e10vq
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
     
(Mark One)    
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended March 31, 2009
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from               to          
 
Commission File Number 1-10042
 
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
     
Texas and Virginia
  75-1743247
(State or other jurisdiction of   (IRS employer
incorporation or organization)
  identification no.)
     
Three Lincoln Centre, Suite 1800
  75240
5430 LBJ Freeway, Dallas, Texas
  (Zip code)
(Address of principal executive offices)
   
 
(972) 934-9227
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).*  Yes o     No o
 
* The registrant has not yet been phased into the interactive data requirements.
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer o Smaller Reporting Company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes o     No þ
 
Number of shares outstanding of each of the issuer’s classes of common stock, as of April 22, 2009.
 
     
Class
 
Shares Outstanding
 
No Par Value
  92,008,920
 


TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONDENSED CONSOLIDATED 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
SIGNATURE
EXHIBITS INDEX Item 6
EX-12
EX-15
EX-31
EX-32


Table of Contents

 
GLOSSARY OF KEY TERMS
 
     
AEC
  Atmos Energy Corporation
AEH
  Atmos Energy Holdings, Inc.
AEM
  Atmos Energy Marketing, LLC
AOCI
  Accumulated other comprehensive income
APS
  Atmos Pipeline and Storage, LLC
Bcf
  Billion cubic feet
FASB
  Financial Accounting Standards Board
Fitch
  Fitch Ratings, Ltd.
FSP
  FASB Staff Position
GRIP
  Gas Reliability Infrastructure Program
LPSC
  Louisiana Public Service Commission
Mcf
  Thousand cubic feet
MMcf
  Million cubic feet
MPSC
  Mississippi Public Service Commission
Moody’s
  Moody’s Investors Services, Inc.
NYMEX
  New York Mercantile Exchange, Inc.
PPA
  Pension Protection Act of 2006
RRC
  Railroad Commission of Texas
RRM
  Rate Review Mechanism
S&P
  Standard & Poor’s Corporation
SEC
  United States Securities and Exchange Commission
SFAS
  Statement of Financial Accounting Standards
WNA
  Weather Normalization Adjustment


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Table of Contents

 
PART I. FINANCIAL INFORMATION
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    March 31,
    September 30,
 
    2009     2008  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 5,873,028     $ 5,730,156  
Less accumulated depreciation and amortization
    1,609,836       1,593,297  
                 
Net property, plant and equipment
    4,263,192       4,136,859  
Current assets
               
Cash and cash equivalents
    482,085       46,717  
Accounts receivable, net
    531,749       477,151  
Gas stored underground
    327,288       576,617  
Other current assets
    137,433       184,619  
                 
Total current assets
    1,478,555       1,285,104  
Goodwill and intangible assets
    738,772       739,086  
Deferred charges and other assets
    205,242       225,650  
                 
    $ 6,685,761     $ 6,386,699  
                 
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, 2009 — 91,947,614 shares;
               
September 30, 2008 — 90,814,683 shares
  $ 460     $ 454  
Additional paid-in capital
    1,768,307       1,744,384  
Retained earnings
    480,355       343,601  
Accumulated other comprehensive loss
    (70,628 )     (35,947 )
                 
Shareholders’ equity
    2,178,494       2,052,492  
Long-term debt
    2,169,141       2,119,792  
                 
Total capitalization
    4,347,635       4,172,284  
Current liabilities
               
Accounts payable and accrued liabilities
    472,078       395,388  
Other current liabilities
    413,764       460,372  
Short-term debt
          350,542  
Current maturities of long-term debt
    400,225       785  
                 
Total current liabilities
    1,286,067       1,207,087  
Deferred income taxes
    466,868       441,302  
Regulatory cost of removal obligation
    313,486       298,645  
Deferred credits and other liabilities
    271,705       267,381  
                 
    $ 6,685,761     $ 6,386,699  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    March 31  
    2009     2008  
    (Unaudited)  
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 1,230,420     $ 1,521,856  
Regulated transmission and storage segment
    59,234       51,440  
Natural gas marketing segment
    708,658       1,128,653  
Pipeline, storage and other segment
    12,272       10,022  
Intersegment eliminations
    (189,178 )     (227,986 )
                 
      1,821,406       2,483,985  
Purchased gas cost
               
Natural gas distribution segment
    863,340       1,164,332  
Regulated transmission and storage segment
           
Natural gas marketing segment
    685,114       1,112,321  
Pipeline, storage and other segment
    1,656       338  
Intersegment eliminations
    (188,755 )     (227,400 )
                 
      1,361,355       2,049,591  
                 
Gross profit
    460,051       434,394  
Operating expenses
               
Operation and maintenance
    121,740       120,053  
Depreciation and amortization
    53,450       48,790  
Taxes, other than income
    58,314       54,408  
                 
Total operating expenses
    233,504       223,251  
                 
Operating income
    226,547       211,143  
Miscellaneous income (expense)
    (1,565 )     1,467  
Interest charges
    35,533       33,516  
                 
Income before income taxes
    189,449       179,094  
Income tax expense
    60,446       67,560  
                 
Net income
  $ 129,003     $ 111,534  
                 
Basic net income per share
  $ 1.42     $ 1.25  
                 
Diluted net income per share
  $ 1.41     $ 1.24  
                 
Cash dividends per share
  $ 0.330     $ 0.325  
                 
Weighted average shares outstanding:
               
Basic
    90,895       89,314  
                 
Diluted
    91,567       89,990  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Six Months Ended
 
    March 31  
    2009     2008  
    (Unaudited)  
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 2,286,388     $ 2,450,033  
Regulated transmission and storage segment
    113,916       96,486  
Natural gas marketing segment
    1,496,153       1,969,370  
Pipeline, storage and other segment
    28,720       16,749  
Intersegment eliminations
    (387,439 )     (391,143 )
                 
      3,537,738       4,141,495  
Purchased gas cost
               
Natural gas distribution segment
    1,620,924       1,819,309  
Regulated transmission and storage segment
           
Natural gas marketing segment
    1,442,586       1,907,075  
Pipeline, storage and other segment
    5,559       1,067  
Intersegment eliminations
    (386,594 )     (389,988 )
                 
      2,682,475       3,337,463  
                 
Gross profit
    855,263       804,032  
Operating expenses
               
Operation and maintenance
    256,495       241,242  
Depreciation and amortization
    106,576       97,303  
Taxes, other than income
    102,451       95,835  
                 
Total operating expenses
    465,522       434,380  
                 
Operating income
    389,741       369,652  
Miscellaneous income (expense)
    (1,866 )     1,374  
Interest charges
    74,524       70,333  
                 
Income before income taxes
    313,351       300,693  
Income tax expense
    108,385       115,356  
                 
Net income
  $ 204,966     $ 185,337  
                 
Basic net income per share
  $ 2.26     $ 2.08  
                 
Diluted net income per share
  $ 2.24     $ 2.06  
                 
Cash dividends per share
  $ 0.66     $ 0.65  
                 
Weighted average shares outstanding:
               
Basic
    90,637       89,133  
                 
Diluted
    91,311       89,817  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Six Months Ended
 
    March 31  
    2009     2008  
    (Unaudited)  
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 204,966     $ 185,337  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    106,576       97,303  
Charged to other accounts
    21       67  
Deferred income taxes
    97,892       72,277  
Other
    13,634       6,853  
Net assets/liabilities from risk management activities
    5,810       (22,667 )
Net change in operating assets and liabilities
    185,723       140,022  
                 
Net cash provided by operating activities
    614,622       479,192  
Cash Flows From Investing Activities
               
Capital expenditures
    (221,330 )     (198,722 )
Other, net
    (3,925 )     (3,132 )
                 
Net cash used in investing activities
    (225,255 )     (201,854 )
Cash Flows From Financing Activities
               
Net decrease in short-term debt
    (353,468 )     (150,582 )
Net proceeds from debt offering
    446,188        
Settlement of Treasury lock agreement
    1,938        
Repayment of long-term debt
    (625 )     (2,253 )
Cash dividends paid
    (60,446 )     (58,431 )
Issuance of common stock
    12,414       12,839  
                 
Net cash provided by (used in) financing activities
    46,001       (198,427 )
                 
Net increase in cash and cash equivalents
    435,368       78,911  
Cash and cash equivalents at beginning of period
    46,717       60,725  
                 
Cash and cash equivalents at end of period
  $ 482,085     $ 139,636  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 2009
 
1.   Nature of Business
 
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions in the service areas described below:
 
     
Division   Service Area
 
Atmos Energy Colorado-Kansas Division
  Colorado, Kansas, Missouri(1)
Atmos Energy Kentucky/Mid-States Division
  Georgia(1), Illinois(1), Iowa(1), Kentucky, Missouri(1), Tennessee, Virginia(1)
Atmos Energy Louisiana Division
  Louisiana
Atmos Energy Mid-Tex Division
  Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division
  Mississippi
Atmos Energy West Texas Division
  West Texas
 
 
(1) Denotes states where we have more limited service areas.
 
In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.
 
Our regulated transmission and storage business consists of the regulated operations of our Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands.
 
Our nonregulated businesses operate primarily in the Midwest and Southeast and include our natural gas marketing operations and pipeline, storage and other operations. These businesses are operated through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH), which is wholly owned by the Company and based in Houston, Texas.
 
Our natural gas marketing operations are conducted through 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 Southeast and Midwest and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS owns and operates a 21 mile pipeline located in New Orleans, Louisiana. This pipeline is used primarily to aggregate gas supply for our regulated natural gas distribution division in Louisiana and for AEM, but also provides limited third party transportation services.
 
APS also engages in asset optimization activities whereby it seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. Certain of these arrangements are asset management plans with regulated affiliates of the Company which have been approved by applicable state regulatory commissions. Generally, these asset management plans require APS to share with our regulated customers a portion of the profits earned from these arrangements.
 
Further, APS owns or has an interest in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for pipeline capacity to meet customer demand during peak periods. Finally, APS manages our natural gas gathering operations, which were limited in nature as of March 31, 2009.
 
2.   Unaudited Interim Financial Information
 
In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, 2009 are not indicative of our results of operations for the full 2009 fiscal year, which ends September 30, 2009.
 
Significant accounting policies
 
Our accounting policies are described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, and there were no changes to those policies. However, during the six months ended March 31, 2009, we recognized a non-recurring $8.3 million increase in gross profit associated with a one-time update to our estimate for gas delivered to customers but not yet billed, resulting from base rate changes in several jurisdictions.
 
During the second quarter of fiscal 2009, we updated the tax rates used to record deferred taxes. The one-time tax benefit resulted in a favorable impact to net income of $11.3 million.
 
Additionally, during the second quarter of fiscal 2009, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
 
Effective October 1, 2008, the Company adopted Statement of Financial Accounting Standards (SFAS) 157, Fair Value Measurements, the measurement date requirements of SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115, SFAS 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 and FASB Staff Position (FSP) FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. Except for the adoption of these accounting pronouncements, which are further discussed below, there were no significant changes to our accounting policies during the six months ended March 31, 2009.
 
SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosure on fair value measurements required under other accounting pronouncements but does not change existing


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
guidance as to whether or not an instrument is carried at fair value. The adoption of this standard did not materially impact our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 4.
 
Effective October 1, 2008, the Company adopted the measurement date requirements of SFAS 158 using the remeasurement approach. Under this approach, the Company remeasured its projected benefit obligation, fair value of plan assets and its fiscal 2009 net periodic cost. In accordance with the transition rules of SFAS 158, the impact of changing the measurement date from June 30, 2008 to September 30, 2008 decreased retained earnings by $7.8 million, net of tax, decreased the unrecognized actuarial loss by $9.0 million and increased our postretirement liabilities by $3.5 million during the first quarter of fiscal 2009.
 
SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of the standard is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis. The fair value option is irrevocable, unless a new election date occurs. The adoption of this standard did not impact our financial position, results of operations or cash flows.
 
SFAS 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement requires specific disclosures regarding how and why an entity uses derivative instruments; the accounting for derivative instruments and related hedged items; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Since SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard did not have an impact on our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 3.
 
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP requires companies to disclose the fair value of financial instruments for which it is practicable to estimate the value and the methods and significant assumptions used to estimate the fair value. The disclosure is required for interim and annual reports. The disclosure requirements of this FSP are presented in Note 4.
 
Regulatory assets and liabilities
 
We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Significant regulatory assets and liabilities as of March 31, 2009 and September 30, 2008 included the following:
 
                 
    March 31,
    September 30,
 
    2009     2008  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 89,244     $ 100,563  
Merger and integration costs, net
    7,374       7,586  
Deferred gas costs
    58,660       55,103  
Environmental costs
    741       980  
Rate case costs
    9,144       12,885  
Deferred franchise fees
    597       651  
Deferred income taxes, net
    343       343  
Other
    7,846       8,120  
                 
    $ 173,949     $ 186,231  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 61,177     $ 76,979  
Regulatory cost of removal obligation
    329,120       317,273  
Other
    5,499       5,639  
                 
    $ 395,796     $ 399,891  
                 
 
Currently, our authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from various state regulatory commissions.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Comprehensive income
 
The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and six-month periods ended March 31, 2009 and 2008:
 
                                 
    Three Months Ended March 31     Six Months Ended March 31  
    2009     2008     2009     2008  
    (In thousands)  
 
Net income
  $ 129,003     $ 111,534     $ 204,966     $ 185,337  
Unrealized holding losses on investments, net of tax benefit of $429 and $1,385 for the three months ended March 31, 2009 and 2008 and of $3,759 and $671 for the six months ended March 31, 2009 and 2008
    (862 )     (2,262 )     (6,295 )     (1,097 )
Other than temporary impairment of investments, net of tax expense of $790 for the six months ended March 31, 2009
                1,288        
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $1,353 and $482 for the three months ended March 31, 2009 and 2008 and $1,835 and $964 for the six months ended March 31, 2009 and 2008
    1,854       787       2,641       1,574  
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $(7,524) and $2,260 for the three months ended March 31, 2009 and 2008 and $(21,341) and $7,197 for the six months ended March 31, 2009 and 2008
    (9,771 )     3,690       (32,315 )     11,743  
                                 
Comprehensive income
  $ 120,224     $ 113,749     $ 170,285     $ 197,557  
                                 
 
Accumulated other comprehensive loss, net of tax, as of March 31, 2009 and September 30, 2008 consisted of the following unrealized gains (losses):
 
                 
    March 31,
    September 30,
 
    2009     2008  
    (In thousands)  
 
Accumulated other comprehensive loss:
               
Unrealized holding gains (losses) on investments
  $ (4,097 )   $ 910  
Treasury lock agreements
    (8,463 )     (11,104 )
Cash flow hedges
    (58,068 )     (25,753 )
                 
    $ (70,628 )   $ (35,947 )
                 
 
3.   Financial Instruments
 
We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically utilize financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Currently, we utilize financial instruments in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. However, our pipeline, storage


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.
 
Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.
 
Regulated Commodity Risk Management Activities
 
In our natural gas distribution segment, our customers are exposed to the effect of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
 
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. If the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2008-2009 heating season, in the jurisdictions where we are permitted to utilize financial instruments, we anticipated hedging approximately 29 percent, or 25.5 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.
 
The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with SFAS 71. Accordingly, there is no earnings impact to our natural gas distribution segment as a result of the use of financial instruments.
 
Nonregulated Commodity Risk Management Activities
 
Our natural gas marketing segment, through AEM, aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request.
 
We also perform asset optimization activities in both our natural gas marketing segment and pipeline, storage and other segment. Through asset optimization activities, we seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time. Over time, gains and losses on the sale of storage gas


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
inventory will be offset by gains and losses on the financial instruments, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.
 
As a result of these activities, our nonregulated operations are exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Futures contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.
 
We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our natural gas marketing segment associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 46 months. The effective portion of the unrealized gains and losses arising from the use of cash flow hedges is recorded as a component of accumulated other comprehensive income (AOCI) on the balance sheet. Amounts associated with cash flow hedges recognized in the income statement include (i) the amount of unrealized gain or loss that has been reclassified from AOCI when the hedged volumes are sold and (ii) the amount of ineffectiveness associated with these hedges in the period the ineffectiveness arises.
 
We use financial instruments, designated as fair value hedges, to hedge the exposure to changes in the fair value of our natural gas inventory used in our asset optimization activities in our natural gas marketing and pipeline, storage and other segments. Therefore, gains and losses arising from these financial instruments should offset the changes in the fair value of the hedged item to the extent the hedging relationship is effective. Ineffectiveness is recognized in the income statement in the period the ineffectiveness arises.
 
Also, in our natural gas marketing segment, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.
 
Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. Our risk management committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.
 
Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on March 31, 2009, AEH had net open positions (including existing storage) of less than 0.1 Bcf.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Interest Rate Risk Management Activities
 
In March 2009, we entered into a Treasury lock agreement to fix the Treasury yield component of the interest cost associated with our $450 million 8.50% senior notes (the Senior Notes Offering), which was completed on March 26, 2009. The Senior Notes Offering is discussed in Note 5. We designated this Treasury lock as a cash flow hedge of an anticipated transaction. This Treasury lock was settled on March 23, 2009 with the receipt of $1.9 million from the counterparty due to an increase in the 10 year Treasury rates between inception of the Treasury lock and settlement. Because the Treasury lock was effective, the net $1.2 million unrealized gain was recorded as a component of accumulated other comprehensive income and will be recognized over the 10 year life of the senior notes.
 
In prior years, we similarly managed interest rate risk by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. These Treasury locks were settled at various times at a net loss. These realized gains and losses were recorded as a component of accumulated other comprehensive income (loss) and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these Treasury locks extend through fiscal 2035. However, the majority of the remaining amounts of these Treasury locks will be recognized as a component of interest expense through fiscal 2019.
 
Quantitative Disclosures Related to Financial Instruments
 
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
 
As of March 31, 2009, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2009, we had net long/(short) commodity contracts outstanding in the following quantities:
 
                             
        Natural
    Natural
    Pipeline,
 
    Hedge
  Gas
    Gas
    Storage
 
Contract Type   Designation   Distribution     Marketing     and Other  
        Quantity (MMcf)  
 
Commodity contracts
  Fair Value           (19,052 )     (1,410 )
    Cash Flow           38,822       (1,905 )
    Not designated     7,727       109,450       (688 )
                             
          7,727       129,220       (4,003 )
                             
 
Financial Instruments on the Balance Sheet
 
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of March 31, 2009 and September 30, 2008. As required by SFAS 161, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $79.1 million and $56.6 million of cash held on deposit in margin accounts as of March 31, 2009 and September 30, 2008 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.
 
                             
        Natural
    Natural
       
        Gas
    Gas
       
    Balance Sheet Location   Distribution     Marketing(1)     Total  
        (In thousands)  
 
March 31, 2009:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 73,163     $ 73,163  
Noncurrent commodity contracts
  Deferred charges and other assets           8,018       8,018  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (116,698 )     (116,698 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (1,712 )     (1,712 )
                             
Total
              (37,229 )     (37,229 )
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets     676       40,262       40,938  
Noncurrent commodity contracts
  Deferred charges and other assets           5,108       5,108  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (22,535 )     (39,098 )     (61,633 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (4 )     (1,689 )     (1,693 )
                             
Total
        (21,863 )     4,583       (17,280 )
                             
Total Financial Instruments
      $ (21,863 )   $ (32,646 )   $ (54,509 )
                             
 
 
(1) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.
 
                             
        Natural
    Natural
       
        Gas
    Gas
       
    Balance Sheet Location   Distribution     Marketing(1)     Total  
        (In thousands)  
 
September 30, 2008:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 101,191     $ 101,191  
Noncurrent commodity contracts
  Deferred charges and other assets           4,984       4,984  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (89,397 )     (89,397 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (206 )     (206 )
                             
Total
              16,572       16,572  
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets           20,010       20,010  
Noncurrent commodity contracts
  Deferred charges and other assets           1,093       1,093  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (58,566 )     (20,145 )     (78,711 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (5,111 )     (988 )     (6,099 )
                             
Total
        (63,677 )     (30 )     (63,707 )
                             
Total Financial Instruments
      $ (63,677 )   $ 16,542     $ (47,135 )
                             
 
 
(1) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Impact of Financial Instruments on the Income Statement
 
The following tables present the impact that financial instruments had on our condensed consolidated income statement, by operating segment, as applicable, for the three and six months ended March 31, 2009 and 2008.
 
Unrealized margins recorded in our natural gas marketing and pipeline, storage and other segments are comprised of various components, including, but not limited to, unrealized gains and losses arising from hedge ineffectiveness. Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative instrument and the hedged item and could materially affect our results of operations for the reported period. For the three months ended March 31, 2009 and 2008 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $4.2 million and $6.5 million. For the six months ended March 31, 2009 and 2008 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $24.6 million and $45.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below. Although these unrealized gains and losses are currently recorded in our income statement, they are not necessarily indicative of the economic gross profit we anticipate realizing when the underlying physical and financial transactions are settled.
 
Fair Value Hedges
 
The impact of commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and six months ended March 31, 2009 and 2008 is presented below.
 
                         
    Three Months Ended March 31, 2009  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ 19,870     $ 2,105     $ 21,975  
Fair value adjustment for natural gas inventory designated as the hedged item
    (18,562 )     (437 )     (18,999 )
                         
Total impact on revenue
  $ 1,308     $ 1,668     $ 2,976  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ 2,327     $     $ 2,327  
Timing ineffectiveness
    (1,019 )     1,668       649  
                         
    $ 1,308     $ 1,668     $ 2,976  
                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Three Months Ended March 31, 2008  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ (33,448 )   $ (735 )   $ (34,183 )
Fair value adjustment for natural gas inventory designated as the hedged item
    39,922       1,352       41,274  
                         
Total impact on revenue
  $ 6,474     $ 617     $ 7,091  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ (739 )   $     $ (739 )
Timing ineffectiveness
    7,213       617       7,830  
                         
    $ 6,474     $ 617     $ 7,091  
                         
 
                         
    Six Months Ended March 31, 2009  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ 45,553     $ 6,044     $ 51,597  
Fair value adjustment for natural gas inventory designated as the hedged item
    (30,422 )     (1,990 )     (32,412 )
                         
Total impact on revenue
  $ 15,131     $ 4,054     $ 19,185  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ 4,279     $     $ 4,279  
Timing ineffectiveness
    10,852       4,054       14,906  
                         
    $ 15,131     $ 4,054     $ 19,185  
                         
 
                         
    Six Months Ended March 31, 2008  
    Natural
    Pipeline,
       
    Gas
    Storage and
       
    Marketing     Other     Consolidated  
    (In thousands)  
 
Commodity contracts
  $ (16,221 )   $ 1,387     $ (14,834 )
Fair value adjustment for natural gas inventory designated as the hedged item
    57,523       2,410       59,933  
                         
Total impact on revenue
  $ 41,302     $ 3,797     $ 45,099  
                         
The impact on revenue is comprised of the following:
                       
Basis ineffectiveness
  $ 1,217     $     $ 1,217  
Timing ineffectiveness
    40,085       3,797       43,882  
                         
    $ 41,302     $ 3,797     $ 45,099  
                         
 
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot to forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on revenue.

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Cash Flow Hedges
 
The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
                                 
    Three Months Ended March 31, 2009  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (48,585 )   $ 16,170     $ (32,415 )
Gain arising from ineffective portion of commodity contracts
          1,180             1,180  
                                 
Total impact on revenue
          (47,405 )     16,170       (31,235 )
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,269 )                 (1,269 )
                                 
Total Impact from Cash Flow Hedges
  $ (1,269 )   $ (47,405 )   $ 16,170     $ (32,504 )
                                 
 
                                 
    Three Months Ended March 31, 2008  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (8,040 )   $ 13,492     $ 5,452  
Loss arising from ineffective portion of commodity contracts
          (634 )           (634 )
                                 
Total impact on revenue
          (8,674 )     13,492       4,818  
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,269 )                 (1,269 )
                                 
Total Impact from Cash Flow Hedges
  $ (1,269 )   $ (8,674 )   $ 13,492     $ 3,549  
                                 
 
                                 
    Six Months Ended March 31, 2009  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (76,829 )   $ 24,139     $ (52,690 )
Gain arising from ineffective portion of commodity contracts
          5,372             5,372  
                                 
Total impact on revenue
          (71,457 )     24,139       (47,318 )
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (2,538 )                 (2,538 )
                                 
Total Impact from Cash Flow Hedges
  $ (2,538 )   $ (71,457 )   $ 24,139     $ (49,856 )
                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Six Months Ended March 31, 2008  
    Natural
    Natural
    Pipeline,
       
    Gas
    Gas
    Storage
       
    Distribution     Marketing     and Other     Consolidated  
    (In thousands)  
 
Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (17,294 )   $ 13,916     $ (3,378 )
Gain arising from ineffective portion of commodity contracts
          126             126  
                                 
Total impact on revenue
          (17,168 )     13,916       (3,252 )
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (2,538 )                 (2,538 )
                                 
Total Impact from Cash Flow Hedges
  $ (2,538 )   $ (17,168 )   $ 13,916     $ (5,790 )
                                 
 
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended March 31, 2009 and 2008. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
    (In thousands)  
 
Increase (decrease) in fair value:
                               
Treasury lock agreements
  $ 1,221     $     $ 1,221     $  
Forward commodity contracts
    (29,544 )     7,070       (64,659 )     9,649  
Recognition of (gains) losses in earnings due to settlements:
                               
Treasury lock agreements
    633       787       1,420       1,574  
Forward commodity contracts
    19,773       (3,380 )     32,344       2,094  
                                 
Total other comprehensive income (loss) from hedging, net of tax(1)
  $ (7,917 )   $ 4,477     $ (29,674 )   $ 13,317  
                                 
 
 
(1) Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.
 
The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of March 31, 2009:
 
                         
    Treasury
             
    Lock
    Commodity
       
    Agreements     Contracts     Total  
    (In thousands)  
 
Next twelve months
  $ (2,426 )   $ (54,233 )   $ (56,659 )
Thereafter
    (6,037 )     (3,835 )     (9,872 )
                         
Total(1)
  $ (8,463 )   $ (58,068 )   $ (66,531 )
                         
 
 
(1) Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Financial Instruments Not Designated as Hedges
 
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three and six months ended March 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact to our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
 
                                 
    Three Months Ended March 31     Six Months Ended March 31  
    2009     2008     2009     2008  
    (In thousands)  
 
Natural gas marketing commodity contracts
  $ 10,593     $ (14,120 )   $ 6,761     $ (13,794 )
Pipeline, storage and other commodity contracts
    183       (245 )     100       (889 )
                                 
Total impact on revenue
  $ 10,776     $ (14,365 )   $ 6,861     $ (14,683 )
                                 
 
4.   Fair Value Measurements
 
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) and expands disclosures about fair value measurements. This Statement does not require any new fair value measurements; rather it provides guidance on how to perform fair value measurements as required or permitted under previous accounting pronouncements.
 
We prospectively adopted the provisions of SFAS 157 on October 1, 2008 for most of the financial assets and liabilities recorded on our balance sheet at fair value. Adoption of this statement for these assets and liabilities did not have a material impact on our financial position, results of operations or cash flows.
 
In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157, which provided a one-year deferral of SFAS 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. Under this partial deferral, SFAS 157 will not be effective until October 1, 2009 for fair value measurements for the following:
 
  •  Asset retirement obligations
 
  •  Most nonfinancial assets and liabilities that may be acquired in a business combination
 
  •  Impairment analyses performed for nonfinancial assets
 
We believe the adoption of SFAS 157 for the reporting of these nonfinancial assets and liabilities will not have a material impact on our financial position, results of operations or cash flows.
 
In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, which clarified the application of SFAS 157 in inactive markets. This FSP did not impact our financial position, results of operations or cash flows.
 
SFAS 157 also applies to the valuation of our pension and post-retirement plan assets. The adoption of this standard did not affect these valuations because SFAS 157 specifically excluded pension and post-


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
retirement assets from its prescribed disclosure provisions. Accordingly, these plan assets are not included in the tabular disclosures below. However, in December 2008, the FASB issued FSP FAS 132(R)-1 — Employers’ Disclosures about Postretirement Benefit Plan Assets, which will, among other things, require disclosure about fair value measurements similar to those required by SFAS 157. This FSP will impact our annual disclosure requirements beginning in fiscal 2010.
 
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP requires companies to disclose the fair value of financial instruments for which it is practicable to estimate the value and the methods and significant assumptions used to estimate the fair value. We have adopted the disclosure requirements of this FSP, which are presented below.
 
Determining Fair Value
 
SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.
 
Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices) as a practical expedient for determining fair value measurement, as permitted under SFAS 157. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed. We utilize models and other valuation methods to determine fair value when external sources are not available. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then-current market conditions. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.
 
Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. Recent adverse developments in the global financial and credit markets have made it more difficult and more expensive for companies to access the short-term capital markets, which may negatively impact the creditworthiness of our counterparties. A continued tightening of the credit markets could cause more of our counterparties to fail to perform. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.
 
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:
 
Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities.
 
Level 2 — Pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable.
 
Level 3 — Generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. Currently, we have no assets or liabilities recorded at fair value that would qualify for Level 3 reporting.
 
Quantitative Disclosures
 
Financial Instruments
 
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. The following table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009. As required under SFAS 157, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
                                         
    Quoted
    Significant
    Significant
             
    Prices in
    Other
    Other
             
    Active
    Observable
    Unobservable
    Netting and
       
    Markets
    Inputs
    Inputs
    Cash
    March 31,
 
    (Level 1)     (Level 2)     (Level 3)     Collateral(1)     2009  
    (In thousands)  
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 676     $        —     $     $ 676  
Natural gas marketing segment
    45,770       80,564             (75,558 )     50,776  
                                         
Total financial instruments
    45,770       81,240             (75,558 )     51,452  
Hedged portion of gas stored underground
                                       
Natural gas marketing segment
    62,912                         62,912  
Pipeline, storage and other segment(2)
    3,656                         3,656  
                                         
Total gas stored underground
    66,568                         66,568  
Available-for-sale securities
    26,605                         26,605  
                                         
Total assets
  $ 138,943     $ 81,240     $     $ (75,558 )   $ 144,625  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 22,539     $     $     $ 22,539  
Natural gas marketing segment
    117,413       41,567             (154,656 )     4,324  
                                         
Total liabilities
  $ 117,413     $ 64,106     $     $ (154,656 )   $ 26,863  
                                         
 
 
(1) This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and FSP FIN 39-1. In addition, as of March 31, 2009, we had $79.1 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $71.6 million was used to offset financial instruments in a liability position. The remaining $7.5 million has been reflected as a financial instrument asset.
 
(2) Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Other Fair Value Measures
 
In addition to the financial instruments above, we have several nonfinancial assets and liabilities subject to fair value measures. These assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable, debt, asset retirement obligations and pension and post-retirement plan assets. As noted above, fair value disclosures for asset retirement obligations and pension and post-retirement plan assets are not currently effective for us. We record cash and cash equivalents, accounts receivable, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities. The fair value of our debt is determined using a discounted cash flow analysis based upon borrowing rates currently available to us, the remaining average maturities and our credit rating. The following table presents the carrying value and fair value of our debt as of March 31, 2009:
 
         
    March 31, 2009
    (In thousands)
 
Carrying Amount
  $ 2,572,987  
Fair Value
  $ 2,166,454  
 
The fair value as of March 31, 2009 was calculated utilizing discount rates ranging from 6.6 percent to 9.6 percent, remaining average maturities ranging from one to 26 years, and a credit adjustment of 6.0 percent.
 
5.   Debt
 
Long-term debt
 
Long-term debt at March 31, 2009 and September 30, 2008 consisted of the following:
 
                 
    March 31,
    September 30,
 
    2009     2008  
    (In thousands)  
 
Unsecured 4.00% Senior Notes, due April 2009
  $ 400,000     $ 400,000  
Unsecured 7.375% Senior Notes, due 2011
    350,000       350,000  
Unsecured 10% Notes, due 2011
    2,303       2,303  
Unsecured 5.125% Senior Notes, due 2013
    250,000       250,000  
Unsecured 4.95% Senior Notes, due 2014
    500,000       500,000  
Unsecured 6.35% Senior Notes, due 2017
    250,000       250,000  
Unsecured 8.50% Senior Notes, due 2019
    450,000        
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  
Other term notes due in installments through 2013
    684       1,309  
                 
Total long-term debt
    2,572,987       2,123,612  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (3,621 )     (3,035 )
Current maturities
    (400,225 )     (785 )
                 
    $ 2,169,141     $ 2,119,792  
                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
On March 26, 2009, we closed our Senior Notes Offering. The effective interest rate on these notes is 8.69 percent, after giving effect to the settlement of the $450 million treasury lock discussed in Note 3. Most of the net proceeds of approximately $446 million were used to redeem our $400 million 4.00% unsecured senior notes, which, on March 30, 2009, were called for redemption on April 30, 2009, prior to their October 2009 maturity. In connection with the repayment of the $400 million 4.00% unsecured senior notes, we paid a $6.6 million call premium in accordance with the terms of the senior notes and accrued interest of approximately $0.6 million. The remaining net proceeds will be used for general corporate purposes.
 
Short-term debt
 
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings reach their highest levels in the winter months.
 
We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. At March 31, 2009, there was no short-term debt outstanding. At September 30, 2008, there was $350.5 million of short-term debt outstanding, comprised of $330.5 million outstanding under our bank credit facilities and $20.0 million outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.
 
Regulated Operations
 
We fund our regulated operations as needed primarily through a $566.7 million commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $800 million of working capital funding. The first facility is a five-year unsecured facility, expiring December 2011, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At the time this credit facility was established, borrowings under this facility were limited to $600 million. However, in September 2008, the limit on borrowings was effectively reduced to $566.7 million after one lender with a 5.55% share of the commitments ceased funding under the facility. On March 30, 2009, the credit facility was amended to reflect this reduction. At March 31, 2009, there were no borrowings under this facility and $566.7 million was available.
 
The second facility is a $212.5 million unsecured 364-day facility expiring October 2009, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 1.25 percent to 2.50 percent, based on the Company’s credit ratings. At March 31, 2009, there were no borrowings outstanding under this facility.
 
The third facility was an $18 million unsecured facility that bore interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. At March 31, 2009, there were no borrowings outstanding under this facility. This facility expired on March 31, 2009 and was replaced with a $25 million unsecured facility effective April 1, 2009 that bears interest at a daily negotiated rate.
 
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At March 31, 2009, our total-debt-to-


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
total-capitalization ratio, as defined, was 56 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
 
In addition to these third-party facilities, our regulated operations had a $200 million intercompany revolving credit facility with AEH. Through December 31, 2008, this facility bore interest at the one-month LIBOR rate plus 0.20 percent. In January 2009, this facility was replaced with a new $200 million 364 day-facility that bears interest at the lower of (i) the one-month LIBOR rate plus 0.45 percent or (ii) the marginal borrowing rate available to the Company on the date of borrowing. The marginal borrowing rate is defined as the lower of (i) a rate based upon the lower of the Prime Rate or the Eurodollar rate under the five year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved the new facility through December 31, 2009. There were no borrowings outstanding under this facility at March 31, 2009.
 
Nonregulated Operations
 
On December 30, 2008, AEM and the participating banks amended and restated AEM’s former uncommitted credit facility, primarily to convert the $580 million uncommitted demand credit facility to a 364-day $375 million committed revolving credit facility and extend it to December 29, 2009.
 
The amended facility also provides the ability for AEM to increase the borrowing base up to a maximum of $450 million through an accordion feature, subject to the approval of the participating banks; adds a swing line loan feature; adjusts the interest rate on borrowings as discussed below and increases the fees paid to reflect the facility’s conversion to a committed facility and current credit market conditions. The swing line loan feature allows AEM to borrow, on a same day basis, an amount ranging from $17 million to $27 million based on the terms of an election within the agreement. Effective April 1, 2009, the borrowing base was increased to $450 million as a result of the exercise of the accordion feature in the facility.
 
AEM uses this facility primarily to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. At AEM’s option, borrowings made under the credit facility are based on a base rate or an offshore rate, in each case plus an applicable margin. The base rate is a floating rate equal to the higher of: (a) 0.50 percent per annum above the latest federal funds rate; (b) the per annum rate of interest established by BNP Paribas from time to time as its “prime rate” or “base rate” for U.S. dollar loans; (c) an offshore rate (based on LIBOR with a one-month interest period) as in effect from time to time; and (d) the “cost of funds” rate based on an average of interest rates reported by one or more of the lenders to the administrative agent. The offshore rate is a floating rate equal to the higher of (a) an offshore rate based upon LIBOR for the applicable interest period; and (b) a “cost of funds” rate referred to above. In the case of both base rate and offshore rate loans, the applicable margin ranges from 2.250 percent to 2.625 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.
 
At March 31, 2009, there were no borrowings outstanding under this credit facility. However, at March 31, 2009, AEM letters of credit totaling $48.4 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $201.0 million at March 31, 2009.
 
AEM is required by the financial covenants in this facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At March 31, 2009, AEM’s ratio of total liabilities to tangible net worth, as defined, was 0.83 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $75 million to $112.5 million. As defined in the financial


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
covenants, at March 31, 2009, AEM’s net working capital was $251.5 million and its tangible net worth was $271.3 million.
 
To supplement borrowings under this facility, through December 31, 2008, AEM had a $200 million intercompany demand credit facility with AEH, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Amounts outstanding under this facility are subordinated to AEM’s committed credit facility. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. A total of $60.0 million was outstanding under this facility at March 31, 2009.
 
Finally, through December 31, 2008, AEH had a $200 million intercompany demand credit facility with AEC, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved the new facility through December 31, 2009. There were no borrowings outstanding under this facility at March 31, 2009.
 
Shelf Registration
 
On March 23, 2009, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in common stock and/or debt securities available for issuance, including approximately $450 million of capacity carried over from our prior shelf registration statement filed with the SEC in December 2006.
 
As of March 31, 2009, we had $450 million of availability remaining under the registration statement after completing our Senior Notes Offering. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $300 million of equity securities and $150 million of subordinated debt securities.
 
Debt Covenants
 
In addition to the financial covenants described above, our debt instruments contain various covenants that are usual and customary for debt instruments of these types.
 
Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.
 
Further, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate.
 
Finally, AEM’s credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2. We have no other 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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
We were in compliance with all of our debt covenants as of March 31, 2009. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
 
6.   Earnings Per Share
 
Basic and diluted earnings per share for the three and six months ended March 31, 2009 and 2008 are calculated as follows:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
    (In thousands, except per share amounts)  
 
Net income
  $ 129,003     $ 111,534     $ 204,966     $ 185,337  
                                 
Denominator for basic income per share — weighted average common shares
    90,895       89,314       90,637       89,133  
Effect of dilutive securities:
                               
Restricted and other shares
    639       583       639       585  
Stock options
    33       93       35       99  
                                 
Denominator for diluted income per share — weighted average common shares
    91,567       89,990       91,311       89,817  
                                 
Income per share — basic
  $ 1.42     $ 1.25     $ 2.26     $ 2.08  
                                 
Income per share — diluted
  $ 1.41     $ 1.24     $ 2.24     $ 2.06  
                                 
 
There were approximately 260,000 out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2009. There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2008 as their exercise price was less than the average market price of the common stock during that period.
 
7.   Interim Pension and Other Postretirement Benefit Plan Information
 
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and six months ended March 31, 2009 and 2008 are presented in the following table. All of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
                                 
    Three Months Ended March 31  
    Pension Benefits     Other Benefits  
    2009     2008     2009     2008  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 3,703     $ 3,878     $ 2,946     $ 3,341  
Interest cost
    7,554       6,736       3,520       2,912  
Expected return on assets
    (6,238 )     (6,311 )     (573 )     (715 )
Amortization of transition asset
                378       378  
Amortization of prior service cost
    (183 )     (171 )            
Amortization of actuarial loss
    955       1,926              
                                 
Net periodic pension cost
  $ 5,791     $ 6,058     $ 6,271     $ 5,916  
                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Six Months Ended March 31  
    Pension Benefits     Other Benefits  
    2009     2008     2009     2008  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 7,406     $ 7,756     $ 5,892     $ 6,682  
Interest cost
    15,108       13,472       7,040       5,824  
Expected return on assets
    (12,476 )     (12,621 )     (1,146 )     (1,430 )
Amortization of transition asset
                756       756  
Amortization of prior service cost
    (366 )     (342 )            
Amortization of actuarial loss
    1,910       3,852              
                                 
Net periodic pension cost
  $ 11,582     $ 12,117     $ 12,542     $ 11,832  
                                 
 
The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2009 and 2008 are as follows:
 
                                 
    Pension Benefits     Other Benefits  
    2009     2008     2009     2008  
 
Discount rate
    7.57 %     6.30 %     7.57 %     6.30 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %
Expected return on plan assets
    8.25 %     8.25 %     5.00 %     5.00 %
 
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2009. Based upon this valuation, we expect we will be required to contribute less than $25 million to our pension plans by September 15, 2009.
 
We contributed $5.2 million to our other post-retirement benefit plans during the six months ended March 31, 2009. We expect to contribute a total of approximately $10 million to these plans during fiscal 2009.
 
8.   Commitments and Contingencies
 
Litigation and Environmental Matters
 
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 12 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, there were no material changes in the status of such litigation and environmental-related matters or claims during the six months ended March 31, 2009. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
In addition, we are involved in other litigation and environmental-related matters or claims that arise in the ordinary course of our business. While the ultimate results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we believe the final outcome of such litigation and response actions will not have a material adverse effect on our financial condition, results of operations or cash flows.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Purchase Commitments
 
AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At March 31, 2009, AEM was committed to purchase 97.6 Bcf within one year, 32.5 Bcf within one to three years and 1.0 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year under fixed price contracts with prices ranging from $2.59 to $7.68 per Mcf. Purchases under these contracts totaled $431.5 million and $860.3 million for the three months ended March 31, 2009 and 2008 and $959.0 million and $1,432.3 million for the six months ended March 31, 2009 and 2008.
 
Our natural gas distribution divisions, except for our 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 and fixed prices. The estimated commitments under these contracts as of March 31, 2009 are as follows (in thousands):
 
         
2009
  $ 40,033  
2010
    53,425  
2011
    5,245  
2012
    6,769  
2013
    7,453  
Thereafter
    2,571  
         
    $ 115,496  
         
 
Regulatory Matters
 
As previously described in Note 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, in December 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines.
 
After responding to two sets of data requests received from the Commission, the Commission agreed to allow us to conduct our own internal investigation into compliance with the Commission’s rules. During the second quarter, we completed our internal investigation and submitted the results to the Commission. During our investigation, we identified certain transactions that could possibly be considered non-compliant, and we continue to fully cooperate with the Commission as we work to resolve this matter. We have accrued what we believe is an adequate amount for the anticipated resolution of this proceeding. While the ultimate resolution of this investigation cannot be predicted with certainty, we believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
As of March 31, 2009, rate cases were in progress in our City of Dallas and Virginia service areas and annual rate filing mechanisms were in progress in our Mid-Tex, West Texas, Louisiana and Atmos Pipeline — Texas divisions. These regulatory proceedings are discussed in further detail in Management’s Discussion and Analysis — Recent Ratemaking Developments.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
9.   Concentration of Credit Risk
 
Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. During the six months ended March 31, 2009, there were no material changes in our concentration of credit risk.
 
10.   Segment Information
 
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage business as well as other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local distribution companies and industrial customers primarily in the Midwest and Southeast. Additionally, we provide natural gas transportation and storage services to certain of our natural gas distribution operations and to third parties.
 
We operate the Company through the following four segments:
 
  •  The natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations.
 
  •  The regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division.
 
  •  The natural gas marketing segment, which includes a variety of nonregulated natural gas management services.
 
  •  The pipeline, storage and other segment, which includes our nonregulated natural gas transmission and storage services.
 
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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. 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, 2009 and 2008 by segment are presented in the following tables:
 
                                                 
    Three Months Ended March 31, 2009  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from
external parties
  $ 1,230,196     $ 32,097     $ 549,136     $ 9,977     $     $ 1,821,406  
Intersegment revenues
    224       27,137       159,522       2,295       (189,178 )      
                                                 
      1,230,420       59,234       708,658       12,272       (189,178 )     1,821,406  
Purchased gas cost
    863,340             685,114       1,656       (188,755 )     1,361,355  
                                                 
Gross profit
    367,080       59,234       23,544       10,616       (423 )     460,051  
Operating expenses
                                               
Operation and maintenance
    90,710       17,327       12,323       1,889       (509 )     121,740  
Depreciation and amortization
    47,541       5,006       396       507             53,450  
Taxes, other than income
    55,101       2,572       446       195             58,314  
                                                 
Total operating expenses
    193,352       24,905       13,165       2,591       (509 )     233,504  
                                                 
Operating income
    173,728       34,329       10,379       8,025       86       226,547  
Miscellaneous income (expense)
    835       283       118       2,060       (4,861 )     (1,565 )
Interest charges
    28,821       7,349       3,461       677       (4,775 )     35,533  
                                                 
Income before income taxes
    145,742       27,263       7,036       9,408             189,449  
Income tax expense
    44,166       7,798       3,688       4,794             60,446  
                                                 
Net income
  $ 101,576     $ 19,465     $ 3,348     $ 4,614     $     $ 129,003  
                                                 
Capital expenditures
  $ 84,618     $ 28,303     $ 88     $ 954     $     $ 113,963  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Three Months Ended March 31, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,521,636     $ 22,830     $ 931,990     $ 7,529     $     $ 2,483,985  
Intersegment revenues
    220       28,610       196,663       2,493       (227,986 )      
                                                 
      1,521,856       51,440       1,128,653       10,022       (227,986 )     2,483,985  
Purchased gas cost
    1,164,332             1,112,321       338       (227,400 )     2,049,591  
                                                 
Gross profit
    357,524       51,440       16,332       9,684       (586 )     434,394  
Operating expenses
                                               
Operation and maintenance
    98,578       15,086       5,525       1,536       (672 )     120,053  
Depreciation and amortization
    43,130       4,907       374       379             48,790  
Taxes, other than income
    52,304       1,385       407       312             54,408  
                                                 
Total operating expenses
    194,012       21,378       6,306       2,227       (672 )     223,251  
                                                 
Operating income
    163,512       30,062       10,026       7,457       86       211,143  
Miscellaneous income
    3,670       209       602       1,942       (4,956 )     1,467  
Interest charges
    29,084       6,776       2,002       524       (4,870 )     33,516  
                                                 
Income before income taxes
    138,098       23,495       8,626       8,875             179,094  
Income tax expense
    52,442       8,271       3,347       3,500             67,560  
                                                 
Net income
  $ 85,656     $ 15,224     $ 5,279     $ 5,375     $     $ 111,534  
                                                 
Capital expenditures
  $ 89,671     $ 13,700     $ 38     $ 1,158     $     $ 104,567  
                                                 
 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Six Months Ended March 31, 2009  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,285,968     $ 62,319     $ 1,165,980     $ 23,471     $     $ 3,537,738  
Intersegment revenues
    420       51,597       330,173       5,249       (387,439 )      
                                                 
      2,286,388       113,916       1,496,153       28,720       (387,439 )     3,537,738  
Purchased gas cost
    1,620,924             1,442,586       5,559       (386,594 )     2,682,475  
                                                 
Gross profit
    665,464       113,916       53,567       23,161       (845 )     855,263  
Operating expenses
                                               
Operation and maintenance
    188,704       44,896       20,839       3,073       (1,017 )     256,495  
Depreciation and amortization
    94,680       9,961       797       1,138             106,576  
Taxes, other than income
    95,847       5,360       1,039       205             102,451  
                                                 
Total operating expenses
    379,231       60,217       22,675       4,416       (1,017 )     465,522  
                                                 
Operating income
    286,233       53,699       30,892       18,745       172       389,741  
Miscellaneous income (expense)
    3,956       1,098       419       4,221       (11,560 )     (1,866 )
Interest charges
    61,708       15,428       7,363       1,413       (11,388 )     74,524  
                                                 
Income before income taxes
    228,481       39,369       23,948       21,553             313,351  
Income tax expense
    76,772       12,243       10,025       9,345             108,385  
                                                 
Net income
  $ 151,709     $ 27,126     $ 13,923     $ 12,208     $     $ 204,966  
                                                 
Capital expenditures
  $ 173,621     $ 33,363     $ 117     $ 14,229     $     $ 221,330  
                                                 
 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    Six Months Ended March 31, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,449,665     $ 45,267     $ 1,634,712     $ 11,851     $     $ 4,141,495  
Intersegment revenues
    368       51,219       334,658       4,898       (391,143 )      
                                                 
      2,450,033       96,486       1,969,370       16,749       (391,143 )     4,141,495  
Purchased gas cost
    1,819,309             1,907,075       1,067       (389,988 )     3,337,463  
                                                 
Gross profit
    630,724       96,486       62,295       15,682       (1,155 )     804,032  
Operating expenses
                                               
Operation and maintenance
    195,825       30,518       13,402       2,824       (1,327 )     241,242  
Depreciation and amortization
    85,962       9,823       761       757             97,303  
Taxes, other than income
    87,922       3,829       3,407       677             95,835  
                                                 
Total operating expenses
    369,709       44,170       17,570       4,258       (1,327 )     434,380  
                                                 
Operating income
    261,015       52,316       44,725       11,424       172       369,652  
Miscellaneous income
    4,146       383       1,398       3,970       (8,523 )     1,374  
Interest charges
    60,298       13,847       3,316       1,223       (8,351 )     70,333  
                                                 
Income before income taxes
    204,863       38,852       42,807       14,171             300,693  
Income tax expense
    79,043       13,781       16,928       5,604             115,356  
                                                 
Net income
  $ 125,820     $ 25,071     $ 25,879     $ 8,567     $     $ 185,337  
                                                 
Capital expenditures
  $ 173,984     $ 22,082     $ 69     $ 2,587     $     $ 198,722  
                                                 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at March 31, 2009 and September 30, 2008 by segment is presented in the following tables:
 
                                                 
    March 31, 2009  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
                                               
Property, plant and equipment, net
  $ 3,577,546     $ 608,118     $ 7,312     $ 70,216     $     $ 4,263,192  
Investment in subsidiaries
    484,117             (2,096 )           (482,021 )      
Current assets
                                               
Cash and cash equivalents
    379,391             86,143       16,551             482,085  
Assets from risk management activities
    676             42,266       2,394       (3,623 )     41,713  
Other current assets
    671,993       16,614       265,457       77,428       (76,735 )     954,757  
Intercompany receivables
    504,887                   147,783       (652,670 )      
                                                 
Total current assets
    1,556,947       16,614       393,866       244,156       (733,028 )     1,478,555  
Intangible assets
                1,774                   1,774  
Goodwill
    569,920       132,367       24,282       10,429             736,998  
Noncurrent assets from risk management activities
                9,739                   9,739  
Deferred charges and other assets
    166,610       7,924       873       20,096             195,503  
                                                 
    $ 6,355,140     $ 765,023     $ 435,750     $ 344,897     $ (1,215,049 )   $ 6,685,761  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 2,178,494     $ 157,270     $ 75,451     $ 251,396     $ (484,117 )   $ 2,178,494  
Long-term debt
    2,168,683                   458             2,169,141  
                                                 
Total capitalization
    4,347,177       157,270       75,451       251,854       (484,117 )     4,347,635  
Current liabilities
                                               
Current maturities of long-term debt
    400,000                   225             400,225  
Short-term debt
                60,000             (60,000 )      
Liabilities from risk management activities
    22,535             6,734       1,200       (3,623 )     26,846  
Other current liabilities
    586,656       6,850       203,044       76,973       (14,527 )     858,996  
Intercompany payables
          525,249       127,421             (652,670 )      
                                                 
Total current liabilities
    1,009,191       532,099       397,199       78,398       (730,820 )     1,286,067  
Deferred income taxes
    422,381       71,643       (37,586 )     10,542       (112 )     466,868  
Noncurrent liabilities from risk management activities
    4             13                   17  
Regulatory cost of removal obligation
    313,486                               313,486  
Deferred credits and other liabilities
    262,901       4,011       673       4,103             271,688  
                                                 
    $ 6,355,140     $ 765,023     $ 435,750     $ 344,897     $ (1,215,049 )   $ 6,685,761  
                                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                 
    September 30, 2008  
    Natural
    Regulated
    Natural
    Pipeline,
             
    Gas
    Transmission
    Gas
    Storage and
             
    Distribution     and Storage     Marketing     Other     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
                                               
Property, plant and equipment, net
  $ 3,483,556     $ 585,160     $ 7,520     $ 60,623     $     $ 4,136,859  
Investment in subsidiaries
    463,158             (2,096 )           (461,062 )      
Current assets
                                               
Cash and cash equivalents
    30,878             9,120       6,719             46,717  
Assets from risk management activities
                69,008       20,239       (20,956 )     68,291  
Other current assets
    774,933       18,396       411,648       56,791       (91,672 )     1,170,096  
Intercompany receivables
    578,833                   135,795       (714,628 )      
                                                 
Total current assets
    1,384,644       18,396       489,776       219,544       (827,256 )     1,285,104  
Intangible assets
                2,088                   2,088  
Goodwill
    569,920       132,367       24,282       10,429             736,998  
Noncurrent assets from risk management activities
                5,473                   5,473  
Deferred charges and other assets
    195,985       11,212       1,182       11,798             220,177  
                                                 
    $ 6,097,263     $ 747,135     $ 528,225     $ 302,394     $ (1,288,318 )   $ 6,386,699  
                                                 
CAPITALIZATION AND LIABILITIES
                                               
Shareholders’ equity
  $ 2,052,492     $ 130,144     $ 114,559     $ 218,455     $ (463,158 )   $ 2,052,492  
Long-term debt
    2,119,267                   525             2,119,792  
                                                 
Total capitalization
    4,171,759       130,144       114,559       218,980       (463,158 )     4,172,284  
Current liabilities
                                               
Current maturities of long-term debt
                      785             785  
Short-term debt
    385,592             6,500             (41,550 )     350,542  
Liabilities from risk management activities
    58,566             20,688       616       (20,956 )     58,914  
Other current liabilities
    538,777       7,053       236,217       62,796       (47,997 )     796,846  
Intercompany payables
          543,384       171,244             (714,628 )      
                                                 
Total current liabilities
    982,935       550,437       434,649       64,197       (825,131 )     1,207,087  
Deferred income taxes
    384,860       62,720       (21,936 )     15,687       (29 )     441,302  
Noncurrent liabilities from risk management activities
    5,111             258                   5,369  
Regulatory cost of removal obligation
    298,645                               298,645  
Deferred credits and other liabilities
    253,953       3,834       695       3,530             262,012  
                                                 
    $ 6,097,263     $ 747,135     $ 528,225     $ 302,394     $ (1,288,318 )   $ 6,386,699  
                                                 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Shareholders of
Atmos Energy Corporation
 
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, 2009, the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2009 and 2008, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2009 and 2008. 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, 2008, 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 18, 2008, 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, 2008, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
/s/  Ernst & Young LLP
 
Dallas, Texas
April 30, 2009


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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
INTRODUCTION
 
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2008.
 
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
 
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties, which are discussed in more detail in our Annual Report on Form 10-K for the year ended September 30, 2008, include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of recent economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events; and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
 
OVERVIEW
 
Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.
 
Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.
 
We operate the Company through the following four segments:
 
  •  the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,


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  •  the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division,
 
  •  the natural gas marketing segment, which includes a variety of nonregulated natural gas management services and
 
  •  the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.
 
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
 
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
 
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008 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 quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the six months ended March 31, 2009.
 
RESULTS OF OPERATIONS
 
The following table presents our consolidated financial highlights for the three and six months ended March 31, 2009 and 2008:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
    (In thousands, except per share data)  
 
Operating revenues
  $ 1,821,406     $ 2,483,985     $ 3,537,738     $ 4,141,495  
Gross profit
    460,051       434,394       855,263       804,032  
Operating expenses
    233,504       223,251       465,522       434,380  
Operating income
    226,547       211,143       389,741       369,652  
Miscellaneous income (expense)
    (1,565 )     1,467       (1,866 )     1,374  
Interest charges
    35,533       33,516       74,524       70,333  
Income before income taxes
    189,449       179,094       313,351       300,693  
Income tax expense
    60,446       67,560       108,385       115,356  
Net income
  $ 129,003     $ 111,534     $ 204,966     $ 185,337  
Diluted net income per share
  $ 1.41     $ 1.24     $ 2.24     $ 2.06  


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Our consolidated net income during the three and six months ended March 31, 2009 and 2008 was earned in each of our business segments as follows:
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 101,576     $ 85,656     $ 15,920  
Regulated transmission and storage segment
    19,465       15,224       4,241  
Natural gas marketing segment
    3,348       5,279       (1,931 )
Pipeline, storage and other segment
    4,614       5,375       (761 )
                         
Net income
  $ 129,003     $ 111,534     $ 17,469  
                         
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 151,709     $ 125,820     $ 25,889  
Regulated transmission and storage segment
    27,126       25,071       2,055  
Natural gas marketing segment
    13,923       25,879       (11,956 )
Pipeline, storage and other segment
    12,208       8,567       3,641  
                         
Net income
  $ 204,966     $ 185,337     $ 19,629  
                         
 
The following tables segregate our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 121,041     $ 100,880     $ 20,161  
Nonregulated operations
    7,962       10,654       (2,692 )
                         
Consolidated net income
  $ 129,003     $ 111,534     $ 17,469  
                         
Diluted EPS from regulated operations
  $ 1.32     $ 1.12     $ 0.20  
Diluted EPS from nonregulated operations
    0.09       0.12       (0.03 )
                         
Consolidated diluted EPS
  $ 1.41     $ 1.24     $ 0.17  
                         
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 178,835     $ 150,891     $ 27,944  
Nonregulated operations
    26,131       34,446       (8,315 )
                         
Consolidated net income
  $ 204,966     $ 185,337     $ 19,629  
                         
Diluted EPS from regulated operations
  $ 1.96     $ 1.68     $ 0.28  
Diluted EPS from nonregulated operations
    0.28       0.38       (0.10 )
                         
Consolidated diluted EPS
  $ 2.24     $ 2.06     $ 0.18  
                         


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The following summarizes the results of our operations and other significant events for the six months ended March 31, 2009:
 
  •  Regulated operations generated 87 percent of our net income during the six months ended March 31, 2009 compared to 81 percent during the six months ended March 31, 2008. The $27.9 million increase in our regulated operations net income primarily reflects favorable ratemaking activity coupled with a one-time tax benefit discussed below.
 
  •  Nonregulated operations contributed 13 percent of net income during the six months ended March 31, 2009 compared to 19 percent during the six months ended March 31, 2008. The $8.3 million decrease in our nonregulated operations net income primarily reflects a decrease in unrealized margins and an increase in operating expenses partially offset by favorable asset optimization margins.
 
  •  For the six months ended March 31, 2009, we generated $614.6 million in operating cash flow compared with $479.2 million for the six months ended March 31, 2008, primarily reflecting the favorable impact on our working capital due to the decline in natural gas prices in the current year compared to the prior-year period and the favorable timing of the recovery of gas costs.
 
  •  On March 23, 2009, we filed a $900 million shelf registration statement with the Securities and Exchange Commission (SEC) that replaced our previously existing shelf registration statement. On March 26, 2009, we completed an offering of $450 million unsecured 8.50% senior notes and received net proceeds of approximately $446 million. Most of the net proceeds received were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.
 
  •  Quarter-to-date and year-to-date results were favorably impacted by a one-time tax benefit of $11.3 million, or $0.12 per diluted share. The benefit arose during the quarter when we updated the tax rates used to record our deferred taxes. This benefit increased natural gas distribution net income by $10.5 million and regulated transmission and storage income by $1.7 million. However, net income for the natural gas marketing and pipeline, storage and other segments’ net income were reduced by $0.3 million and $0.6 million.
 
Three Months Ended March 31, 2009 compared with Three Months Ended March 31, 2008
 
Natural Gas Distribution Segment
 
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
 
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
 
Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 90 percent of our residential and commercial meters in the following states for the following time periods:
 
     
Georgia
  October – May
Kansas
  October – May
Kentucky
  November – April
Louisiana
  December – March
Mississippi
  November – April
Tennessee
  November – April
Texas: Mid-Tex
  November – April
Texas: West Texas
  October – May
Virginia
  January – December


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Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income. Prior to January 1, 2009, timing differences exist between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. The effect of these timing differences could be significant in periods of volatile gas prices, particularly in our Mid-Tex Division. These timing differences may favorably or unfavorably affect net income; however, these amounts should offset over time with no permanent impact on net income. Beginning January 1, 2009, changes in our franchise fee agreements in our Mid-Tex Division became effective which should significantly reduce the impact of this timing difference on a prospective basis. However, this timing difference still occurs for gross receipts taxes.
 
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the three months ended March 31, 2009 and 2008 are presented below.
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 367,080     $ 357,524     $ 9,556  
Operating expenses
    193,352       194,012       (660 )
                         
Operating income
    173,728       163,512       10,216  
Miscellaneous income
    835       3,670       (2,835 )
Interest charges
    28,821       29,084       (263 )
                         
Income before income taxes
    145,742       138,098       7,644  
Income tax expense
    44,166       52,442       (8,276 )
                         
Net income
  $ 101,576     $ 85,656     $ 15,920  
                         
Consolidated natural gas distribution sales volumes — MMcf
    121,560       135,568       (14,008 )
Consolidated natural gas distribution transportation volumes — MMcf
    35,061       39,730       (4,669 )
                         
Total consolidated natural gas distribution throughput — MMcf
    156,621       175,298       (18,677 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.48     $ 0.44     $ 0.04  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 7.10     $ 8.59     $ (1.49 )


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The following table shows our operating income by natural gas distribution division, in order of total customers served, for the three months ended March 31, 2009 and 2008. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Mid-Tex
  $ 80,374     $ 72,479     $ 7,895  
Kentucky/Mid-States
    27,404       29,875       (2,471 )
Louisiana
    19,782       19,236       546  
West Texas
    14,806       8,919       5,887  
Mississippi
    16,771       16,514       257  
Colorado-Kansas
    13,623       15,536       (1,913 )
Other
    968       953       15  
                         
Total
  $ 173,728     $ 163,512     $ 10,216  
                         
 
The $9.6 million increase in natural gas distribution gross profit primarily reflects a net $21.9 million increase in rates. The net increase in rates was attributable primarily to the Mid-Tex Division, which increased $16.5 million as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all incorporated cities in the division other than the City of Dallas (the Settled Cities) and rate adjustments for customers in the City of Dallas. The current year period also reflects a $5.4 million increase in rate adjustments primarily in Georgia, Louisiana and West Texas. The increase also reflects the reversal of a $7.0 million accrual for estimated unrecoverable gas costs recorded in a prior year. These increases in gross profit were partially offset by a $13.5 million decrease as a result of an 11 percent decrease in distribution throughput, primarily associated with lower residential and commercial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.
 
Partially offsetting these increases was a decrease of approximately $8.9 million in revenue-related taxes primarily due to lower revenues, on which the tax is calculated, in the current-year quarter compared to the prior-year quarter. This decrease was partially offset by a $0.8 million quarter-over-quarter decrease in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulting in an $8.1 million decrease in operating income when compared with the prior-year quarter.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, decreased $0.7 million.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, decreased $6.9 million, primarily due to lower legal, fuel and other administrative costs.
 
Depreciation and amortization expense increased $4.4 million for the second quarter of fiscal 2009 compared with second quarter of fiscal 2008. The increase primarily was attributable to additional assets placed in service during the current-year period.
 
Results for the quarter include the aforementioned $10.5 million tax benefit, which more than offset the decrease attributable to the absence in the current-year quarter of a $1.2 million gain on the sale of irrigation assets in our West Texas Division in the prior-year quarter.
 
Recent Ratemaking Developments
 
Significant ratemaking developments that occurred during the six months ended March 31, 2009 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s final ruling.


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Annual Rate Filing Mechanisms
 
In March 2009, the Mid-Tex Division filed its second RRM with the Settled Cities. The filing requested an increase in operating income of $9.7 million for the Settled Cities. Representatives of the Settled Cities are currently reviewing the filing and a final determination is expected in July 2009. Beginning in November 2008, rates were implemented from our first RRM filing with the Settled Cities, which resulted in an increase in operating income on a system-wide basis of approximately $27.3 million. The impact to the Mid-Tex Division for the Settled Cities was approximately $21.8 million.
 
In April 2009, the West Texas Division filed its second RRM with the West Texas Cities. The filing requested an increase in operating income of $11.1 million. Representatives of the West Texas Cities are currently reviewing the filing and a final determination is expected in August 2009. Beginning in November 2008, rates were implemented from our first RRM with the West Texas Cities, which resulted in an increase in operating income of $4.5 million, of which $3.9 million is being collected over a 91/2 month period.
 
In April 2009, the City of Lubbock approved an RRM tariff similar to the RRM tariff utilized by the West Texas Cities. The West Texas Division filed its first RRM with the City of Lubbock on April 15, 2009. The filing requested an increase in operating income of $3.5 million. The City of Lubbock is currently reviewing the filing and a final determination is expected in October 2009.
 
In December 2008, the Louisiana Division filed its TransLa annual rate stabilization clause with the Louisiana Public Service Commission (LPSC) for the test year ended September 30, 2008. The filing resulted in an increase in operating income of $0.6 million and was implemented in April 2009.
 
In April 2009, the Louisiana Division filed its LGS annual rate stabilization clause with the LPSC requesting an increase in operating income of $3.9 million. The filing was for the test year ended December 31, 2008. We anticipate final resolution of this proceeding by June 2009.
 
In September 2008, we filed our Mississippi stable rate filing with the Mississippi Public Service Commission (MPSC) requesting an increase of $3.5 million. In January 2009, we withdrew this request after we were unable to reach a mutually agreeable settlement with the MPSC.
 
GRIP Filings
 
In May 2008, the Mid-Tex Division made a GRIP filing seeking a $10.3 million increase on a system-wide basis. However, this filing was only applicable to the City of Dallas and the Mid-Tex environs and sought a $1.8 million increase for customers in those service areas. Rates were approved for this filing in December 2008 and were implemented in January 2009. However, in April 2009, the City of Dallas challenged the legality of the implementation of the GRIP rates, which the Company is contesting in the District Courts of Dallas and Travis Counties.
 
In March 2009, the Mid-Tex Division made a GRIP filing seeking an $18.7 million increase on a system-wide basis. However, this filing is applicable to the City of Dallas only and seeks a $2.7 million increase for customers in the City of Dallas. The City of Dallas has until July 10, 2009 to either accept or object to the filing. If this filing is accepted, the rates will go into effect until such time that they are superseded by the statement of intent filed with the City of Dallas discussed below.
 
Rate Case Filings
 
In October 2008, our Kentucky/Mid-States Division filed a rate case with the Tennessee Regulatory Authority seeking an increase in operating income of $6.3 million. In January 2009, the Consumer Advocate and Protection Division recommended a decrease in rates of $3.7 million. In March 2009, a unanimous stipulation was filed and approved in the case. The parties agreed to an increase in operating income of $2.5 million with a stated return on equity of 10.3 percent. The increase in rates was implemented in April 2009.
 
In November 2008, the Mid-Tex Division filed a statement of intent to increase operating income for customers within the City of Dallas by $9.1 million. The City of Dallas suspended the filing on December 10, 2008 and denied the increase in March 2009. The Company has appealed the filing and in April 2009 we requested an increase in operating income of $7.5 million and concurrently filed for a statement of intent to increase operating income $1.3 million applicable to the Mid-Tex unincorporated areas. A final ruling by the Railroad Commission of Texas (RRC) is expected by October 2009. If the statement of intent applicable to the


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City of Dallas is approved by the RRC, the new rates implemented could supersede the City of Dallas GRIP rates discussed above.
 
In April 2009, the Kentucky/Mid-States Division filed an expedited rate case with the Virginia State Corporation Commission seeking an increase in operating income of $1.7 million. Interim rates will be implemented subject to refund on May 1, 2009. The application is currently in discovery with a final determination expected in October 2009.
 
Other Ratemaking Activity
 
In May 2007, our Mid-Tex Division filed for a 36-month gas contract review filing. This filing was mandated by prior RRC orders and related to the prudency of gas purchases made from November 2003 through October 2006, which total approximately $2.7 billion. The intervening parties recommended disallowances ranging from $58 million to $89 million. A hearing was held at the RRC in September 2008. In December 2008, a proposal for decision was issued by the Hearing Examiner recommending no gas cost disallowance. In February 2009, the RRC approved the Hearing Examiner’s recommendation to disallow no gas costs.
 
Regulated Transmission and Storage Segment
 
Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking and lending arrangements and sales of inventory on hand.
 
Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the three months ended March 31, 2009 and 2008 are presented below.
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 27,061     $ 28,260     $ (1,199 )
Third-party transportation
    23,846       18,229       5,617  
Storage and park and lend services
    2,657       1,862       795  
Other
    5,670       3,089       2,581  
                         
Gross profit
    59,234       51,440       7,794  
Operating expenses
    24,905       21,378       3,527  
                         
Operating income
    34,329       30,062       4,267  
Miscellaneous income
    283       209       74  
Interest charges
    7,349       6,776       573  
                         
Income before income taxes
    27,263       23,495       3,768  
Income tax expense
    7,798       8,271       (473 )
                         
Net income
  $ 19,465     $ 15,224     $ 4,241  
                         
Gross pipeline transportation volumes — MMcf
    193,356       223,476       (30,120 )
                         
Consolidated pipeline transportation volumes — MMcf
    123,285       141,108       (17,823 )
                         


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The $7.8 million increase in gross profit was attributable primarily to a $3.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions and a $3.3 million increase from higher demand-based fees. The improvement in gross profit also reflects a $2.9 million gain on the routine sale of excess gas during the quarter and a $1.4 million increase due to our 2006 and 2007 GRIP filings. These increases were partially offset by a $4.1 million decrease arising from lower city-gate, electrical generation, Barnett Shale and HUB deliveries.
 
Operating expenses increased $3.5 million primarily due to increased employee and pipeline maintenance costs.
 
Results for the quarter also include the aforementioned $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.
 
Recent Ratemaking Developments
 
In February 2009, the Atmos Pipeline — Texas Division made a GRIP filing seeking an increase in operating income of $6.3 million. The filing was approved by the RRC and a final order was issued in April 2009.
 
Natural Gas Marketing Segment
 
Our natural gas marketing activities are conducted through Atmos Energy Marketing, LLC (AEM). AEM aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues received for services we deliver.
 
Our asset optimization activities seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time.
 
AEM continually manages its net physical position to attempt to increase in the future the potential economic gross profit that was created when the original transaction was executed. Therefore, AEM may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market conditions and recognize any associated gains or losses at that time. If AEM elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to economically hedge the original financial instruments. If AEM elects to defer the withdrawal of gas, it will reset its financial instruments by settling the original financial instruments and executing new financial instruments to correspond to the revised withdrawal schedule.
 
We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The hedged natural gas inventory is marked to market at the end of each month based on


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the Gas Daily index with changes in fair value recognized as unrealized gains and losses in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.
 
AEM also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the execution of the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas marketing segment for the three months ended March 31, 2009 and 2008 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.
 
Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical (spot) and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Delivered gas
  $ 23,165     $ 26,195     $ (3,030 )
Asset optimization
    (2,073 )     27,737       (29,810 )
                         
      21,092       53,932       (32,840 )
Unrealized margins
    2,452       (37,600 )     40,052  
                         
Gross profit
    23,544       16,332       7,212  
Operating expenses
    13,165       6,306       6,859  
                         
Operating income
    10,379       10,026       353  
Miscellaneous income
    118       602       (484 )
Interest charges
    3,461       2,002       1,459  
                         
Income before income taxes
    7,036       8,626       (1,590 )
Income tax expense
    3,688       3,347       341  
                         
Net income
  $ 3,348     $ 5,279     $ (1,931 )
                         
Gross natural gas marketing sales volumes — MMcf
    123,066       136,677       (13,611 )
                         
Consolidated natural gas marketing sales volumes — MMcf
    104,973       120,023       (15,050 )
                         
Net physical position (Bcf)
    21.9       20.7       1.2  
                         
 
The $7.2 million increase in our natural gas marketing segment’s gross profit was driven primarily by a $40.1 million increase in unrealized margins. This increase reflects lower volatility during the current quarter


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compared with the prior-year quarter between current cash prices used to value our physical inventory and future natural gas prices, which influence the prices used to value the financial instruments used to hedge our physical inventory.
 
The increase in unrealized margins was partially offset by a $29.8 million decrease in asset optimization margins. During the current quarter, as a result of falling current cash prices, AEM elected to defer storage withdrawals, reset the corresponding financial instruments and inject additional gas into storage to increase the potential gross profit it could realize in future periods from its asset optimization activities. Accordingly, AEM’s results for the quarter reflect lower realized gains from storage withdrawals and the settlement of the associated financial instruments. In the prior-year quarter, AEM elected to withdraw storage and realize the corresponding storage withdrawal gains.
 
In addition, delivered gas margins decreased $3.0 million compared with the prior-year quarter largely attributable to a 10 percent decrease in gross sales volumes, primarily associated with lower industrial demand due to the current economic climate. Per-unit margins for the quarter were approximately two percent lower compared with the prior-year quarter.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $6.9 million primarily due to an increase in legal and other administrative costs.
 
Economic Gross Profit
 
AEM monitors the impact of its asset optimization efforts by estimating the gross profit, before associated storage fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic gross profit, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement is referred to as the potential gross profit.(1) The following table presents AEM’s economic gross profit and its potential gross profit at March 31, 2009, December 31, 2008 and September 30, 2008.
 
                                 
                Associated Net
       
    Net Physical
    Economic
    Unrealized
    Potential Gross
 
Period Ending
  Position     Gross Profit     Gain     Profit(1)  
    (Bcf)     (In millions)     (In millions)     (In millions)  
 
March 31, 2009
    21.9     $ 33.4     $ 2.4     $ 31.0  
December 31, 2008
    16.3     $ 20.7     $ 4.8     $ 15.9  
September 30, 2008
    8.0     $ 48.5     $ 36.4     $ 12.1  
 
 
(1) Potential gross profit represents the increase in AEM’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include storage and other operating expenses and increased income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic gross profit or the potential gross profit will be fully realized in the future. We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides our investors a more comprehensive view of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.
 
As of March 31, 2009, based upon AEM’s planned inventory withdrawal schedule and associated planned settlement of financial instruments, the economic gross profit was $33.4 million. This amount will be reduced by $2.4 million of net unrealized gains recorded in the financial statements as of March 31, 2009 that will reverse when the inventory is withdrawn and the accompanying financial instruments are settled. Therefore, the potential gross profit was $31.0 million at March 31, 2009.
 
During the six months ended March 31, 2009, AEM increased its potential gross profit by $18.9 million to $31.0 million. In the first quarter, AEM withdrew gas and substantially realized the associated potential gross profit reported as of September 30, 2008. Since that time, as a result of falling current cash prices, AEM


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has been deferring storage withdrawals and has been a net injector of gas into storage to increase the potential gross profit it could realize in future periods from its asset optimization activities. As a result of these activities, AEM has increased its net physical position by 13.9 Bcf since September 30, 2008. However, the captured spreads on these positions have been lower than those captured as of September 30, 2008, resulting in a lower economic gross profit compared to that time, but higher than the economic gross profit of $10.8 million as of March 31, 2008. This decrease from September 2008 to March 2009 was partially offset by lower unrealized gains associated with these positions primarily due to lower current cash prices.
 
The economic gross profit is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic gross profit or the potential gross profit calculated as of March 31, 2009 will be fully realized in the future nor can we predict in what time periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted. Assuming AEM fully executes its plan in place on March 31, 2009, without encountering operational or other issues, we anticipate that approximately $1 million of the potential gross profit as of March 31, 2009 will be recognized in fiscal 2009 with the remaining $30 million expected to be recognized during the first six months of fiscal 2010.
 
Pipeline, Storage and Other Segment
 
Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS owns and operates a 21 mile pipeline located in New Orleans, Louisiana. This pipeline is primarily used to aggregate gas supply for our regulated natural gas distribution division in Louisiana and for AEM, but also provides limited third party transportation services.
 
APS also engages in asset optimization activities whereby it seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. Certain of these arrangements are asset management plans with regulated affiliates of the Company which have been approved by applicable state regulatory commissions. Generally, these asset management plans require APS to share with our regulated customers a portion of the profits earned from these arrangements.
 
Further, APS owns or has an interest in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for pipeline capacity to meet customer demand during peak periods. Finally, APS manages our natural gas gathering operations, which were limited in nature as of March 31, 2009.
 
Results for this segment are impacted primarily by seasonal weather patterns and volatility in the natural gas markets. Additionally, this segment’s results include an unrealized component as APS hedges its risk associated with its asset optimization activities.


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Review of Financial and Operating Results
 
Financial and operational highlights for our pipeline, storage and other segment for the three months ended March 31, 2009 and 2008 are presented below.
 
                         
    Three Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Asset optimization
  $ 15,157     $ 6,604     $ 8,553  
Storage and transportation services
    3,312       3,895       (583 )
Other
    350       1,113       (763 )
Unrealized margins
    (8,203 )     (1,928 )     (6,275 )
                         
Gross profit
    10,616       9,684       932  
Operating expenses
    2,591       2,227       364  
                         
Operating income
    8,025       7,457       568  
Miscellaneous income
    2,060       1,942       118  
Interest charges
    677       524       153  
                         
Income before income taxes
    9,408       8,875       533  
Income tax expense
    4,794       3,500       1,294  
                         
Net income
  $ 4,614     $ 5,375     $ (761 )
                         
 
Gross profit from our pipeline, storage and other segment increased $0.9 million primarily due to an $8.6 million increase in asset optimization margins resulting from larger realized gains from the settlement of financial positions associated with storage and trading activities and basis gains earned from utilizing controlled pipeline capacity. These increases were partially offset by a $6.3 million decrease in unrealized margins associated with our asset optimization activities due to a widening of the spreads between current cash prices and forward natural gas prices.
 
Operating expenses for the three months ended March 31, 2009 were consistent with the prior-year quarter.


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Six Months Ended March 31, 2009 compared with Six Months Ended March 31, 2008
 
Natural Gas Distribution Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2009 and 2008 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 665,464     $ 630,724     $ 34,740  
Operating expenses
    379,231       369,709       9,522  
                         
Operating income
    286,233       261,015       25,218  
Miscellaneous income
    3,956       4,146       (190 )
Interest charges
    61,708       60,298       1,410  
                         
Income before income taxes
    228,481       204,863       23,618  
Income tax expense
    76,772       79,043       (2,271 )
                         
Net income
  $ 151,709     $ 125,820     $ 25,889  
                         
Consolidated natural gas distribution sales volumes — MMcf
    213,006       220,335       (7,329 )
Consolidated natural gas distribution transportation
volumes — MMcf
    69,397       73,479       (4,082 )
                         
Total consolidated natural gas distribution
throughput — MMcf
    282,403       293,814       (11,411 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.46     $ 0.44     $ 0.02  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 7.61     $ 8.26     $ (0.65 )
 
The following table shows our operating income by natural gas distribution division, in order of total customers served, for the six months ended March 31, 2009 and 2008. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Mid-Tex
  $ 133,052     $ 122,704     $ 10,348  
Kentucky/Mid-States
    46,429       44,043       2,386  
Louisiana
    34,366       31,168       3,198  
West Texas
    22,819       13,895       8,924  
Mississippi
    25,206       24,343       863  
Colorado-Kansas
    22,224       22,224        
Other
    2,137       2,638       (501 )
                         
Total
  $ 286,233     $ 261,015     $ 25,218  
                         
 
The $34.7 million increase in natural gas distribution gross profit primarily reflects a net $37.2 million increase in rates. The net increase in rates was attributable primarily to the Mid-Tex Division, which increased $27.8 million as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all


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incorporated cities in the division other than the City of Dallas (the Settled Cities) and rate adjustments for customers in the City of Dallas. The current year period also reflects a $9.4 million increase in rate adjustments primarily in Georgia, Kansas, Louisiana and West Texas. The increase in gross profit also reflects the reversal of a $7.0 million uncollectible gas cost accrual recorded in a prior year and an $8.3 million increase attributable to a non-recurring update to our estimate for gas delivered to customers but not yet billed to reflect changes in base rates in several of our jurisdictions recorded in the fiscal first quarter. These increases in gross profit were partially offset by a $14.8 million decrease as a result of a four percent decrease in distribution throughput primarily associated with lower residential and commercial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.
 
Partially offsetting these increases was a decrease of approximately $9.2 million in revenue-related taxes primarily due to lower revenues, on which the tax is calculated, in the current-year period compared to the prior-year period. This decrease, combined with a $7.3 million period-over-period increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in a $16.5 million decrease in operating income when compared with the prior-year period.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $9.5 million.
 
Operation and maintenance expense, excluding the provision for doubtful accounts, decreased $4.7 million, primarily due to lower legal, fuel and other administrative costs. These decreases were partially offset by a $2.1 million noncash charge in the first quarter of fiscal 2009 to impair certain available-for-sale investments due to the recent deterioration of the financial markets.
 
Depreciation and amortization expense increased $8.7 million for the current-year period compared with six months ended March 31, 2008. The increase primarily was attributable to additional assets placed in service during the current-year period.
 
Results for the prior-year period also included a $1.2 million gain on the sale of irrigation assets in our West Texas Division.
 
Interest charges allocated to the natural gas distribution segment increased $1.4 million due to higher average short-term debt balances, interest rates and commitment fees experienced during the current-year period compared to the prior-year period. These increases are associated with the recent adverse conditions in the credit markets.
 
Results for the current-year period include the aforementioned $10.5 million tax benefit associated with updating the rates used to determine our deferred taxes.


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Regulated Transmission and Storage Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2009 and 2008 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 51,413     $ 50,648     $ 765  
Third-party transportation
    49,212       36,461       12,751  
Storage and park and lend services
    5,014       3,901       1,113  
Other
    8,277       5,476       2,801  
                         
Gross profit
    113,916       96,486       17,430  
Operating expenses
    60,217       44,170       16,047  
                         
Operating income
    53,699       52,316       1,383  
Miscellaneous income
    1,098       383       715  
Interest charges
    15,428       13,847       1,581  
                         
Income before income taxes
    39,369       38,852       517  
Income tax expense
    12,243       13,781       (1,538 )
                         
Net income
  $ 27,126     $ 25,071     $ 2,055  
                         
Gross pipeline transportation volumes — MMcf
    385,528       412,340       (26,812 )
                         
Consolidated pipeline transportation volumes — MMcf
    259,143       277,308       (18,165 )
                         
 
The $17.4 million increase in gross profit was attributable primarily to a $7.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions and a $6.4 million increase from higher demand-based fees. The improvement in gross profit also reflects a $2.9 million gain on the sale of excess gas during the current-year period and a $2.7 million increase due to our 2006 and 2007 GRIP filings. These increases were partially offset by a $3.4 million decrease associated with lower city-gate, electrical generation, Barnett Shale and HUB deliveries.
 
Operating expenses increased $16.0 million primarily due to increased employee and pipeline maintenance costs.
 
Results for the current-year period also include the aforementioned $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.


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Natural Gas Marketing Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas marketing segment for the six months ended March 31, 2009 and 2008 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Delivered gas
  $ 41,718     $ 44,368     $ (2,650 )
Asset optimization
    34,866       27,212       7,654  
                         
      76,584       71,580       5,004  
Unrealized margins
    (23,017 )     (9,285 )     (13,732 )
                         
Gross profit
    53,567       62,295       (8,728 )
Operating expenses
    22,675       17,570       5,105  
                         
Operating income
    30,892       44,725       (13,833 )
Miscellaneous income
    419       1,398       (979 )
Interest charges
    7,363       3,316       4,047  
                         
Income before income taxes
    23,948       42,807       (18,859 )
Income tax expense
    10,025       16,928       (6,903 )
                         
Net income
  $ 13,923     $ 25,879     $ (11,956 )
                         
Gross natural gas marketing sales volumes — MMcf
    233,724       245,386       (11,662 )
                         
Consolidated natural gas marketing sales volumes — MMcf
    198,281       216,229       (17,948 )
                         
Net physical position (Bcf)
    21.9       20.7       1.2  
                         
 
The $8.7 million decrease in our natural gas marketing segment’s gross profit was driven primarily by a $13.7 million decrease in unrealized margins. This decrease reflects higher volatility during the current period between current cash prices used to value our physical inventory and future natural gas prices, which influence the prices used to value the financial instruments used to hedge our physical inventory.
 
Additionally, realized delivered gas margins decreased by $2.7 million. The decrease was largely attributable to a five percent decrease in gross sales volumes primarily associated with lower industrial demand due to the current economic climate combined with a one percent decrease in per-unit margins, compared with the prior-year period.
 
The decrease in unrealized margins and delivered gas margins was partially offset by a $7.7 million increase in asset optimization margins. During the first quarter of fiscal 2009, AEM withdrew physical storage inventory and realized the spreads it had captured during fiscal 2008 as a result of deferring storage withdrawals and increasing the spreads associated with those physical positions. These gains were partially offset by the margin loss incurred in the second quarter as a result of deferring storage withdrawals and injecting gas into storage. In the prior-year period, AEM deferred storage withdrawals from the first quarter into the second quarter, and recognized the storage withdrawal gains during the second quarter of fiscal 2008.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $5.1 million primarily due to an increase in legal and other administrative costs partially offset by the absence in the current year of $2.4 million related to tax matters incurred in the prior-year period.


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Pipeline, Storage and Other Segment
 
Review of Financial and Operating Results
 
Financial and operational highlights for our pipeline, storage and other segment for the six months ended March 31, 2009 and 2008 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2009     2008     Change  
    (In thousands)  
 
Asset optimization
  $ 20,624     $ 6,374     $ 14,250  
Storage and transportation services
    6,627       7,023       (396 )
Other
    1,339       1,840       (501 )
Unrealized margins
    (5,429 )     445       (5,874 )
                         
Gross profit
    23,161       15,682       7,479  
Operating expenses
    4,416       4,258       158  
                         
Operating income
    18,745       11,424       7,321  
Miscellaneous income
    4,221       3,970       251  
Interest charges
    1,413       1,223       190  
                         
Income before income taxes
    21,553       14,171       7,382  
Income tax expense
    9,345       5,604       3,741  
                         
Net income
  $ 12,208     $ 8,567     $ 3,641  
                         
 
Gross profit from our pipeline, storage and other segment increased $7.5 million primarily due to a $14.3 million increase in asset optimization margins as a result of larger realized gains from the settlement of financial positions associated with storage and trading activities, basis gains earned from utilizing controlled pipeline capacity and higher margins earned under asset management plans during the current-year period compared with the prior-year period. These increases were partially offset by a $5.9 million decrease in unrealized margins associated with our asset optimization activities due to a widening of the spreads between current cash prices and forward natural gas prices.
 
Operating expenses for the six months ended March 31, 2009 were consistent with the prior-year period.
 
Liquidity and Capital Resources
 
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
 
The primary means we use to fund our working capital needs and growth is to utilize internally generated funds and to access the commercial paper markets. Recent adverse developments in global financial and credit markets have made it more difficult and more expensive for the Company to access the short-term capital markets, including the commercial paper market, to satisfy our liquidity requirements. Consequently, during the first quarter, we experienced higher than normal borrowings under our five-year credit facility used to backstop our commercial paper program in lieu of commercial paper borrowings to fund our working capital needs. However, subsequent to the end of the first quarter, credit market conditions improved, both as to availability and interest rates, and we have been able to access the commercial paper markets on more reasonably economical terms. At March 31, 2009, there were no borrowings or commercial paper outstanding under this facility and $566.7 million was available.


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On March 26, 2009, we closed our offering of $450 million of 8.50% senior notes due 2019. Most of the net proceeds of approximately $446 million were used to redeem our $400 million 4.00% unsecured senior notes, which, on March 30, 2009, were called for redemption on April 30, 2009, prior to their October 2009 maturity. In connection with the repayment of the $400 million 4.00% unsecured senior notes, we paid a $6.6 million call premium in accordance with the terms of the senior notes and accrued interest of approximately $0.6 million. The remaining net proceeds will be used for general corporate purposes.
 
During the six months ended March 31, 2009, we increased our liquidity sources in various ways. In October 2008, we replaced our former $300 million 364-day committed credit facility with a new facility that will allow borrowings up to $212.5 million and expires in October 2009. In December 2008, we converted AEM’s former $580 million uncommitted credit facility to a $375 million committed credit facility that will expire in December 2009. Effective April 1, 2009, we exercised the accordion feature of this facility to increase the credit available under the facility to $450 million. In addition, we replaced our $18 million unsecured committed credit facility that expired in March 2009 with a $25 million unsecured facility effective April 1, 2009. As a result of executing these new agreements, we will have a total of approximately $1.3 billion available to us under four committed credit facilities beginning April 1, 2009. As of March 31, 2009, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $998 million.
 
We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2009.
 
Cash Flows
 
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.
 
Cash flows from operating activities
 
Period-over-period changes in our operating cash flows primarily are attributable to changes in net income and working capital changes, particularly within our natural gas distribution segment resulting from 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, 2009, we generated operating cash flow of $614.6 million from operating activities compared with $479.2 million for the six months ended March 31, 2008. Period over period, the $135.4 million increase was attributable primarily to the favorable impact on our working capital due to the decline in natural gas prices in the current year compared to the prior-year period which increased operating cash flow by $61.2 million, coupled with a $51.9 million increase due to the favorable timing in the recovery of gas costs during the current year.
 
Cash flows from investing activities
 
In recent years, a substantial portion of our cash resources has been used to fund growth projects, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.


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Capital expenditures for fiscal 2009 are expected to range from $500 million to $515 million. For the six months ended March 31, 2009, capital expenditures were $221.3 million compared with $198.7 million for the six months ended March 31, 2008. The increase in capital spending primarily reflects spending for a nonregulated growth project and the construction of a pipeline extension in our regulated operations.
 
Cash flows from financing activities
 
For the six months ended March 31, 2009, our financing activities provided $46.0 million compared with a use of cash of $198.4 million in the prior-year period. Our significant financing activities for the six months ended March 31, 2009 and 2008 are summarized as follows:
 
  •  On March 26, 2009, we issued $450 million of 8.50% senior notes due 2019. The effective interest rate of this offering, inclusive of all debt issue costs, was 8.74 percent. After giving effect to the settlement of our $450 million Treasury lock agreement on March 23, 2009, the effective rate on these senior notes was reduced to 8.69 percent. Most of the net proceeds of approximately $446 million were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.
 
  •  During the six months ended March 31, 2009, we decreased our borrowings by a net $353.5 million under our short-term credit facilities compared with $150.6 million in the prior-year period. The reduction in the net borrowings reflects the timing of the use of our line of credit to finance natural gas purchases and working capital.
 
  •  We repaid $0.6 million of long-term debt during the six months ended March 31, 2009 compared with $2.3 million during the six months ended March 31, 2008. Payments in both periods reflected regularly scheduled payments in accordance with our various debt agreements.
 
  •  During the six months ended March 31, 2009, we paid $60.4 million in cash dividends compared with $58.4 million for the six months ended March 31, 2008. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.65 per share during the six months ended March 31, 2008 to $0.66 per share during the six months ended March 31, 2009 combined with new share issuances under our various equity plans.
 
  •  During the six months ended March 31, 2009, we issued 0.6 million shares of common stock under our various equity plans, which generated net proceeds of $12.4 million. In addition, we issued 0.5 million shares of common stock under our 1998 Long-Term Incentive Plan.
 
The following table summarizes our share issuances for the six months ended March 31, 2009 and 2008.
 
                 
    Six Months Ended
 
    March 31  
    2009     2008  
 
Shares issued:
               
Direct Stock Purchase Plan
    220,361       203,025  
Retirement Savings Plan and Trust
    330,990       268,712  
1998 Long-Term Incentive Plan
    579,990       343,500  
Outside Directors Stock-for-Fee Plan
    1,590       1,602  
                 
Total shares issued
    1,132,931       816,839  
                 
 
Credit Facilities
 
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements. However, our short-term borrowings reach their highest levels in the winter months.


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We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. As of March 31, 2009, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $998 million. These facilities are described in further detail in Note 5 to the unaudited condensed consolidated financial statements.
 
Shelf Registration
 
On March 23, 2009, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in common stock and/or debt securities available for issuance, including approximately $450 million of capacity carried over from our prior shelf registration statement filed with the SEC in December 2006. Immediately following the filing of the registration statement, we issued $450 million of 8.50% senior notes due 2019 under the registration statement. Most of the net proceeds of approximately $446 million were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.
 
As of March 31, 2009, we had $450 million of availability remaining under the registration statement. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $300 million of equity securities and $150 million of subordinated debt securities.
 
Credit Ratings
 
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
 
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). In December 2008, S&P upgraded our credit rating from BBB to BBB+ and affirmed a stable outlook. S&P cited improved financial performance and rate case decisions that have increased cash flow as the key drivers for the upgrade. In January 2009, Moody’s changed our rating outlook from stable to positive. Additionally, our credit rating is currently under review for a possible upgrade by Moody’s. Fitch still maintains its stable outlook. Our current debt ratings are all considered investment grade and are as follows:
 
                         
    S&P   Moody’s   Fitch
 
Unsecured senior long-term debt
    BBB+       Baa3       BBB+  
Commercial paper
    A-2       P-3       F-2  
 
A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of the recent adverse global financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.
 
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.


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Debt Covenants
 
We were in compliance with all of our debt covenants as of March 31, 2009. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.
 
Capitalization
 
The following table presents our capitalization as of March 31, 2009, September 30, 2008 and March 31, 2008:
 
                                                 
    March 31, 2009     September 30, 2008     March 31, 2008  
    (In thousands, except percentages)  
 
Short-term debt
  $       %   $ 350,542       7.7 %   $       %
Long-term debt
    2,569,366       54.1 %     2,120,577       46.9 %     2,128,149       50.0 %
Shareholders’ equity
    2,178,494       45.9 %     2,052,492       45.4 %     2,125,993       50.0 %
                                                 
Total capitalization
  $ 4,747,860       100.0 %   $ 4,523,611       100.0 %   $ 4,254,142       100.0 %
                                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 54.1 percent at March 31, 2009, 54.6 percent at September 30, 2008 and 50.0 percent at March 31, 2008. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. The increase in the debt to capital ratio compared to March 31, 2008 is due to the timing of the repayment of our $400 million unsecured 4.00% unsecured senior notes. Had we repaid the notes as of March 31, 2009, our total-debt-to-capital ratio would have been 49.9 percent. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.
 
Contractual Obligations and Commercial Commitments
 
Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the six months ended March 31, 2009.
 
In February 2008, Atmos Pipeline and Storage, LLC announced plans to construct and operate a salt-cavern gas storage project in Franklin Parish, Louisiana. The project, located near several large interstate pipelines, includes the development of three 5 billion cubic feet (Bcf) caverns for a total of 15 Bcf of working gas storage, with six-turn injection and withdrawal capacity. Testing of the salt core samples was completed in March 2009 which showed favorable conditions for development. We have filed a 7C application with the Federal Energy Regulatory Commission (FERC) to construct and operate the project and expect approval of this request in June 2009. Finally, we have engaged the services of an investment bank to assist us in determining the optimal ownership and/or development alternatives for this project, which is still in process.
 
Risk Management Activities
 
We conduct risk management activities through our natural gas distribution, natural gas marketing and pipeline, storage and other segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.
 
In our natural gas marketing and pipeline, storage and other segments, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.


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The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and six months ended March 31, 2009 and 2008:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (51,314 )   $ (21,528 )   $ (63,677 )   $ (21,053 )
Contracts realized/settled
    (47,231 )     (4,972 )     (100,996 )     (27,310 )
Fair value of new contracts
    277       1,401       (4,006 )     (280 )
Other changes in value
    76,405       34,604       146,816       58,148  
                                 
Fair value of contracts at end of period
  $ (21,863 )   $ 9,505     $ (21,863 )   $ 9,505  
                                 
 
The fair value of our natural gas distribution segment’s financial instruments at March 31, 2009 is presented below by time period and fair value source:
 
                                         
    Fair Value of Contracts at March 31, 2009  
    Maturity in Years        
                      Greater
    Total Fair
 
Source of Fair Value
  Less than 1     1-3     4-5     than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ (21,859 )   $ (4 )   $     $     $ (21,863 )
Prices based on models and other valuation methods
                             
                                         
Total Fair Value
  $ (21,859 )   $ (4 )   $     $     $ (21,863 )
                                         
 
The following table shows the components of the change in fair value of our natural gas marketing segment’s financial instruments for the three and six months ended March 31, 2009 and 2008:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (28,598 )   $ 51,859     $ 16,542     $ 26,808  
Contracts realized/settled
    6,972       (46,331 )     (13,275 )     (41,256 )
Fair value of new contracts
                       
Other changes in value
    (11,020 )     (28,503 )     (35,913 )     (8,527 )
                                 
Fair value of contracts at end of period
    (32,646 )     (22,975 )     (32,646 )     (22,975 )
Netting of cash collateral
    79,098       29,591       79,098       29,591  
                                 
Cash collateral and fair value of contracts at period end
  $ 46,452     $ 6,616     $ 46,452     $ 6,616  
                                 
 
The fair value of our natural gas marketing segment’s financial instruments at March 31, 2009 is presented below by time period and fair value source:
 
                                         
    Fair Value of Contracts at March 31, 2009  
    Maturity in Years        
                      Greater
    Total Fair
 
Source of Fair Value
  Less than 1     1-3     4-5     than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ (42,372 )   $ 9,726     $     $     $ (32,646 )
Prices based on models and other valuation methods
                             
                                         
Total Fair Value
  $ (42,372 )   $ 9,726     $     $     $ (32,646 )
                                         


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Pension and Postretirement Benefits Obligations
 
Effective October 1, 2008, the Company adopted the requirement under SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), that the measurement date used to determine our projected benefit and postretirement obligations and net periodic pension and postretirement costs must correspond to a fiscal year end. In accordance with the transition rules, the impact of changing the measurement date from June 30, 2008 to September 30, 2008 decreased retained earnings by $7.8 million, net of tax, decreased the unrecognized actuarial loss by $9.0 million and increased our postretirement liabilities by $3.5 million.
 
Further, our fiscal 2009 costs were determined using a September 30, 2008 measurement date. As of September 30, 2008, interest and corporate bond rates utilized to determine our discount rates, were significantly higher than the interest and corporate bond rates as of June 30, 2007, the measurement date for our fiscal 2008 net periodic cost. Accordingly, we increased our discount rate used to determine our fiscal 2009 pension and benefit costs to 7.57 percent. We maintained the expected return on our pension plan assets at 8.25 percent, despite the recent decline in the financial markets as we believe this rate reflects the average rate of expected earnings on plan assets that will fund our projected benefit obligation. Although the fair value of our plan assets has declined as the financial markets have declined, the impact of this decline is mitigated by the fact that assets are “smoothed” for purposes of determining net periodic pension cost. Accordingly, asset gains and losses are recognized over time as a component of net periodic pension and benefit costs for our Pension Account Plan, our largest funded plan. Therefore, our fiscal 2009 pension and postretirement medical costs were materially the same as in fiscal 2008.
 
For the six months ended March 31, 2009 and 2008, our total net periodic pension and other benefits cost was $24.1 million and $23.9 million. Those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2009. Based upon this valuation, we expect we will be required to contribute less than $25 million to our pension plans by September 15, 2009. The need for this funding reflects the decline in the fair value of the plans’ assets resulting from the unfavorable market conditions experienced during the latter half of calendar year 2008. This contribution will increase the level of our plan assets to achieve a desirable PPA funding threshold. With respect to our postretirement medical plans, we anticipate contributing a total of approximately $10 million to these plans during fiscal 2009.
 
The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plan are subject to change, depending upon the actuarial value of plan assets and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts are impacted by actual investment returns, changes in interest rates and changes in the demographic composition of the participants in the plan.


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OPERATING STATISTICS AND OTHER INFORMATION
 
The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage, natural gas marketing and pipeline, storage and other segments for the three and six-month periods ended March 31, 2009 and 2008.
 
Natural Gas Distribution Sales and Statistical Data
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
 
METERS IN SERVICE, end of period
                               
Residential
    2,937,865       2,933,980       2,937,865       2,933,980  
Commercial
    274,449       275,998       274,449       275,998  
Industrial
    2,212       2,269       2,212       2,269  
Public authority and other
    9,243       8,948       9,243       8,948  
                                 
Total meters
    3,223,769       3,221,195       3,223,769       3,221,195  
                                 
INVENTORY STORAGE BALANCE — Bcf
    31.9       34.4       31.9       34.4  
SALES VOLUMES — MMcf(1)
                               
Gas sales volumes
                               
Residential
    74,467       83,934       128,675       132,965  
Commercial
    36,689       40,506       65,018       67,126  
Industrial
    5,758       7,258       11,158       13,212  
Public authority and other
    4,646       3,870       8,155       7,032  
                                 
Total gas sales volumes
    121,560       135,568       213,006       220,335  
Transportation volumes
    36,169       40,938       71,454       75,791  
                                 
Total throughput
    157,729       176,506       284,460       296,126  
                                 
OPERATING REVENUES (000’s)(1)
                               
Gas sales revenues
                               
Residential
  $ 785,456     $ 971,673     $ 1,432,556     $ 1,525,962  
Commercial
    334,815       421,708       637,509       690,177  
Industrial
    46,259       62,135       96,414       113,311  
Public authority and other
    36,991       37,244       68,385       67,848  
                                 
Total gas sales revenues
    1,203,521       1,492,760       2,234,864       2,397,298  
Transportation revenues
    16,889       17,786       32,655       32,791  
Other gas revenues
    10,010       11,310       18,869       19,944  
                                 
Total operating revenues
  $ 1,230,420     $ 1,521,856     $ 2,286,388     $ 2,450,033  
                                 
Average transportation revenue per Mcf
  $ 0.47     $ 0.43     $ 0.46     $ 0.43  
Average cost of gas per Mcf sold
  $ 7.10     $ 8.59     $ 7.61     $ 8.26  
 
See footnote following these tables.


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Regulated Transmission and Storage, Natural Gas Marketing and Pipeline, Storage and Other Operations Sales and Statistical Data
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2009     2008     2009     2008  
 
CUSTOMERS, end of period
                               
Industrial
    698       716       698       716  
Municipal
    61       61       61       61  
Other
    527       474       527       474  
                                 
Total
    1,286       1,251       1,286       1,251  
                                 
INVENTORY STORAGE BALANCE — Bcf
                               
Natural gas marketing
    20.4       19.6       20.4       19.6  
Pipeline, storage and other
    2.0       1.2       2.0       1.2  
                                 
Total
    22.4       20.8       22.4       20.8  
                                 
REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf(1)
    193,356       223,476       385,528       412,340  
NATURAL GAS MARKETING SALES
VOLUMES — MMcf(1)
    123,066       136,677       233,724       245,386  
OPERATING REVENUES (000’s)(1)
                               
Regulated transmission and storage
  $ 59,234     $ 51,440     $ 113,916     $ 96,486  
Natural gas marketing
    708,658       1,128,653       1,496,153       1,969,370  
Pipeline, storage and other
    12,272       10,022       28,720       16,749  
                                 
Total operating revenues
  $ 780,164     $ 1,190,115     $ 1,638,789     $ 2,082,605  
                                 
 
Note to preceding tables:
 
 
(1) Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.
 
RECENT ACCOUNTING DEVELOPMENTS
 
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.
 
Item 3.   Quantitative and Qualitative Disclosures About Market Risk
 
Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the year ended September 30, 2008. During the six months ended March 31, 2009, there were no material changes in our quantitative and qualitative disclosures about market risk.
 
Item 4.   Controls and Procedures
 
Management’s Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the


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SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
 
Changes in Internal Control over Financial Reporting
 
We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of the fiscal year ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
PART II. OTHER INFORMATION
 
Item 1.   Legal Proceedings
 
During the six months ended March 31, 2009, except as noted in Note 8 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 12 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
At the Annual Meeting of Shareholders of Atmos Energy Corporation on February 4, 2009, 79,385,275 votes were cast as follows:
 
                         
          Votes
       
    Votes
    Withheld/
    Votes
 
    For     Against     Abstaining  
 
Class I Director:
                       
Ruben E. Esquivel
    77,254,669       2,130,606        
Class II Directors:
                       
Richard W. Cardin
    77,675,895       1,709,380        
Thomas C. Meredith
    77,720,662       1,664,613        
Nancy K. Quinn
    78,057,677       1,327,598        
Stephen R. Springer
    77,027,075       2,358,200        
Richard Ware II
    77,735,952       1,649,323        
Ratification of the Audit Committee’s engagement of Ernst & Young LLP to serve as the Company’s registered independent public accounting firm for fiscal year 2009
    78,424,677       767,618       192,980  
Shareholder proposal regarding declassification of the Board of Directors
    45,212,206       17,596,650       527,384  
 
Mr. Dan Busbee, a Class I director, retired on February 4, 2009, at the conclusion of the Annual Meeting of Shareholders, in accordance with the Board’s mandatory retirement policy. The remaining directors will continue to serve until the expiration of their terms. The term of the Class I directors, Travis W. Bain II, Richard W. Douglas, Ruben E. Esquivel and Richard K. Gordon, will expire in 2011. The term of the Class II directors, Richard W. Cardin, Thomas C. Meredith, Nancy K. Quinn, Stephen R. Springer and Richard Ware II, will expire in 2012. The term of the Class III directors, Robert W. Best, Thomas J. Garland, Phillip E. Nichol and Charles K. Vaughan, will expire in 2010.
 
Item 6.   Exhibits
 
A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.


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SIGNATURE
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
Atmos Energy Corporation
       (Registrant)
 
  By: 
/s/  Fred E. Meisenheimer
Fred E. Meisenheimer
Senior Vice President, Chief Financial
Officer and Controller
(Duly authorized signatory)
 
Date: May 1, 2009


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


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