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 December 31, 2010
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
(State or other jurisdiction of
incorporation or organization)
  75-1743247
(IRS employer
identification no.)
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
(Address of principal executive offices)
  75240
(Zip code)
 
(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 corporate 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 þ      No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o      No þ
 
Number of shares outstanding of each of the issuer’s classes of common stock, as of February 3, 2011.
 
     
Class
 
Shares Outstanding
 
No Par Value
  90,648,911
 


TABLE OF CONTENTS

GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
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 6. Exhibits
SIGNATURE
EXHIBITS INDEX
EX-12
EX-15
EX-31
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT


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.
GAAP
  Generally Accepted Accounting Principles
GRIP
  Gas Reliability Infrastructure Program
GSRS
  Gas System Reliability Surcharge
ISRS
  Infrastructure System Replacement Surcharge
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
PRP
  Pipeline Replacement Program
RRC
  Railroad Commission of Texas
RRM
  Rate Review Mechanism
S&P
  Standard & Poor’s Corporation
SEC
  United States Securities and Exchange Commission
WNA
  Weather Normalization Adjustment


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PART I. FINANCIAL INFORMATION
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,
    September 30,
 
    2010     2010  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 6,638,718     $ 6,542,318  
Less accumulated depreciation and amortization
    1,779,374       1,749,243  
                 
Net property, plant and equipment
    4,859,344       4,793,075  
Current assets
               
Cash and cash equivalents
    129,892       131,952  
Accounts receivable, net
    564,934       273,207  
Gas stored underground
    339,105       319,038  
Other current assets
    229,324       150,995  
                 
Total current assets
    1,263,255       875,192  
Goodwill and intangible assets
    739,991       740,148  
Deferred charges and other assets
    359,033       355,376  
                 
    $ 7,221,623     $ 6,763,791  
                 
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
               
Common stock, no par value (stated at $.005 per share);
               
200,000,000 shares authorized; issued and outstanding:
               
December 31, 2010 — 90,638,491 shares
               
September 30, 2010 — 90,164,103 shares
  $ 453     $ 451  
Additional paid-in capital
    1,724,899       1,714,364  
Retained earnings
    529,900       486,905  
Accumulated other comprehensive income (loss)
    19,601       (23,372 )
                 
Shareholders’ equity
    2,274,853       2,178,348  
Long-term debt
    1,807,319       1,809,551  
                 
Total capitalization
    4,082,172       3,987,899  
Current liabilities
               
Accounts payable and accrued liabilities
    510,085       266,208  
Other current liabilities
    349,914       413,640  
Short-term debt
    247,993       126,100  
Current maturities of long-term debt
    352,434       360,131  
                 
Total current liabilities
    1,460,426       1,166,079  
Deferred income taxes
    892,090       829,128  
Regulatory cost of removal obligation
    354,871       350,521  
Deferred credits and other liabilities
    432,064       430,164  
                 
    $ 7,221,623     $ 6,763,791  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 727,195     $ 802,894  
Regulated transmission and storage segment
    49,007       46,860  
Nonregulated segment
    475,640       548,016  
Intersegment eliminations
    (94,847 )     (104,918 )
                 
      1,156,995       1,292,852  
Purchased gas cost
               
Natural gas distribution segment
    427,423       508,267  
Regulated transmission and storage segment
           
Nonregulated segment
    450,462       478,241  
Intersegment eliminations
    (94,450 )     (104,505 )
                 
      783,435       882,003  
                 
Gross profit
    373,560       410,849  
Operating expenses
               
Operation and maintenance
    116,594       123,862  
Depreciation and amortization
    56,161       53,839  
Taxes, other than income
    40,696       42,552  
                 
Total operating expenses
    213,451       220,253  
                 
Operating income
    160,109       190,596  
Miscellaneous expense
    (737 )     (269 )
Interest charges
    38,917       38,708  
                 
Income before income taxes
    120,455       151,619  
Income tax expense
    46,458       58,289  
                 
Net income
  $ 73,997     $ 93,330  
                 
Basic net income per share
  $ 0.81     $ 1.00  
                 
Diluted net income per share
  $ 0.81     $ 1.00  
                 
Cash dividends per share
  $ 0.340     $ 0.335  
                 
Weighted average shares outstanding:
               
Basic
    90,082       92,152  
                 
Diluted
    90,408       92,509  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (Unaudited)
 
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 73,997     $ 93,330  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization:
               
Charged to depreciation and amortization
    56,161       53,839  
Charged to other accounts
    46       36  
Deferred income taxes
    43,423       12,832  
Other
    4,712       4,382  
Net assets / liabilities from risk management activities
    5,304       (26,891 )
Net change in operating assets and liabilities
    (137,819 )     (42,372 )
                 
Net cash provided by operating activities
    45,824       95,156  
                 
Cash Flows From Investing Activities
               
Capital expenditures
    (123,162 )     (115,439 )
Other, net
    (370 )     (1,873 )
                 
Net cash used in investing activities
    (123,532 )     (117,312 )
                 
Cash Flows From Financing Activities
               
Net increase in short-term debt
    112,628       111,335  
Repayment of long-term debt
    (10,000 )      
Cash dividends paid
    (31,002 )     (31,234 )
Repurchase of equity awards
    (3,231 )      
Issuance of common stock
    7,253       5,681  
                 
Net cash provided by financing activities
    75,648       85,782  
                 
Net increase (decrease) in cash and cash equivalents
    (2,060 )     63,626  
Cash and cash equivalents at beginning of period
    131,952       111,203  
                 
Cash and cash equivalents at end of period
  $ 129,892     $ 174,829  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2010
 
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. Our corporate headquarters and shared-services function are located in Dallas, Texas and our customer support centers are located in Amarillo and Waco, Texas.
 
Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three 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. Our regulated activities also include our regulated pipeline and storage operations, which include the transportation of natural gas to our distribution system and the management of our underground storage facilities. Our regulated businesses are 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 nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc, (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties. AEH also seeks to maximize, through asset optimization activities, the economic value associated with storage and transportation capacity it owns or controls. Certain of these arrangements are with regulated affiliates of the Company, which have been approved by applicable state regulatory commissions.
 
As discussed in Note 10, we operate the Company through the following three 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 our Atmos Pipeline — Texas Division and
 
  •  the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
 
2.   Unaudited Interim Financial Information
 
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. 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, 2010. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2010 are not indicative of our results of operations for the full 2011 fiscal year, which ends September 30, 2011.
 
We have evaluated subsequent events from the December 31, 2010 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as discussed


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
in Note 8, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.
 
Significant accounting policies
 
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. During the three months ended December 31, 2010, two new accounting standards became applicable to the Company pertaining to goodwill impairment testing for reporting units with zero or negative carrying amounts and disclosure of supplementary pro forma information for business combinations. The adoption of these standards did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the quarter ended December 31, 2010.
 
Regulatory assets and liabilities
 
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets 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.
 
Significant regulatory assets and liabilities as of December 31, 2010 and September 30, 2010 included the following:
 
                 
    December 31,
    September 30,
 
    2010     2010  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 206,165     $ 209,564  
Merger and integration costs, net
    6,596       6,714  
Deferred gas costs
    48,205       22,701  
Regulatory cost of removal asset
    38,533       31,014  
Environmental costs
    704       805  
Rate case costs
    4,756       4,505  
Deferred franchise fees
    452       1,161  
Other
    2,643       1,046  
                 
    $ 308,054     $ 277,510  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 8,424     $ 43,333  
Deferred franchise fees
    2,812        
Regulatory cost of removal obligation
    388,391       381,474  
Other
    6,012       6,112  
                 
    $ 405,639     $ 430,919  
                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from applicable state regulatory commissions.
 
Comprehensive income
 
The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2010 and 2009:
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands)  
 
Net income
  $ 73,997     $ 93,330  
Unrealized holding gains on investments, net of tax expense of $455 and $390 for the three months ended December 31, 2010 and 2009
    776       664  
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $18,704 and $248 for the three months ended December 31, 2010 and 2009
    31,847       422  
Net unrealized gains on commodity hedging transactions, net of tax expense of $6,617 and $4,254 for the three months ended December 31, 2010 and 2009
    10,350       6,654  
                 
Comprehensive income
  $ 116,970     $ 101,070  
                 
 
Accumulated other comprehensive income (loss), net of tax, as of December 31, 2010 and September 30, 2010 consisted of the following unrealized gains (losses):
 
                 
    December 31,
    September 30,
 
    2010     2010  
    (In thousands)  
 
Accumulated other comprehensive income (loss):
               
Unrealized holding gains on investments
  $ 4,981     $ 4,205  
Treasury lock agreements(1)
    26,379       (5,468 )
Cash flow hedges
    (11,759 )     (22,109 )
                 
    $ 19,601     $ (23,372 )
                 
 
 
(1) The increase primarily reflects the change in fair value of certain Treasury lock agreements executed in September 2010. See Note 3 for further information.
 
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, 2010. During the first quarter there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our financial instruments do not contain any credit risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions.
 
Regulated Commodity Risk Management Activities
 
Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects 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. Historically, 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 2010-2011 heating season, in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 35 percent, or 31.5 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges.
 
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 costs 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 applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.
 
Nonregulated Commodity Risk Management Activities
 
In our nonregulated operations, we aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver 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 our nonregulated segment. Through asset optimization activities, we seek to enhance our gross profit by maximizing 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 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. 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 inventory should 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 segment is 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 56 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.
 
Also, in our nonregulated operations, 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.
 
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. A risk 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 in order 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. Our operations 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 December 31, 2010, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.5 Bcf.
 
Interest Rate Risk Management Activities
 
We periodically manage interest rate risk by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings.
 
We intend to refinance our $350 million unsecured 7.375% Senior Notes that will mature in May 2011 through the issuance of 30-year unsecured senior notes in June 2011. Additionally, we anticipate issuing $250 million of 30-year unsecured senior notes in November 2011 to fund our capital expenditure program. In September 2010, we entered into five Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuances of these senior notes. We designated all of these Treasury locks as cash flow hedges of an anticipated transaction.
 
In prior years, we entered 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 cumulative 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 the settled Treasury locks extend through fiscal 2035. However, the majority of the remaining amounts associated with the settled Treasury locks will be recognized by the end of fiscal 2019.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 December 31, 2010, 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 December 31, 2010, we had net long/(short) commodity contracts outstanding in the following quantities:
 
                             
        Natural
       
    Hedge
  Gas
       
Contract Type   Designation   Distribution   Nonregulated    
        Quantity (MMcf)    
 
Commodity contracts
  Fair Value           (21,100 )        
    Cash Flow           35,177          
    Not designated     17,171       38,571          
                             
          17,171       52,648          
                             
 
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 December 31, 2010 and September 30, 2010. As required by authoritative accounting literature, 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 $25.3 million and $24.9 million of cash held on deposit as of December 31, 2010 and September 30, 2010 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 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
       
        Gas
       
    Balance Sheet Location   Distribution   Nonregulated   Total
            (In thousands)    
 
December 31, 2010:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 28,489     $ 28,489  
Noncurrent commodity contracts
  Deferred charges and other assets           384       384  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (38,419 )     (38,419 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (7,841 )     (7,841 )
                             
Total
              (17,387 )     (17,387 )
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets     50,653       16,061       66,714  
Noncurrent commodity contracts
  Deferred charges and other assets     77       1,816       1,893  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (22,944 )     (10,330 )     (33,274 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (980 )     (841 )     (1,821 )
                             
Total
        26,806       6,706       33,512  
                             
Total Financial Instruments
      $ 26,806     $ (10,681 )   $ 16,125  
                             
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                             
        Natural
       
        Gas
       
    Balance Sheet Location   Distribution   Nonregulated   Total
            (In thousands)    
 
September 30, 2010:
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 40,030     $ 40,030  
Noncurrent commodity contracts
  Deferred charges and other assets           2,461       2,461  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (56,575 )     (56,575 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (9,222 )     (9,222 )
                             
Total
              (23,306 )     (23,306 )
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets     2,219       16,459       18,678  
Noncurrent commodity contracts
  Deferred charges and other assets     47       2,056       2,103  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (48,942 )     (7,178 )     (56,120 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (2,924 )     (405 )     (3,329 )
                             
Total
        (49,600 )     10,932       (38,668 )
                             
Total Financial Instruments
      $ (49,600 )   $ (12,374 )   $ (61,974 )
                             
 
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 months ended December 31, 2010 and 2009.
 
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended December 31, 2010 and 2009 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $13.5 million and $45.3 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
 
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2010 and 2009 is presented below.
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands)  
 
Commodity contracts
  $ (1,723 )   $ (2,639 )
Fair value adjustment for natural gas inventory designated as the hedged item
    15,625       49,183  
                 
Total impact on revenue
  $ 13,902     $ 46,544  
                 
The impact on revenue is comprised of the following:
               
Basis ineffectiveness
  $ 921     $ 64  
Timing ineffectiveness
    12,981       46,480  
                 
    $ 13,902     $ 46,544  
                 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Cash Flow Hedges
 
The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2010 and 2009 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 are settled.
 
                         
    Three Months Ended December 31, 2010  
    Natural
             
    Gas
             
    Distribution     Nonregulated     Consolidated  
          (In thousands)        
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (14,253 )   $ (14,253 )
Loss arising from ineffective portion of commodity contracts
          (444 )     (444 )
                         
Total impact on revenue
          (14,697 )     (14,697 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (670 )           (670 )
                         
Total Impact from Cash Flow Hedges
  $ (670 )   $ (14,697 )   $ (15,367 )
                         
 
                         
    Three Months Ended December 31, 2009  
    Natural
             
    Gas
             
    Distribution     Nonregulated     Consolidated  
          (In thousands)        
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $ (23,117 )   $ (23,117 )
Loss arising from ineffective portion of commodity contracts
          (1,218 )     (1,218 )
                         
Total impact on revenue
          (24,335 )     (24,335 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (670 )           (670 )
                         
Total Impact from Cash Flow Hedges
  $ (670 )   $ (24,335 )   $ (25,005 )
                         


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 months ended December 31, 2010 and 2009. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands)  
 
Increase (decrease) in fair value:
               
Treasury lock agreements
  $ 31,425     $  
Forward commodity contracts
    1,657       (7,447 )
Recognition of losses in earnings due to settlements:
               
Treasury lock agreements
    422       422  
Forward commodity contracts
    8,693       14,101  
                 
Total other comprehensive income from hedging, net of tax(1)
  $ 42,197     $ 7,076  
                 
 
 
(1) Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.
 
Deferred losses recorded in AOCI associated with our Treasury lock agreements are recognized in earnings as they are amortized, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. 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 December 31, 2010. However, the table below does not include the expected recognition in earnings of the Treasury lock agreements entered into on September 30, 2010 as those instruments have not yet settled.
 
                         
    Treasury
             
    Lock
    Commodity
       
    Agreements     Contracts     Total  
          (In thousands)        
 
Next twelve months
  $ (1,687 )   $ (7,286 )   $ (8,973 )
Thereafter
    (3,702 )     (4,473 )     (8,175 )
                         
Total(1)
  $ (5,389 )   $ (11,759 )   $ (17,148 )
                         
 
 
(1) Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.
 
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 months ended December 31, 2010 and 2009 was an increase in revenue of $4.2 million and $15.3 million. Note that this does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this is not indicative of the economic gross profit we realized when the underlying physical and financial transactions are settled.
 
As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on 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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
4.   Fair Value Measurements
 
We report certain assets and liabilities at fair value, which is defined 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 record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. During the first quarter of fiscal 2011, there were no changes in these methods.
 
Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 8 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2010.
 
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. Authoritative accounting literature 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), with the lowest priority given to unobservable inputs (Level 3). 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 December 31, 2010 and September 30, 2010. As required under authoritative accounting literature, 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
    December 31,
 
    (Level 1)     (Level 2)(1)     (Level 3)     Collateral(2)     2010  
                (In thousands)              
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 50,730     $      —     $     $ 50,730  
Nonregulated segment
    10,006       36,745             (25,033 )     21,718  
                                         
Total financial instruments
    10,006       87,475             (25,033 )     72,448  
Hedged portion of gas stored underground
    84,734                         84,734  
Available-for-sale securities
    42,617                         42,617  
                                         
Total assets
  $ 137,357     $ 87,475     $     $ (25,033 )   $ 199,799  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 23,924     $     $     $ 23,924  
Nonregulated segment
    26,667       30,765             (50,329 )     7,103  
                                         
Total liabilities
  $ 26,667     $ 54,689     $     $ (50,329 )   $ 31,027  
                                         


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Quoted
    Significant
    Significant
             
    Prices in
    Other
    Other
             
    Active
    Observable
    Unobservable
    Netting and
       
    Markets
    Inputs
    Inputs
    Cash
    September 30,
 
    (Level 1)     (Level 2)(1)     (Level 3)     Collateral(3)     2010  
                (In thousands)              
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 2,266     $      —     $     $ 2,266  
Nonregulated segment
    18,544       42,462             (41,760 )     19,246  
                                         
Total financial instruments
    18,544       44,728             (41,760 )     21,512  
Hedged portion of gas stored underground
    57,507                         57,507  
Available-for-sale securities
    41,466                         41,466  
                                         
Total assets
  $ 117,517     $ 44,728     $     $ (41,760 )   $ 120,485  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 51,866     $     $     $ 51,866  
Nonregulated segment
    41,430       31,950             (66,649 )     6,731  
                                         
Total liabilities
  $ 41,430     $ 83,816     $     $ (66,649 )   $ 58,597  
                                         
 
 
(1) Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences.
 
(2) This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of December 31, 2010, we had $25.3 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $8.3 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.0 million is classified as current risk management assets.
 
(3) This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2010 we had $24.9 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $12.3 million is classified as current risk management assets.


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Table of Contents

ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Other Fair Value Measures
 
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of December 31, 2010:
 
         
    December 31,
    2010
    (In thousands)
 
Carrying Amount
  $ 2,162,696  
Fair Value
  $ 2,359,916  
 
5.   Debt
 
Long-term debt
 
Long-term debt at December 31, 2010 and September 30, 2010 consisted of the following:
 
                 
    December 31,
    September 30,
 
    2010     2010  
    (In thousands)  
 
Unsecured 7.375% Senior Notes, due May 2011
  $ 350,000     $ 350,000  
Unsecured 10% Notes, due December 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       450,000  
Unsecured 5.95% Senior Notes, due 2034
    200,000       200,000  
Medium term notes
               
Series A, 1995-2, 6.27%, due December 2010
          10,000  
Series A, 1995-1, 6.67%, due 2025
    10,000       10,000  
Unsecured 6.75% Debentures, due 2028
    150,000       150,000  
Rental property term note due in installments through 2013
    393       393  
                 
Total long-term debt
    2,162,696       2,172,696  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (2,943 )     (3,014 )
Current maturities
    (352,434 )     (360,131 )
                 
    $ 1,807,319     $ 1,809,551  
                 
 
As noted above, our Unsecured 7.375% Senior Notes will mature in May 2011 and our Unsecured 10% Notes will mature in December 2011; accordingly, these have been classified within the current maturities of long-term debt.
 
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 typically reach their highest levels in the winter months.


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Table of Contents

ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 $1.0 billion of working capital funding. At December 31, 2010 and September 30, 2010, there was $248.0 million and $126.1 million outstanding under our commercial paper program. As of December 31, 2010, our commercial paper had maturities of less than one week with an interest rate of 0.33 percent. 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 our 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 $566.7 million unsecured facility, expiring December 15, 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 December 31, 2010, there were no borrowings under this facility, but we had $248.0 million of commercial paper outstanding, leaving $318.7 million available.
 
The second facility is a $200 million unsecured 180-day facility that expires in April 2011. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 1.50 percent to 2.75 percent, based on the Company’s credit ratings. At December 31, 2010, there were no borrowings outstanding under this facility.
 
The third facility is a $25 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. At December 31, 2010, there were no borrowings outstanding under this facility.
 
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 December 31, 2010, our total-debt-to-total-capitalization ratio, as defined, was 54 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 have a $200 million intercompany revolving credit facility with AEH. This facility 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, (ii) a rate based upon the lower of the Prime Rate or the Eurodollar rate under the five year revolving credit facility or (iii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2011 for up to $350 million. There was $117.6 million outstanding under this facility at December 31, 2010.
 
Nonregulated Operations
 
Atmos Energy Marketing, LLC (AEM), a wholly-owned subsidiary of AEH maintains a third-party commercial revolving credit facility primarily to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. On December 8, 2010, AEM and the participating


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Table of Contents

ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
banks amended and restated AEM’s one-year $450 million committed revolving credit facility, replacing it with a $200 million three-year facility with an accordion feature that could increase AEM’s borrowing capacity to $500 million.
 
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 three-month interest period) as in effect from time to time; or (d) the “cost of funds” rate which is the cost of funds as reasonably determined by 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; or (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 1.875 percent to 2.25 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. This facility has swing line loan features, which allow AEM to borrow, on a same day basis, an amount ranging from $6 million to $30 million based on the terms of an election within the agreement. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.
 
At December 31, 2010, there were no borrowings outstanding under this credit facility. However, at December 31, 2010, AEM letters of credit totaling $37.8 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $112.2 million at December 31, 2010.
 
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 December 31, 2010, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.25 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at December 31, 2010, AEM’s net working capital was $195.8 million and its tangible net worth was $207.0 million.
 
Finally, AEH had a $200 million intercompany demand credit facility with AEC, which bore interest at greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. In October 2010, we received regulatory approval to increase this facility, effective December 1, 2010 through December 31, 2011, to $350 million with substantially the same terms. There were no borrowings outstanding under this facility at December 31, 2010.
 
Shelf Registration
 
We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we will be able to issue a total of $950 million in debt securities and $350 million in equity securities. At December 31, 2010, no amounts have been drawn down against the shelf registration statement.
 
Debt Covenants
 
In addition to the financial covenants described above, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
We were in compliance with all of our debt covenants as of December 31, 2010. 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
 
Since we have non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents (referred to as participating securities) we are required to use the two-class method of computing earnings per share. The Company’s non-vested restricted stock and restricted stock units, for which vesting is predicated solely on the passage of time granted under the 1998 Long-Term Incentive Plan, are considered to be participating securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three months ended December 31, 2010 and 2009 are calculated as follows:
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands, except per share amounts)  
 
Basic Earnings Per Share
               
Net income
  $ 73,997     $ 93,330  
Less: Income allocated to participating securities
    779       1,037  
                 
Net income available to common shareholders
  $ 73,218     $ 92,293  
                 
Basic weighted average shares outstanding
    90,082       92,152  
                 
Net income per share — Basic
  $ 0.81     $ 1.00  
                 
Diluted Earnings Per Share
               
Net income available to common shareholders
  $ 73,218     $ 92,293  
Effect of dilutive stock options and other shares
    2       3  
                 
Net income available to common shareholders
  $ 73,220     $ 92,296  
                 
Basic weighted average shares outstanding
    90,082       92,152  
Additional dilutive stock options and other shares
    326       357  
                 
Diluted weighted average shares outstanding
    90,408       92,509  
                 
Net income per share — Diluted
  $ 0.81     $ 1.00  
                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2010 and 2009 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 months ended December 31, 2010 and 2009 are presented in the following table. Most 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.
 
In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Pension Account Plan (PAP) to new participants, effective October 1, 2010. Employees participating in the PAP as of October 1, 2010 were allowed to make a one-time election to migrate from the PAP into our defined contribution plan with enhanced features, effective January 1, 2011. Participants who chose to remain in the PAP will continue to earn benefits and interest allocations with no changes to their existing benefits. During the first quarter ended December 31, 2010, a limited number of participants elected to join the new plan, which resulted in an immaterial curtailment gain and a revaluation of the net periodic pension cost for the remainder of fiscal 2011. The curtailment gain will be recorded in our second fiscal quarter. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective January 1, 2011 to 5.68 percent, which will reduce our net periodic pension cost by approximately $1.8 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.
 
                                 
    Three Months Ended December 31  
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 4,380     $ 3,993     $ 3,601     $ 3,360  
Interest cost
    6,924       6,524       3,203       3,018  
Expected return on assets
    (5,963 )     (6,320 )     (682 )     (615 )
Amortization of transition asset
                378       378  
Amortization of prior service cost
    (112 )     (193 )     (362 )     (375 )
Amortization of actuarial loss
    3,494       2,822       87       93  
                                 
Net periodic pension cost
  $ 8,723     $ 6,826     $ 6,225     $ 5,859  
                                 
 
The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2010 and 2009 are as follows:
 
                                 
    Pension Benefits     Other Benefits  
    2010     2009     2010     2009  
 
Discount rate
    5.39 %     5.52 %     5.39 %     5.52 %
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
2006 (PPA), we determined the funded status of our plans as of January 1, 2011. Based upon this valuation, we expect we will be required to contribute less than $2 million to our pension plans by September 15, 2011.
 
We contributed $2.7 million to our other post-retirement benefit plans during the three months ended December 31, 2010. We expect to contribute a total of approximately $11 million to these plans during fiscal 2011.
 
For our Supplemental Executive Retirement Plans, we own equity securities that are classified as available-for-sale securities. These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.
 
Assets for the supplemental plans are held in separate rabbi trusts and comprise the following:
 
                                 
          Gross
    Gross
       
    Amortized
    Unrealized
    Unrealized
       
    Cost     Gain     Loss     Fair Value  
    (In thousands)  
 
As of December 31, 2010:
                               
Domestic equity mutual funds
  $ 28,686     $ 6,598     $      —     $ 35,284  
Foreign equity mutual funds
    4,426       1,308             5,734  
Money market funds
    1,599                   1,599  
                                 
    $ 34,711     $ 7,906     $     $ 42,617  
                                 
As of September 30, 2010:
                               
Domestic equity mutual funds
  $ 29,540     $ 5,698     $     $ 35,238  
Foreign equity mutual funds
    4,753       976             5,729  
Money market funds
    499                   499  
                                 
    $ 34,792     $ 6,674     $     $ 41,466  
                                 
 
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, 2010, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2010. 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.
 
Since April 2009, Atmos Energy and two subsidiaries of AEH, AEM and Atmos Gathering Company, LLC, have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.
 
During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.
 
A hearing is scheduled on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. In the event the trial judge denies these motions, Atmos Energy will appeal the decision. We strongly believe that the trial court erred in not granting our motion to dismiss the lawsuit prior to trial and that the verdict is unsupported by law. After consultation with counsel, we believe that it is probable that any judgment based on this verdict would be overturned on appeal.
 
We have accrued what we believe is an adequate amount for the anticipated resolution of this matter; however, the amount accrued does not reflect the amount of the verdict. The Company does not have insurance coverage that could mitigate any losses that may arise from the resolution of this matter; however, we believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
In addition, we are involved in other litigation and environmental-related matters or claims that arise in the ordinary course of our business. While the ultimate results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we believe the final outcome of such litigation and response actions will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
Purchase Commitments
 
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2010, AEH was committed to purchase 74.1 Bcf within one year, 36.2 Bcf within one to three years and 6.4 Bcf after three years under indexed contracts. AEH is committed to purchase 3.1 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $3.87 to $6.36 per Mcf. Purchases under these contracts totaled $334.2 million and $354.1 million for the three months ended December 31, 2010 and 2009.
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in this service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of December 31, 2010 are as follows (in thousands):
 
         
2011
  $ 178,340  
2012
    73,729  
2013
    5,353  
2014
    2,311  
2015
     
Thereafter
     
         
    $ 259,733  
         
 
Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. There were no material changes to the estimated storage and transportation fees for the quarter ended December 31, 2010.
 
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, 2010, 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. There have been no material developments in this matter during the quarter ended December 31, 2010. 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.
 
We have been replacing certain steel service lines in our Mid-Tex Division since our acquisition of the natural gas distribution system in 2004. Since early 2010, we have been discussing the financial and operational details of an accelerated steel service line replacement program with representatives of 440 municipalities served by our Mid-Tex Division. As previously discussed in Note 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, all of the cities our Mid-Tex Division serves have agreed to a program of installing 100,000 replacements during the next two years, with approved recovery of the associated return, depreciation and taxes. Under the terms of the agreement, the accelerated replacement program commenced in the first quarter of fiscal 2011, replacing 8,079 lines for a cost of $10.0 million. The program is progressing on schedule for completion in September 2012.
 
In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act, which we expect will provide additional clarity regarding the extent of the impact of this legislation on us. The costs of participating in financial markets for hedging certain risks inherent in our business may be increased as a result of the new legislation. We may also incur additional costs associated with compliance with new regulations and anticipate additional reporting and disclosure obligations.
 
As of December 31, 2010, rate cases were in progress in our Atmos Pipeline — Texas and West Texas service areas and annual rate filing mechanisms were in progress in our Louisiana and Mississippi service


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
areas. In addition, there were other ratemaking activities in progress in our Kansas and Missouri service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
 
9.   Concentration of Credit Risk
 
Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. During the three months ended December 31, 2010, there were no material changes in our concentration of credit risk.
 
10.   Segment Information
 
Through November 30, 2010, our operations were divided into four segments:
 
  •  The natural gas distribution segment, which included our regulated natural gas distribution and related sales operations.
 
  •  The regulated transmission and storage segment, which included the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division.
 
  •  The natural gas marketing segment, which included a variety of nonregulated natural gas management services.
 
  •  The pipeline, storage and other segment, which included our nonregulated natural gas gathering transmission and storage services.
 
As a result of the appointment of a new CEO effective October 1, 2010, during the first quarter of fiscal 2011, we revised the information used by the chief operating decision maker to manage the Company. As a result of this change, effective December 1, 2010, we began dividing our operations into the following three segments:
 
  •  The natural gas distribution segment, remains unchanged and includes our regulated natural gas distribution and related sales operations.
 
  •  The regulated transmission and storage segment, remains unchanged and includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division.
 
  •  The nonregulated segment, is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services which were previously reported in the natural gas marketing and pipeline, storage and other segments.
 
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, 2010. 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 month periods ended December 31, 2010 and 2009 by segment are presented in the following tables to reflect our business structure as of December 31, 2010. Prior-year amounts have been restated accordingly.
 
                                         
    Three Months Ended December 31, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 726,994     $ 21,233     $ 408,768     $     $ 1,156,995  
Intersegment revenues
    201       27,774       66,872       (94,847 )      
                                         
      727,195       49,007       475,640       (94,847 )     1,156,995  
Purchased gas cost
    427,423             450,462       (94,450 )     783,435  
                                         
Gross profit
    299,772       49,007       25,178       (397 )     373,560  
Operating expenses
                                       
Operation and maintenance
    91,333       15,574       10,084       (397 )     116,594  
Depreciation and amortization
    49,278       5,799       1,084             56,161  
Taxes, other than income
    34,976       3,553       2,167             40,696  
                                         
Total operating expenses
    175,587       24,926       13,335       (397 )     213,451  
                                         
Operating income
    124,185       24,081       11,843             160,109  
Miscellaneous income (expense)
    (709 )     (282 )     290       (36 )     (737 )
Interest charges
    29,719       8,064       1,170       (36 )     38,917  
                                         
Income before income taxes
    93,757       15,735       10,963             120,455  
Income tax expense
    36,439       5,633       4,386             46,458  
                                         
Net income
  $ 57,318     $ 10,102     $ 6,577     $     $ 73,997  
                                         
Capital expenditures
  $ 109,499     $ 12,739     $ 924     $     $ 123,162  
                                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Three Months Ended December 31, 2009  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 802,686     $ 19,842     $ 470,324     $     $ 1,292,852  
Intersegment revenues
    208       27,018       77,692       (104,918 )      
                                         
      802,894       46,860       548,016       (104,918 )     1,292,852  
Purchased gas cost
    508,267             478,241       (104,505 )     882,003  
                                         
Gross profit
    294,627       46,860       69,775       (413 )     410,849  
Operating expenses
                                       
Operation and maintenance
    96,033       17,579       10,663       (413 )     123,862  
Depreciation and amortization
    47,857       4,942       1,040             53,839  
Taxes, other than income
    37,990       3,267       1,295             42,552  
                                         
Total operating expenses
    181,880       25,788       12,998       (413 )     220,253  
                                         
Operating income
    112,747       21,072       56,777             190,596  
Miscellaneous income (expense)
    657       43       376       (1,345 )     (269 )
Interest charges
    29,678       7,968       2,407       (1,345 )     38,708  
                                         
Income before income taxes
    83,726       13,147       54,746             151,619  
Income tax expense
    32,278       4,693       21,318             58,289  
                                         
Net income
  $ 51,448     $ 8,454     $ 33,428     $     $ 93,330  
                                         
Capital expenditures
  $ 100,462     $ 13,759     $ 1,218     $     $ 115,439  
                                         

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at December 31, 2010 and September 30, 2010 by segment is presented to reflect our business structure as of December 31, 2010 in the following tables. Prior-year amounts have been restated accordingly.
 
                                         
    December 31, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
                (In thousands)              
 
ASSETS
                                       
Property, plant and equipment, net
  $ 4,020,501     $ 753,679     $ 85,164     $     $ 4,859,344  
Investment in subsidiaries
    647,892             (2,096 )     (645,796 )      
Current assets
                                       
Cash and cash equivalents
    36,144             93,748             129,892  
Assets from risk management activities
    50,653             21,718             72,371  
Other current assets
    774,001       11,908       418,599       (143,516 )     1,060,992  
Intercompany receivables
    520,489                   (520,489 )      
                                         
Total current assets
    1,381,287       11,908       534,065       (664,005 )     1,263,255  
Intangible assets
                677             677  
Goodwill
    572,262       132,341       34,711             739,314  
Noncurrent assets from risk management activities
    77                         77  
Deferred charges and other assets
    334,654       8,210       16,092             358,956  
                                         
    $ 6,956,673     $ 906,138     $ 668,613     $ (1,309,801 )   $ 7,221,623  
                                         
CAPITALIZATION AND LIABILITIES
                                       
Shareholders’ equity
  $ 2,274,853     $ 222,788     $ 425,104     $ (647,892 )   $ 2,274,853  
Long-term debt
    1,807,057             262             1,807,319  
                                         
Total capitalization
    4,081,910       222,788       425,366       (647,892 )     4,082,172  
Current liabilities
                                       
Current maturities of long-term debt
    352,303             131             352,434  
Short-term debt
    365,614                   (117,621 )     247,993  
Liabilities from risk management activities
    22,944             621             23,565  
Other current liabilities
    618,402       12,779       229,052       (23,799 )     836,434  
Intercompany payables
          516,442       4,047       (520,489 )      
                                         
Total current liabilities
    1,359,263       529,221       233,851       (661,909 )     1,460,426  
Deferred income taxes
    740,068       149,100       2,922             892,090  
Noncurrent liabilities from risk management activities
    980             6,482             7,462  
Regulatory cost of removal obligation
    354,871                         354,871  
Deferred credits and other liabilities
    419,581       5,029       (8 )           424,602  
                                         
    $ 6,956,673     $ 906,138     $ 668,613     $ (1,309,801 )   $ 7,221,623  
                                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    September 30, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
                (In thousands)              
 
ASSETS
                                       
Property, plant and equipment, net
  $ 3,959,112     $ 748,947     $ 85,016     $     $ 4,793,075  
Investment in subsidiaries
    620,863             (2,096 )     (618,767 )      
Current assets
                                       
Cash and cash equivalents
    31,952             100,000             131,952  
Assets from risk management activities
    2,219             18,356             20,575  
Other current assets
    528,655       19,504       325,348       (150,842 )     722,665  
Intercompany receivables
    546,313                   (546,313 )      
                                         
Total current assets
    1,109,139       19,504       443,704       (697,155 )     875,192  
Intangible assets
                834             834  
Goodwill
    572,262       132,341       34,711             739,314  
Noncurrent assets from risk management activities
    47             890             937  
Deferred charges and other assets
    324,707       13,037       16,695             354,439  
                                         
    $ 6,586,130     $ 913,829     $ 579,754     $ (1,315,922 )   $ 6,763,791  
                                         
CAPITALIZATION AND LIABILITIES
                                       
Shareholders’ equity
  $ 2,178,348     $ 212,687     $ 408,176     $ (620,863 )   $ 2,178,348  
Long-term debt
    1,809,289             262             1,809,551  
                                         
Total capitalization
    3,987,637       212,687       408,438       (620,863 )     3,987,899  
Current liabilities
                                       
Current maturities of long-term debt
    360,000             131             360,131  
Short-term debt
    258,488                   (132,388 )     126,100  
Liabilities from risk management activities
    48,942             731             49,673  
Other current liabilities
    473,076       10,949       162,508       (16,358 )     630,175  
Intercompany payables
          543,007       3,306       (546,313 )      
                                         
Total current liabilities
    1,140,506       553,956       166,676       (695,059 )     1,166,079  
Deferred income taxes
    691,126       142,337       (4,335 )           829,128  
Noncurrent liabilities from risk management activities
    2,924             6,000             8,924  
Regulatory cost of removal obligation
    350,521                         350,521  
Deferred credits and other liabilities
    413,416       4,849       2,975             421,240  
                                         
    $ 6,586,130     $ 913,829     $ 579,754     $ (1,315,922 )   $ 6,763,791  
                                         

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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 December 31, 2010, the related condensed consolidated statements of income for the three-month periods ended December 31, 2010 and 2009, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2010 and 2009. 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, 2010, 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 12, 2010, 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, 2010, 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
February 9, 2011


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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, 2010.
 
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 include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; 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; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change 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 its 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 over three 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 regulated distribution and pipeline systems.
 
Through our nonregulated businesses, we provide natural gas management and transportation services to municipalities, natural gas distribution companies including certain of our natural gas distribution divisions and third parties primarily in the Midwest and Southeast. Through our asset optimization activities, we also seek to maximize the economic value associated with the storage and transportation capacity we own or control.


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As discussed in Note 10, as a result of the appointment of a new CEO effective October 1, 2010, during the first quarter of fiscal 2011, we revised the information used by the chief operating decision maker to manage the Company. As a result of this change, effective December 1, 2010, we began dividing our operations into the following three 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 our Atmos Pipeline — Texas Division and
 
  •  the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other 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, the 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, 2010 and include the following:
 
  •  Regulation
 
  •  Revenue Recognition
 
  •  Allowance for Doubtful Accounts
 
  •  Financial Instruments and Hedging Activities
 
  •  Impairment Assessments
 
  •  Pension and Other Postretirement Plans
 
  •  Fair Value Measurements
 
Our critical accounting policies are reviewed quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the three months ended December 31, 2010.
 
RESULTS OF OPERATIONS
 
We reported net income of $74.0 million, or $0.81 per diluted share for the three months ended December 31, 2010 compared with net income of $93.3 million, or $1.00 per diluted share in the prior-year quarter. Regulated operations contributed 91 percent of our net income during this period with our nonregulated operations contributing the remaining nine percent. Excluding the impact of unrealized margins, diluted earnings per share increased $0.10 compared with the prior-year quarter. The $0.10 per diluted share improvement reflects increased gross profit in our regulated operations from ratemaking activities, a 4 percent increase in regulated transmission and storage volumes and an 8 percent increase in nonregulated delivered gas volumes. These increases were partially offset by a 10 percent decline in natural gas distribution volumes and the continued adverse impact of low natural gas price volatility, which contributed to a decline in nonregulated per-unit delivered gas margins and realized asset optimization margins.


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During the quarter, we executed on our strategy to streamline our credit facilities. In October 2010, we replaced our $200 million 364-day revolving credit agreement prior to its expiration with a $200 million 180-day revolving credit agreement. Additionally, in December 2010, we replaced Atmos Energy Marketing’s (AEM) $450 million 364-day revolving credit facility with a $200 million three-year facility with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The new credit facilities should continue to help ensure we have sufficient liquidity to fund our working capital needs while reducing our financing costs.
 
The following table presents our consolidated financial highlights for the three months ended December 31, 2010 and 2009:
 
                 
    Three Months Ended
    December 31
    2010   2009
    (In thousands, except per share data)
 
Operating revenues
  $ 1,156,995     $ 1,292,852  
Gross profit
    373,560       410,849  
Operating expenses
    213,451       220,253  
Operating income
    160,109       190,596  
Miscellaneous expense
    (737 )     (269 )
Interest charges
    38,917       38,708  
Income before income taxes
    120,455       151,619  
Income tax expense
    46,458       58,289  
Net income
  $ 73,997     $ 93,330  
Diluted net income per share
  $ 0.81     $ 1.00  
 
Our consolidated net income during the three months ended December 31, 2010 and 2009 was earned in each of our business segments as follows:
 
                         
    Three Months Ended
 
    December 31  
    2010     2009     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 57,318     $ 51,448     $ 5,870  
Regulated transmission and storage segment
    10,102       8,454       1,648  
Nonregulated segment
    6,577       33,428       (26,851 )
                         
Net income
  $ 73,997     $ 93,330     $ (19,333 )
                         
 
The following table reflects our consolidated net income and diluted earnings per share in our regulated and nonregulated operations:
 
                         
    Three Months Ended
 
    December 31  
    2010     2009     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 67,420     $ 59,902     $ 7,518  
Nonregulated operations
    6,577       33,428       (26,851 )
                         
Consolidated net income
  $ 73,997     $ 93,330     $ (19,333 )
                         
Diluted EPS from regulated operations
  $ 0.74     $ 0.64     $ 0.10  
Diluted EPS from nonregulated operations
    0.07       0.36       (0.29 )
                         
Consolidated diluted EPS
  $ 0.81     $ 1.00     $ (0.19 )
                         


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Three Months Ended December 31, 2010 compared with Three Months Ended December 31, 2009
 
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, Kansas, West Texas
  October — May
Kentucky, Mississippi, Tennessee, Mid-Tex
  November — April
Louisiana
  December — March
Virginia
  January — December
 
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas includes 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 these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
 
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.


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Review of Financial and Operating Results
 
Financial and operational highlights for our natural gas distribution segment for the three months ended December 31, 2010 and 2009 are presented below.
 
                         
    Three Months Ended
 
    December 31  
    2010     2009     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 299,772     $ 294,627     $ 5,145  
Operating expenses
    175,587       181,880       (6,293 )
                         
Operating income
    124,185       112,747       11,438  
Miscellaneous income (expense)
    (709 )     657       (1,366 )
Interest charges
    29,719       29,678       41  
                         
Income before income taxes
    93,757       83,726       10,031  
Income tax expense
    36,439       32,278       4,161  
                         
Net income
  $ 57,318     $ 51,448     $ 5,870  
                         
Consolidated natural gas distribution sales volumes — MMcf
    86,790       99,314       (12,524 )
Consolidated natural gas distribution transportation volumes —
                       
MMcf
    33,754       35,207       (1,453 )
                         
Total consolidated natural gas distribution throughput —
                       
MMcf
    120,544       134,521       (13,977 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.49     $ 0.46     $ 0.03  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 4.92     $ 5.12     $ (0.20 )
 
The following table shows our operating income by natural gas distribution division, in order of total rate base, for the three months ended December 31, 2010 and 2009. 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
 
    December 31  
    2010     2009     Change  
    (In thousands)  
 
Mid-Tex
  $ 57,439     $ 50,381     $ 7,058  
Kentucky/Mid-States
    21,363       17,803       3,560  
Louisiana
    14,961       13,407       1,554  
West Texas
    9,520       11,757       (2,237 )
Colorado-Kansas
    8,012       8,606       (594 )
Mississippi
    10,215       9,802       413  
Other
    2,675       991       1,684  
                         
Total
  $ 124,185     $ 112,747     $ 11,438  
                         
 
The $5.1 million increase in natural gas distribution gross profit primarily reflects a $14.1 million increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Missouri, Kentucky and Kansas service areas.


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These increases were partially offset by:
 
  •  $4.9 million decrease due to a ten percent decrease in consolidated throughput caused principally by warmer weather this fiscal quarter compared to the same period last year in most of our service areas.
 
  •  $2.7 million decrease in revenue taxes, offset by revenue-related franchise taxes, as discussed below.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income decreased $6.3 million, primarily due to the following:
 
  •  $2.9 million decrease in franchise taxes.
 
  •  $2.6 million decrease in employee-related expenses.
 
  •  $1.4 million decrease in legal and other administrative costs.
 
Miscellaneous income decreased $1.4 million primarily due to a decrease in interest income.
 
Recent Ratemaking Developments
 
Significant ratemaking developments that occurred during the three months ended December 31, 2010 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 or other governmental authority’s final ruling.
 
Annual net operating income increases totaling $24.2 million resulting from ratemaking activity became effective in the quarter ended December 31, 2010 as summarized below:
 
         
    Annual Increase to
 
Rate Action
  Operating Income  
    (In thousands)  
 
Annual rate filing mechanisms
  $ 23,122  
Other rate activity
    1,113  
         
    $ 24,235  
         
 
Additionally, the following ratemaking efforts were in progress during the first quarter of fiscal 2011 but had not been completed as of December 31, 2010.
 
                 
            Operating
 
            Income
 
Division
 
Rate Action
 
Jurisdiction
  Requested  
            (In thousands)  
 
Atmos Pipeline - Texas
  Rate Case   Texas Railroad
Commission
  $ 35,282  
Colorado-Kansas
  Ad Valorem True Up(1)   Kansas     685  
Kentucky/Mid-States
  ISRS(2)   Missouri     382  
Louisiana
  Annual Rate Filing   TransLa     431  
Mississippi
  Annual Rate Filing   Mississippi      
West Texas
  Environs Rate Case   Amarillo     78  
                 
            $ 36,858  
                 
 
 
(1) The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in the Company’s base rates.
 
(2) Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.


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A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. There were no fiscal 2011 rate cases completed as of December 31, 2010.
 
As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in significant portions of our Mid-Tex and West Texas divisions. These mechanisms are referred to as rate review mechanisms in our Mid-Tex and West Texas divisions, stable rate filings in the Mississippi Division and a rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms for the quarter ended December 31, 2010.
 
                         
              Additional
     
              Annual
     
        Test Year
    Operating
    Effective
Division
  Jurisdiction   Ended     Income     Date
              (In thousands)      
 
2011 Filings:
                       
Mid-Tex
  Settled Cities     12/31/2009     $ 23,122     10/1/2010
                         
Total 2011 Filings
              $ 23,122      
                         
 
The following table summarizes other ratemaking activity during the quarter ended December 31, 2010:
 
                     
            Additional
     
            Annual
     
            Operating
    Effective
Division
  Jurisdiction   Rate Activity   Income     Date
            (In thousands)      
 
2011 Other Rate Activity:
                   
Colorado-Kansas
  Colorado   AMI(1)   $ 349     12/1/2010
Kentucky/Mid-States
  Georgia   PRP Surcharge(2)     764     10/1/2010
                     
Total 2011 Other Rate Activity
          $ 1,113      
                     
 
 
(1) Automated Meter Infrastructure (AMI) relates to a pilot program in the Weld County area of the Company’s service area.
 
(2) The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.
 
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.


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Review of Financial and Operating Results
 
Financial and operational highlights for our regulated transmission and storage segment for the three months ended December 31, 2010 and 2009 are presented below.
 
                         
    Three Months Ended
 
    December 31  
    2010     2009     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 27,535     $ 26,711     $ 824  
Third-party transportation
    16,512       15,242       1,270  
Storage and park and lend services
    2,170       2,605       (435 )
Other
    2,790       2,302       488  
                         
Gross profit
    49,007       46,860       2,147  
Operating expenses
    24,926       25,788       (862 )
                         
Operating income
    24,081       21,072       3,009  
Miscellaneous income (expense)
    (282 )     43       (325 )
Interest charges
    8,064       7,968       96  
                         
Income before income taxes
    15,735       13,147       2,588  
Income tax expense
    5,633       4,693       940  
                         
Net income
  $ 10,102     $ 8,454     $ 1,648  
                         
Gross pipeline transportation volumes — MMcf
    153,178       157,773       (4,595 )
                         
Consolidated pipeline transportation volumes — MMcf
    99,841       95,938       3,903  
                         
 
The $2.1 million increase in regulated transmission and storage gross profit was attributable primarily to the following factors:
 
  •  $3.1 million increase associated with our GRIP filings.
 
  •  $1.6 million increase in fixed fee services.
 
These increases were partially offset by the following:
 
  •  $1.5 million decrease resulting from lower per-unit transportation margins.
 
  •  $1.0 million decrease due to a decline in throughput to our Mid-Tex Division and a reduction in production.
 
Operating expenses decreased $0.9 million primarily due to lower levels of pipeline maintenance activities.
 
Nonregulated Segment
 
Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.
 
AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. In addition, AEH utilizes proprietary and customer-owned transportation and storage assets to provide various delivered gas 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, AEH’s gas delivery and related services margins arise from the types of commercial transactions we have structured with our


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customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.
 
AEH’s storage and transportation margins arise from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods.
 
AEH also seeks to enhance its gross profit margin by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity it owns or controls in our natural gas distribution and by its subsidiaries. We attempt to meet these objectives by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEH has access and selling financial instruments at advantageous prices to lock in a gross profit margin.
 
AEH continually manages its net physical position to attempt to increase the future economic profit that was created when the original transaction was executed. Therefore, AEH 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 AEH elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to hedge the original financial instruments. If AEH elects to defer the withdrawal of gas, it will reset its positions 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 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.
 
AEH also uses financial instruments to capture additional storage arbitrage opportunities that may arise after 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.
 
Due to the nature of these operations, natural gas prices and differences in natural gas prices between the various markets that we serve (commonly referred to as basis differentials), have a significant impact on our nonregulated businesses. Within our delivered gas activities, basis differentials impact our ability to create value from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Further, higher natural gas prices may 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. Higher gas prices, as well as competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.
 
Volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility often has a significant impact on the spreads between the market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. Volatility could also impact the basis differentials we capture in our delivered gas activities. However,


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increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.
 
Review of Financial and Operating Results
 
Financial and operational highlights for our nonregulated segment for the three months ended December 31, 2010 and 2009 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers, margins earned from storage and transportation services 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 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
 
    December 31  
    2010     2009     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Gas delivery and related services
  $ 16,041     $ 16,087     $ (46 )
Storage and transportation services
    3,349       3,334       15  
Other
    1,319       464       855  
                         
      20,709       19,885       824  
Asset optimization
    3,965       6,006       (2,041 )
                         
Total realized margins
    24,674       25,891       (1,217 )
Unrealized margins
    504       43,884       (43,380 )
                         
Gross profit
    25,178       69,775       (44,597 )
Operating expenses
    13,335       12,998       337  
                         
Operating income
    11,843       56,777       (44,934 )
Miscellaneous income
    290       376       (86 )
Interest charges
    1,170       2,407       (1,237 )
                         
Income before income taxes
    10,963       54,746       (43,783 )
Income tax expense
    4,386       21,318       (16,932 )
                         
Net income
  $ 6,577     $ 33,428     $ (26,851 )
                         
Gross nonregulated delivered gas sales volumes — MMcf
    107,712       102,261       5,451  
                         
Consolidated nonregulated delivered gas sales volumes — MMcf
    94,538       87,229       7,309  
                         
Net physical position (Bcf)
    19.6       19.0       0.6  
                         


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Realized margins for gas delivery, storage and transportation services and other services were $20.7 million, or 84 percent of total realized margins during the three months ended December 31, 2010 compared with $19.9 million, or 77 percent of total realized margins for the prior-year quarter. The increase reflects the following:
 
  •  An eight percent increase in consolidated sales volumes.
 
  •  A decrease in gas delivery per-unit margins from $0.16/Mcf in the prior-year quarter to $0.15/Mcf in the current-year quarter.
 
  •  The $0.9 million increase in other margins primarily reflects increased margin on sales of gas held in storage in the current-year quarter compared to the prior-year quarter.
 
The $2.0 million decrease in realized asset optimization margins from the prior-year quarter primarily reflects the impact of continued low natural gas market volatility. In the prior-year quarter, we were able to take advantage of more favorable trading opportunities in the daily cash market. These opportunities were not as readily available in the current quarter. Additionally, we realized lower spread values on the positions that were closed during the quarter compared with the prior-year quarter due to the decline in the physical to forward spread values experienced in the last 12-15 months.
 
The $43.4 million decrease in unrealized margins is due primarily to a significant unrealized gain recognized in the prior-year quarter. The prior-year quarter unrealized gain resulted from narrowing spreads between the then current cash prices and forward natural gas prices experienced on AEH’s net physical position and the deferral of physical storage withdrawals to later in the 2010 fiscal year.
 
Interest charges decreased $1.2 million primarily due to a decrease in intercompany borrowings.
 
Asset Optimization Activities
 
AEH monitors the impact of its asset optimization efforts by estimating the gross profit, before related fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic value, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement and related fees is referred to as the potential gross profit.
 
We define potential gross profit as the change in AEH’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include other operating expenses and associated 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 value or the potential gross profit will be fully realized in the future.
 
We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone. Because there is no assurance that the economic value or potential gross profit will be realized in the future, corresponding future GAAP amounts are not available.
 
The following table presents AEH’s economic value and its potential gross profit (loss) at December 31, 2010 and 2009.
 
                 
    December 31  
    2010     2009  
    (In millions, unless otherwise noted)  
 
Economic value
  $ (2.6 )   $ 25.7  
Associated unrealized (gains) losses
    10.2       (27.2 )
                 
Subtotal
    7.6       (1.5 )
Related fees(1)
    (7.9 )     (13.3 )
                 
Potential gross profit (loss)
  $ (0.3 )   $ (14.8 )
                 
Net physical position (Bcf)
    19.6       19.0  
                 


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(1) Related fees represent the contractual costs to acquire the storage capacity utilized in our nonregulated segment’s asset optimization activities. The fees primarily consist of demand fees and contractual obligations to sell gas below market index prices in exchange for the right to manage and optimize third party storage assets for the positions we have entered into as of December 31, 2010 and 2009.
 
During the quarter ended December 31, 2010, our nonregulated segment’s economic value increased from ($7.5) million, or ($0.48)/Mcf at September 30, 2010 to ($2.6) million, or ($0.13)/Mcf. This compares unfavorably to economic value at December 31, 2009 of $25.7 million, or $1.35/Mcf.
 
During the three months ended December 31, 2010, the increase in our economic value reflected an increase in spread value resulting from (i) entering into financial hedges with higher average prices and (ii) reducing the weighted average cost of gas held in storage by withdrawing higher cost gas and injecting gas into storage at lower prices. We anticipate the majority of the economic value and corresponding reversal of unrealized mark-to-market gains will occur in fiscal 2011.
 
The economic value 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 AEH 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 value or the potential gross profit calculated as of December 31, 2010 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.
 
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.
 
We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require. During fiscal 2011, we anticipate consolidating our short-term facilities used for our regulated operations into a single line of credit. In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that we do not plan to extend or replace upon expiration. In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility.
 
Our five-year $566.7 million facility will expire in December 2011. We expect to begin discussions during fiscal 2011 to replace the expiring five-year $566.7 million facility with a larger multi-year credit facility. We believe our existing five-year facility will provide adequate short-term borrowing capacity until we can successfully execute a new multi-year credit facility.
 
Our $350 million unsecured 7.375% Senior Notes will mature in May 2011. We intend to refinance this debt on a long-term basis through the issuance of 30-year unsecured senior notes in June 2011. Additionally, we plan to issue $250 million of 30-year unsecured senior notes in November 2011 to fund our capital expenditure program. On September 30, 2010, we entered into five Treasury lock agreements to fix the Treasury yield component of the interest cost of financing the anticipated issuances of senior notes. We designated all of the Treasury lock agreements as cash flow hedges of an anticipated transaction. Any realized gain or loss incurred when these agreements are settled will be recognized as a component of interest expense over the life of the related long-term debt.


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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 2011.
 
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, investing and financing activities for the three months ended December 31, 2010 and 2009 are presented below.
 
                         
    Three Months Ended December 31  
    2010     2009     2010 vs. 2009  
          (In thousands)        
 
Total cash provided by (used in)
                       
Operating activities
  $ 45,824     $ 95,156     $ (49,332 )
Investing activities
    (123,532 )     (117,312 )     (6,220 )
Financing activities
    75,648       85,782       (10,134 )
                         
Change in cash and cash equivalents
    (2,060 )     63,626       (65,686 )
Cash and cash equivalents at beginning of period
    131,952       111,203       20,749  
                         
Cash and cash equivalents at end of period
  $ 129,892     $ 174,829     $ (44,937 )
                         
 
Cash flows from operating activities
 
Period-over-period changes in our operating cash flows are primarily 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.
 
The $49.3 million decrease in operating cash flows primarily reflects the timing of customer collections and vendor payments.
 
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, rate designs in our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
 
Capital expenditures for fiscal 2011 are expected to range from $580 million to $595 million. For the three months ended December 31, 2010, capital expenditures were $123.2 million compared with $115.4 million for the three months ended December 31, 2009. The $7.8 million increase in capital expenditures primarily reflects spending for the steel service line replacement program in the Mid-Tex Division and the purchase of software for new customer service systems in the current quarter partially offset by the relocation of the company’s information technology data center in the prior-year quarter.


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Cash flows from financing activities
 
The $10.1 million decrease in financing cash flows was primarily due to the following:
 
  •  $10.0 million additional cash used to repay long-term debt that matured in December 2010, partially offset by
 
  •  $1.3 million additional cash provided from short-term debt borrowings.
 
The following table summarizes our share issuances for the three months ended December 31, 2010 and 2009.
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
 
Shares issued:
               
Direct Stock Purchase Plan
          79,087  
Retirement Savings Plan and Trust
          79,722  
1998 Long-Term Incentive Plan
    595,103       259,550  
Outside Directors Stock-for-Fee Plan
    638       770  
                 
Total shares issued
    595,741       419,129  
                 
 
The quarter-over-quarter change in the number of shares issued primarily reflects the fact that we are using shares purchased in the open market rather than issuing shares for the Direct Stock Purchase Plan and the Retirement Savings Plan. During the current quarter, we repurchased 121,353 shares attributable to equity awards which are not included in the table above.
 
Share Repurchase Agreement
 
On, July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman Sachs & Co. under which we repurchased $100 million of our outstanding common stock in order to offset stock grants made under our various employee and director incentive compensation plans.
 
We paid $100 million to Goldman Sachs & Co. on July 7, 2010 for shares of Atmos Energy common stock in a share forward transaction and received 2,958,580 shares. The specific number of shares we will ultimately repurchase in the transaction will be based generally on the average of the daily volume-weighted average share price of our common stock over the duration of the agreement. The agreement is scheduled to end in the second fiscal quarter of 2011. As a result of this transaction, beginning in our fourth fiscal quarter of 2010, the number of outstanding shares used to calculate our earnings per share was reduced by the number of shares received and the $100 million purchase price was recorded as a reduction in shareholders’ equity. The number of shares used to calculate our earnings per share in fiscal 2011 will continue to be reduced by the shares we received in July 2010; however, the total impact to diluted earnings per share for fiscal 2011 will be dependent upon the average share price of our common stock over the remainder of the agreement.
 
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.
 
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 $1.0 billion of working capital funding. As of December 31, 2010, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $656 million. These facilities are described in further detail in Note 5 to the unaudited condensed consolidated financial statements.


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In October 2010, our $200 million 364-day facility expired. We replaced the $200 million 364-day facility before its expiration with a $200 million 180-day credit facility that will expire in April 2011.
 
On December 8, 2010, the Company replaced AEM’s existing $450 million 364-day committed revolving credit facility with a $200 million three-year facility with an accordion feature that could increase the Company’s borrowing capacity to $500 million on substantially the same terms, except for a slight reduction in the rate of interest charged for both base rate and offshore borrowings and an extension of the facility for an additional three-year period. As a result of consolidating and reducing the amounts available under our facilities, we expect to reduce our short-term financing costs.
 
Shelf Registration
 
We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we will be able to issue a total of $950 million in debt securities and $350 million in equity securities. At December 31, 2010, no amounts have been drawn down on the shelf registration statement.
 
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). As of December 31, 2010, S&P maintained a stable outlook, while Moody’s and Fitch maintained their ratings outlooks as positive. Our current debt ratings are all considered investment grade and are as follows:
 
                         
    S&P   Moody’s   Fitch
 
Unsecured senior long-term debt
    BBB+       Baa2       BBB+  
Commercial paper
    A-2       P-2       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 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 independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
 
Debt Covenants
 
We were in compliance with all of our debt covenants as of December 31, 2010. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.


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Capitalization
 
The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of December 31, 2010, September 30, 2010 and December 31, 2009:
 
                                                 
    December 31, 2010     September 30, 2010     December 31, 2009  
    (In thousands, except percentages)  
 
Short-term debt
  $ 247,993       5.3 %   $ 126,100       2.8 %   $ 179,712       3.9 %
Long-term debt
    2,159,753       46.1 %     2,169,682       48.5 %     2,169,601       47.1 %
Shareholders’ equity
    2,274,853       48.6 %     2,178,348       48.7 %     2,258,076       49.0 %
                                                 
Total
  $ 4,682,599       100.0 %   $ 4,474,130       100.0 %   $ 4,607,389       100.0 %
                                                 
 
Total debt as a percentage of total capitalization, including short-term debt, was 51.4 percent at December 31, 2010, 51.3 percent at September 30, 2010 and 51.0 percent at December 31, 2009. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.
 
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 three months ended December 31, 2010.
 
As we previously discussed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, in February 2008, Atmos Pipeline and Storage, LLC, a subsidiary of AEH, announced plans to construct and operate a salt-cavern storage project in Franklin Parish, Louisiana. In March 2010, we entered into an option and acquisition agreement with a third party, which provided the third party with the exclusive option to develop the proposed Fort Necessity salt-dome natural gas storage project. In July 2010, we signed an extension to the option and acquisition agreement which gave the third party until March 2011 to exercise the option to develop the project. In January 2011, the third party developer notified us that it did not plan to commence the activities required to allow it to exercise the option by March 2011, accordingly, the option was terminated. We are currently evaluating our strategic alternatives with respect to this project.
 
Risk Management Activities
 
We conduct risk management activities through our natural gas distribution and nonregulated 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 nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial 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 months ended December 31, 2010 and 2009:
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (49,600 )   $ (14,166 )
Contracts realized/settled
    (32,981 )     (21,029 )
Fair value of new contracts
    531       (947 )
Other changes in value
    108,856       18,672  
                 
Fair value of contracts at end of period
  $ 26,806     $ (17,470 )
                 
 
The fair value of our natural gas distribution segment’s financial instruments at December 31, 2010 is presented below by time period and fair value source:
 
                                         
    Fair Value of Contracts at December 31, 2010  
    Maturity in Years        
    Less
                Greater
    Total Fair
 
Source of Fair Value
  Than 1     1-3     4-5     Than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ 27,709     $ (903 )   $     $     $ 26,806  
Prices based on models and other valuation methods
                             
                                         
Total Fair Value
  $ 27,709     $ (903 )   $     $     $ 26,806  
                                         
 
The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three months ended December 31, 2010 and 2009:
 
                 
    Three Months Ended
 
    December 31  
    2010     2009  
    (In thousands)  
 
Fair value of contracts at beginning of period
  $ (12,374 )   $ 26,698  
Contracts realized/settled
    934       (2,212 )
Fair value of new contracts
           
Other changes in value
    759       7,820  
                 
Fair value of contracts at end of period
    (10,681 )     32,306  
Netting of cash collateral
    25,296       (1,315 )
                 
Cash collateral and fair value of contracts at period end
  $ 14,615     $ 30,991  
                 
 
The fair value of our nonregulated segment’s financial instruments at December 31, 2010 is presented below by time period and fair value source:
 
                                         
    Fair Value of Contracts at December 31, 2010  
    Maturity in Years        
    Less
                Greater
    Total Fair
 
Source of Fair Value
  Than 1     1-3     4-5     Than 5     Value  
    (In thousands)  
 
Prices actively quoted
  $ (4,199 )   $ (6,467 )   $ (15 )   $     $ (10,681 )
Prices based on models and other valuation methods
                             
                                         
Total Fair Value
  $ (4,199 )   $ (6,467 )   $ (15 )   $     $ (10,681 )
                                         


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Pension and Postretirement Benefits Obligations
 
For the three months ended December 31, 2010 and 2009, our total net periodic pension and other benefits cost was $14.9 million and $12.7 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.
 
Our fiscal 2011 costs were determined using a September 30, 2010 measurement date. As of September 30, 2010, interest and corporate bond rates utilized to determine our discount rates, were significantly higher than the interest and corporate bond rates as of September 30, 2009, the measurement date for our fiscal 2010 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2011 pension and benefit costs to 5.39 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. Accordingly, our fiscal 2011 pension and postretirement medical costs for the quarter ended December 31, 2010 were significantly higher than the prior-year quarter.
 
In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Pension Account Plan (PAP) to new participants, effective October 1, 2010. Employees participating in the PAP as of October 1, 2010 were allowed to make a one-time election to migrate from the PAP into our defined contribution plan with enhanced features, effective January 1, 2011. Participants who chose to remain in the PAP will continue to earn benefits and interest allocations with no changes to their existing benefits. During the first quarter ended December 31, 2010, a limited number of participants elected to join the new plan, which resulted in an immaterial curtailment gain and a revaluation of the net periodic pension cost for the remainder of fiscal 2011. The curtailment gain will be recorded in our second fiscal quarter. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective January 1, 2011 to 5.68 percent, which will reduce our net periodic pension cost by approximately $1.8 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.
 
In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2011. Based upon this valuation, we expect we will be required to contribute less than $2 million to our pension plans by September 15, 2011. The need for this funding reflects the decline in the fair value of the plans’ assets resulting from the unfavorable market conditions experienced during 2008 and 2009. 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 $11 million to these plans during fiscal 2011.
 
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 will be determined by actual investment returns, changes in interest rates, values of assets in the plan and changes in the demographic composition of the participants in the plan.
 
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 fiscal year ended September 30, 2010. During the three months ended December 31, 2010, there were no material changes in our quantitative and qualitative disclosures about market risk.


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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 December 31, 2010 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 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 first quarter of the fiscal year ended September 30, 2011 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 three months ended December 31, 2010, 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, 2010. 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 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 Treasurer
(Duly authorized signatory)
 
Date: February 9, 2011


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EXHIBITS INDEX
Item 6
 
             
        Page Number or
Exhibit
      Incorporation by
Number
 
Description
 
Reference to
 
  10 .1   Revolving Credit Agreement (180 Day Facility), dated as of October 15, 2010, among Atmos Energy Corporation, the Lenders from time to time parties thereto, SunTrust Bank as Administrative Agent, Wells Fargo Bank, N.A. as Syndication Agent, and Bank of America, N.A. and U.S. Bank National Association as Co-Documentation Agents   Exhibit 10.1 to Form 8-K dated October 15, 2010 (File No. 1-10042)
  10 .2   Fifth Amended and Restated Credit Agreement, dated as of December 8, 2010 among Atmos Energy Marketing, LLC, a Delaware limited liability company, BNP Paribas, a bank organized under the laws of France, as administrative agent, collateral agent, as an issuing bank, a swing line bank and a bank; Société Générale as co-syndication agent, an issuing bank and a bank and the Royal Bank of Scotland, plc, as co-syndication agent and a bank; and Natixis, New York Branch, Credit Agricole Corporate and Investment Bank, and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A. as co-documentation agents and the other financial institutions that become parties thereto   Exhibit 10.1 to Form 8-K dated December 8, 2010 (File No. 1-10042)
  10 .3   Third Amended and Restated Intercreditor Agreement, dated as of December 8, 2010 (as amended, supplemented and otherwise modified from time to time, the “Agreement”), among BNP Paribas, a bank organized under the laws of France, in its capacity as Collateral Agent (together with its successors and assigns in such capacity, the “Agent”) for the Banks thereinafter referred to, and each bank and other financial institution which is now or hereafter a party to the Agreement in its capacity as a Bank and, as applicable, as a Swap Bank (collectively, the “Swap Banks”) and/or a Physical Trade Bank (collectively, the “Physical Trade Banks”)   Exhibit 10.2 to Form 8-K dated December 8, 2010 (File No. 1-10042)
  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*    
  101 .INS   XBRL Instance Document**    
  101 .SCH   XBRL Taxonomy Extension Schema**    
  101 .CAL   XBRL Taxonomy Extension Calculation Linkbase**    
  101 .LAB   XBRL Taxonomy Extension Labels Linkbase**    
  101 .PRE   XBRL Taxonomy Extension Presentation Linkbase**    
 
 
* 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.
 
** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.


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