 
Interest charges
 
Interest charges allocated to the utility segment for the six months ended March 31, 2006 increased to $61.9 million from $55.3 million for the six months ended March 31, 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 $2.4 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 six months ended March 31, 2006 remained unchanged compared to the six months ended March 31, 2005. However, the aforementioned $3.3 million charge recorded during the second quarter associated with an adverse regulatory ruling in our Mid-States Division was offset by an increase in intercompany interest income.


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Operating income
 
Our natural gas marketing segment’s gross profit margin for the six months ended March 31, 2006 and 2005 is summarized as follows:
 
                 
    Six Months Ended
 
    March 31  
    2006     2005  
    (In thousands, except physical position)  
 
Storage Activities
               
Realized margin
  $ 36,883     $ 17,259  
Unrealized margin
    (21,051 )     (8,027 )
                 
Total Storage Activities
    15,832       9,232  
Marketing Activities
               
Realized margin
    50,572       30,835  
Unrealized margin
    3,892       (2,063 )
                 
Total Marketing Activities
    54,464       28,772  
                 
Gross profit
  $ 70,296     $ 38,004  
                 
Net physical position (Bcf)
    23.6       12.5  
                 
 
Our natural gas marketing segment’s gross profit margin was $70.3 million for the six months ended March 31, 2006 compared to gross profit of $38 million for the six months ended March 31, 2005. Gross profit margin from our natural gas marketing segment for the six months ended March 31, 2006 included an unrealized loss of $17.2 million compared with an unrealized loss of $10.1 million in the prior-year period. Natural gas marketing sales volumes were 170.2 Bcf during the six months ended March 31, 2006 compared with 141 Bcf for the prior year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 140.9 Bcf during the current year period compared with 126.9 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 $15.8 million in gross profit margin for the six months ended March 31, 2006 compared to $9.2 million for the six months ended March 31, 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 partially offset by an increase in the unrealized loss associated with these operations due to an unfavorable movement during the six months ended March 31, 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 an 11.1 Bcf increase in our net physical position at March 31, 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 $54.5 million for the six months ended March 31, 2006 compared with $28.8 million for the six months ended March 31, 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 movement during the six months ended March 31, 2006 in the forward natural gas prices associated with financial derivatives used in these activities.


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Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $11.7 million for the six months ended March 31, 2006 from $8.6 million for the six months ended March 31, 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 $58.6 million for the six months ended March 31, 2006 compared with operating income of $29.4 million for the six months ended March 31, 2005.
 
Interest charges
 
Interest charges allocated to the natural gas marketing segment for the six months ended March 31, 2006 increased to $4.9 million from $1.1 million for the six months ended March 31, 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 $85 million for the six months ended March 31, 2006 from $78.6 million for the six months ended March 31, 2005. Total pipeline transportation volumes were 297.9 Bcf during the six months ended March 31, 2006 compared with 288.9 Bcf for the prior year period. Excluding intersegment transportation volumes, total pipeline transportation volumes were 173 Bcf during the current year period compared with 157 Bcf in the prior-year period. The increase in pipeline and storage gross profit margin was primarily attributable to Atmos Pipeline & Storage LLC capturing more favorable arbitrage spreads around its asset management contracts coupled with increased throughput on the Atmos Pipeline — Texas system and higher transportation and related services margins. These increases were partially offset by the absence of one-time inventory sales realized in the prior-year period of approximately $3 million.
 
Operating expenses increased to $37.3 million for the six months ended March 31, 2006 from $36 million for the six months ended March 31, 2005 due to higher employee benefit costs associated with the increase in headcount and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs.
 
As a result of the aforementioned factors, our pipeline and storage segment operating income for the six months ended March 31, 2006 increased to $47.6 million from $42.6 million for the six months ended March 31, 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 six months ended March 31, 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 March 31, 2006 and September 30, 2005:
 
                                 
    March 31, 2006     September 30, 2005  
    (In thousands, except percentages)  
 
Short-term debt
  $ 262,315       6.3 %   $ 144,809       3.7 %
Long-term debt
    2,184,428       52.6 %     2,186,368       55.6 %
Shareholders’ equity
    1,706,291       41.1 %     1,602,422       40.7 %
                                 
Total capitalization, including short-term debt
  $ 4,153,034       100.0 %   $ 3,933,599       100.0 %
                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 58.9 percent at March 31, 2006, and 59.3 percent at September 30, 2005. The decrease in the debt to capitalization ratio was primarily attributable to current-year net income partially offset by an increase in our short-term debt borrowings to fund our natural gas purchases. 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.
 
 
Year-over-year changes in our operating cash flows are attributable primarily 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 six months ended March 31, 2006, we realized a $148.4 million cash inflow from operating activities compared with a $400.1 million cash inflow from operations for the six months ended March 31, 2005. Period over period, our operating cash flow was adversely impacted by significantly higher natural gas prices, which have increased the levels of accounts receivable, natural gas inventories, accounts payable and undercollected deferred gas costs recorded on our balance sheet as of March 31, 2006. Specifically, 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 $84.4 million. However, the reduction in cash held on deposit in a margin account was offset by the following cash outflows: (i) $85.1 million arising from accounts receivable changes; (ii) $58.1 million arising from a twenty-four percent increase in our weighted average cost of gas held in inventory coupled with a 14.9 Bcf increase in natural gas stored underground; (iii) $83.9 million related to deferred gas costs arising from timing differences between when we purchase our natural gas and the period in which we can include this cost in our gas rates; and (iv) $102.8 million caused by the unfavorable timing of payments for accounts payable and other accrued liabilities. Finally, other working capital and other changes reduced operating cash flow by $6.2 million. The changes primarily related to a decrease in risk management assets and liabilities offset by various other working capital changes.
 
 
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


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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 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 six months ended March 31, 2006, we incurred $213.2 million for capital expenditures compared with $137.5 million for the six months ended March 31, 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 and various capital projects in our Mid-Tex Division.
 
 
For the six months ended March 31, 2006, our financing activities provided $76.5 million in cash compared with $1.7 billion provided in the prior-year period. Our significant financing activities for the six months ended March 31, 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 common shares, 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 six months ended March 31, 2006 we increased our borrowings under our credit facilities by $117.5 million. All amounts borrowed under our credit facilities were repaid during the six months ended March 31, 2005. The increase reflects seasonal borrowings to fund natural gas purchases and the impact of higher gas prices.
 
  •  We repaid $2.2 million of long-term debt during the six months ended March 31, 2006 compared with $3.8 million during the six months ended March 31, 2005. The decreased payments during the current quarter reflected the timing of our various debt maturities.
 
  •  During the six months ended March 31, 2006 we paid $50.9 million in cash dividends compared with dividend payments of $49.2 million for the six months ended March 31, 2005. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.62 per share during the six months ended March 31, 2005 to $0.63 per share during the six months ended March 31, 2006 combined with new share issuances under our various plans.


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  •  During the six months ended March 31, 2006 we issued 0.5 million shares of common stock which generated net proceeds of $12.1 million. The following table summarizes the issuances for the six months ended March 31, 2006 and 2005.
 
                 
    Six Months Ended
 
    March 31  
    2006     2005  
 
Shares issued:
               
Retirement Savings Plan
    224,881       242,810  
Direct Stock Purchase Plan
    206,762       240,910  
Outside Directors Stock-for-Fee Plan
    1,268       1,242  
Long-Term Incentive Plan
    104,585       492,801  
Long-Term Stock Plan for Mid-States Division
    300        
Public Offering
          16,100,000  
                 
Total shares issued
    537,796       17,077,763