10-Q 1 d81287e10vq.htm FORM 10-Q e10vq
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q
 
 
     
(Mark One)    
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended March 31, 2011
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 website, 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 April 29, 2011.
 
     
Class
 
Shares Outstanding
 
No Par Value
  90,329,899
 


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 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
Bcf
  Billion cubic feet
Fitch
  Fitch Ratings, Ltd.
GRIP
  Gas Reliability Infrastructure Program
ISRS
  Infrastructure System Replacement Surcharge
Mcf
  Thousand cubic feet
MMcf
  Million cubic feet
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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Table of Contents

 
PART I. FINANCIAL INFORMATION
 
Item 1.   Financial Statements
 
ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    March 31,
    September 30,
 
    2011     2010  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 6,693,971     $ 6,542,318  
Less accumulated depreciation and amortization
    1,779,321       1,749,243  
                 
Net property, plant and equipment
    4,914,650       4,793,075  
Current assets
               
Cash and cash equivalents
    153,246       131,952  
Accounts receivable, net
    458,813       273,207  
Gas stored underground
    228,051       319,038  
Other current assets
    143,978       150,995  
                 
Total current assets
    984,088       875,192  
Goodwill and intangible assets
    739,834       740,148  
Deferred charges and other assets
    357,252       355,376  
                 
    $ 6,995,824     $ 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:
               
March 31, 2011 — 90,329,237 shares;
               
September 30, 2010 — 90,164,103 shares
  $ 452     $ 451  
Additional paid-in capital
    1,728,474       1,714,364  
Retained earnings
    631,044       486,905  
Accumulated other comprehensive income (loss)
    14,009       (23,372 )
                 
Shareholders’ equity
    2,373,979       2,178,348  
Long-term debt
    1,807,323       1,809,551  
                 
Total capitalization
    4,181,302       3,987,899  
Current liabilities
               
Accounts payable and accrued liabilities
    423,726       266,208  
Other current liabilities
    301,824       413,640  
Short-term debt
          126,100  
Current maturities of long-term debt
    352,434       360,131  
                 
Total current liabilities
    1,077,984       1,166,079  
Deferred income taxes
    944,605       829,128  
Regulatory cost of removal obligation
    364,709       350,521  
Deferred credits and other liabilities
    427,224       430,164  
                 
    $ 6,995,824     $ 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
 
    March 31  
    2011     2010  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 1,113,204     $ 1,365,988  
Regulated transmission and storage segment
    54,976       55,181  
Nonregulated segment
    583,531       677,032  
Intersegment eliminations
    (134,424 )     (157,935 )
                 
      1,617,287       1,940,266  
Purchased gas cost
               
Natural gas distribution segment
    723,046       980,603  
Regulated transmission and storage segment
           
Nonregulated segment
    563,473       662,871  
Intersegment eliminations
    (134,054 )     (157,529 )
                 
      1,152,465       1,485,945  
                 
Gross profit
    464,822       454,321  
Operating expenses
               
Operation and maintenance
    116,379       117,088  
Depreciation and amortization
    57,136       53,080  
Taxes, other than income
    54,103       59,613  
Asset impairment
    19,282        
                 
Total operating expenses
    246,900       229,781  
                 
Operating income
    217,922       224,540  
Miscellaneous income
    26,187       49  
Interest charges
    37,892       39,582  
                 
Income before income taxes
    206,217       185,007  
Income tax expense
    74,008       70,881  
                 
Net income
  $ 132,209     $ 114,126  
                 
Basic net income per share
  $ 1.45     $ 1.22  
                 
Diluted net income per share
  $ 1.45     $ 1.22  
                 
Cash dividends per share
  $ 0.340     $ 0.335  
                 
Weighted average shares outstanding:
               
Basic
    90,246       92,518  
                 
Diluted
    90,533       92,853  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Six Months Ended
 
    March 31  
    2011     2010  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 1,840,399     $ 2,168,882  
Regulated transmission and storage segment
    103,983       102,041  
Nonregulated segment
    1,059,171       1,225,048  
Intersegment eliminations
    (229,271 )     (262,853 )
                 
      2,774,282       3,233,118  
Purchased gas cost
               
Natural gas distribution segment
    1,150,469       1,488,870  
Regulated transmission and storage segment
           
Nonregulated segment
    1,013,935       1,141,112  
Intersegment eliminations
    (228,504 )     (262,034 )
                 
      1,935,900       2,367,948  
                 
Gross profit
    838,382       865,170  
Operating expenses
               
Operation and maintenance
    232,973       240,950  
Depreciation and amortization
    113,297       106,919  
Taxes, other than income
    94,799       102,165  
Asset impairment
    19,282        
                 
Total operating expenses
    460,351       450,034  
                 
Operating income
    378,031       415,136  
Miscellaneous income (expense)
    25,450       (220 )
Interest charges
    76,809       78,290  
                 
Income before income taxes
    326,672       336,626  
Income tax expense
    120,466       129,170  
                 
Net income
  $ 206,206     $ 207,456  
                 
Basic net income per share
  $ 2.26     $ 2.22  
                 
Diluted net income per share
  $ 2.26     $ 2.22  
                 
Cash dividends per share
  $ 0.680     $ 0.670  
                 
Weighted average shares outstanding:
               
Basic
    90,157       92,336  
                 
Diluted
    90,455       92,681  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Six Months Ended
 
    March 31  
    2011     2010  
    (Unaudited)
 
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 206,206     $ 207,456  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Asset impairment
    19,282        
Depreciation and amortization:
               
Charged to depreciation and amortization
    113,297       106,919  
Charged to other accounts
    98       96  
Deferred income taxes
    115,302       44,097  
Other
    10,255       11,759  
Net assets/liabilities from risk management activities
    (17,478 )     1,234  
Net change in operating assets and liabilities
    (8,491 )     111,897  
                 
Net cash provided by operating activities
    438,471       483,458  
Cash Flows From Investing Activities
               
Capital expenditures
    (246,663 )     (232,629 )
Other, net
    (1,535 )     (946 )
                 
Net cash used in investing activities
    (248,198 )     (233,575 )
Cash Flows From Financing Activities
               
Net decrease in short-term debt
    (128,884 )     (75,907 )
Unwinding of Treasury lock agreements
    27,803        
Repayment of long-term debt
    (10,066 )     (66 )
Cash dividends paid
    (62,067 )     (62,550 )
Repurchase of equity awards
    (3,333 )      
Issuance of common stock
    7,568       8,590  
                 
Net cash used in financing activities
    (168,979 )     (129,933 )
                 
Net increase in cash and cash equivalents
    21,294       119,950  
Cash and cash equivalents at beginning of period
    131,952       111,203  
                 
Cash and cash equivalents at end of period
  $ 153,246     $ 231,153  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 2011
 
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 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 six-month period ended March 31, 2011 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 March 31, 2011 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as discussed in


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 5, 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 financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010.
 
During the second quarter of fiscal 2011, we recognized a $5.0 million one-time tax benefit related to the administrative settlement of various income tax positions.
 
Additionally, during the second quarter of fiscal 2011, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
 
During the six months ended March 31, 2011, 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 six months ended March 31, 2011.
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Significant regulatory assets and liabilities as of March 31, 2011 and September 30, 2010 included the following:
 
                 
    March 31,
    September 30,
 
    2011     2010  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 203,136     $ 209,564  
Merger and integration costs, net
    6,478       6,714  
Deferred gas costs
    34,211       22,701  
Regulatory cost of removal asset
    38,973       31,014  
Environmental costs
    509       805  
Rate case costs
    5,648       4,505  
Deferred franchise fees
    415       1,161  
Other
    5,101       1,046  
                 
    $ 294,471     $ 277,510  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 6,419     $ 43,333  
Deferred franchise fees
    5,443        
Regulatory cost of removal obligation
    396,388       381,474  
Other
    5,912       6,112  
                 
    $ 414,162     $ 430,919  
                 
 
Currently, our authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from various state regulatory commissions.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Comprehensive income
 
The following table presents the components of comprehensive income, net of related tax, for the three-month and six-month periods ended March 31, 2011 and 2010:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2011     2010     2011     2010  
    (In thousands)  
 
Net income
  $ 132,209     $ 114,126     $ 206,206     $ 207,456  
Unrealized holding gains on investments, net of tax expense of $477 and $408 for the three months ended March 31, 2011 and 2010 and of $932 and $798 for the six months ended March 31, 2011 and 2010
    810       695       1,586       1,359  
Amortization, unrealized gain and unwinding of interest rate hedging transactions, net of tax expense (benefit) of $(6,125) and $248 for the three months ended March 31, 2011 and 2010 and $12,579 and $496 for the six months ended March 31, 2011 and 2010
    (10,427 )     421       21,420       843  
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $2,573 and $(6,321) for the three months ended March 31, 2011 and 2010 and $9,190 and $(2,067) for the six months ended March 31, 2011 and 2010
    4,025       (9,885 )     14,375       (3,231 )
                                 
Comprehensive income
  $ 126,617     $ 105,357     $ 243,587     $ 206,427  
                                 
 
Accumulated other comprehensive income (loss), net of tax, as of March 31, 2011 and September 30, 2010 consisted of the following unrealized gains (losses):
 
                 
    March 31,
    September 30,
 
    2011     2010  
    (In thousands)  
 
Accumulated other comprehensive income (loss):
               
Unrealized holding gains on investments
  $ 5,791     $ 4,205  
Treasury lock agreements
    15,952       (5,468 )
Cash flow hedges
    (7,734 )     (22,109 )
                 
    $ 14,009     $ (23,372 )
                 
 
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 second 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 accelerated payments 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 hedged approximately 35 percent, or 31.7 Bcf of the planned 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 cost 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 59 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 March 31, 2011, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.4 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 $300 million 30-year unsecured senior notes in June 2011. In September 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuances of these senior notes which were designated as cash flow hedges of an anticipated transaction.
 
Additionally, our original fiscal 2011 financing plans included the issuance of $250 million of 30-year unsecured notes in November 2011 to fund our capital expenditure program. In September 2010, we entered into two Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuance of these senior notes, which were designated as cash flow hedges of an anticipated transaction. Due to stronger than anticipated cash flows primarily resulting from the extension of the Bush tax cuts that allow the continued use of bonus depreciation on qualifying expenditures through December 31, 2011, the need to issue $250 million of debt in November has been eliminated and the related Treasury lock agreements were unwound in March 2011. As a result of unwinding these Treasury locks, we recognized a pretax cash gain of $27.8 million during the second quarter.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
Quantitative Disclosures Related to Financial Instruments
 
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
 
As of March 31, 2011, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2011, 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           (20,483 )        
    Cash Flow           27,276          
    Not designated     6,973       26,672          
                             
          6,973       33,465          
                             
 
Financial Instruments on the Balance Sheet
 
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of March 31, 2011 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 $17.1 million and $24.9 million of cash held on deposit in margin accounts as of March 31, 2011 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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
    Regulated
             
        Gas
    Transmission
             
    Balance Sheet Location   Distribution     and Storage     Nonregulated     Total  
        (In thousands)  
 
March 31, 2011
                                   
Designated As Hedges:
                                   
Asset Financial Instruments
                                   
Current commodity and
                                   
interest rate contracts
  Other current assets   $ 33,207     $      —     $ 12,807     $ 46,014  
Noncurrent commodity contracts
  Deferred charges and other assets                 574       574  
                                     
Liability Financial Instruments
                                   
Current commodity contracts
  Other current liabilities                 (21,303 )     (21,303 )
Noncurrent commodity contracts
  Deferred credits and other liabilities                 (5,857 )     (5,857 )
                                     
Total
        33,207             (13,779 )     19,428  
                                     
Not Designated As Hedges:
                                   
Asset Financial Instruments
                                   
Current commodity contracts
  Other current assets     716             10,035       10,751  
Noncurrent commodity contracts
  Deferred charges and other assets                 2,761       2,761  
                                     
Liability Financial Instruments
                                   
Current commodity contracts
  Other current liabilities     (3,390 )           (10,660 )     (14,050 )
Noncurrent commodity contracts
  Deferred credits and other liabilities                 (1,299 )     (1,299 )
                                     
Total
        (2,674 )           837       (1,837 )
                                     
Total Financial Instruments
      $ 30,533     $   —     $ (12,942 )   $ 17,591  
                                     
 
                                     
        Natural
    Regulated
             
        Gas
    Transmission
             
    Balance Sheet Location   Distribution     and Storage     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
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended March 31, 2011 and 2010 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $4.1 million and $(4.9) million. For the six months ended March 31, 2011 and 2010 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $17.5 million and $40.4 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 and six months ended March 31, 2011 and 2010 is presented below.
 
                 
    Three Months Ended
 
    March 31  
    2011     2010  
    (In thousands)  
 
Commodity contracts
  $ (1,279 )   $ 33,461  
Fair value adjustment for natural gas inventory designated as the hedged item
    5,586       (37,666 )
                 
Total impact on revenue
  $ 4,307     $ (4,205 )
                 
The impact on revenue is comprised of the following:
               
Basis ineffectiveness
  $ (509 )   $ (512 )
Timing ineffectiveness
    4,816       (3,693 )
                 
    $ 4,307     $ (4,205 )
                 
 
                 
    Six Months Ended
 
    March 31  
    2011     2010  
    (In thousands)  
 
Commodity contracts
  $ (3,003 )   $ 30,821  
Fair value adjustment for natural gas inventory designated as the hedged item
    21,211       11,517  
                 
Total impact on revenue
  $ 18,208     $ 42,338  
                 
The impact on revenue is comprised of the following:
               
Basis ineffectiveness
  $ 412     $ (449 )
Timing ineffectiveness
    17,796       42,787  
                 
    $ 18,208     $ 42,338  
                 
 
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot to forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on revenue.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Cash Flow Hedges
 
The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2011 and 2010 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
                                 
    Three Months Ended March 31, 2011  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     $ (7,328 )   $ (7,328 )
Loss arising from ineffective portion of commodity contracts
                (233 )     (233 )
                                 
Total impact on revenue
                (7,561 )     (7,561 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (669 )                 (669 )
Gain on unwinding of Treasury lock reclassified from AOCI into miscellaneous income
    21,803       6,000             27,803  
                                 
Total Impact from Cash Flow Hedges
  $ 21,134     $ 6,000     $ (7,561 )   $ 19,573  
                                 
 
                                 
    Three Months Ended March 31, 2010  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     —     $ (8,556 )   $ (8,556 )
Loss arising from ineffective portion of commodity contracts
                (739 )     (739 )
                                 
Total impact on revenue
                (9,295 )     (9,295 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (669 )                 (669 )
                                 
Total Impact from Cash Flow Hedges
  $ (669 )   $   —     $ (9,295 )   $ (9,964 )
                                 
                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Six Months Ended March 31, 2011  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     $ (21,581 )   $ (21,581 )
Loss arising from ineffective portion of commodity contracts
                (677 )     (677 )
                                 
Total impact on revenue
                (22,258 )     (22,258 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,339 )                 (1,339 )
Gain on unwinding of Treasury lock reclassified from AOCI into miscellaneous income
    21,803       6,000             27,803  
                                 
Total Impact from Cash Flow Hedges
  $ 20,464     $ 6,000     $ (22,258 )   $ 4,206  
                                 
 
                                 
    Six Months Ended March 31, 2010  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     —     $ (31,673 )   $ (31,673 )
Loss arising from ineffective portion of commodity contracts
                (1,957 )     (1,957 )
                                 
Total impact on revenue
                (33,630 )     (33,630 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,339 )                 (1,339 )
                                 
Total Impact from Cash Flow Hedges
  $ (1,339 )   $   —     $ (33,630 )   $ (34,969 )
                                 

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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 and six months ended March 31, 2011 and 2010. 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
    Six Months Ended
 
    March 31     March 31  
    2011     2010     2011     2010  
    (In thousands)  
 
Increase (decrease) in fair value:
                               
Treasury lock agreements
  $ 6,667     $     $ 38,092     $  
Forward commodity contracts
    (446 )     (15,104 )     1,211       (22,551 )
Recognition of (gains) losses in earnings due to settlements:
                               
Treasury lock agreements
    (17,094 )     421       (16,672 )     843  
Forward commodity contracts
    4,471       5,219       13,164       19,320  
                                 
Total other comprehensive income (loss) from hedging, net of tax(1)
  $ (6,402 )   $ (9,464 )   $ 35,795     $ (2,388 )
                                 
 
 
(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 March 31, 2011. However, the table below does not include the expected recognition in earnings of three Treasury lock agreements entered into on September 30, 2010 related to the anticipated issuance of long-term debt in June 2011 as those instruments have not yet settled.
 
                         
    Treasury
             
    Lock
    Commodity
       
    Agreements     Contracts     Total  
    (In thousands)  
 
Next twelve months
  $ (1,687 )   $ (4,588 )   $ (6,275 )
Thereafter
    (3,281 )     (3,146 )     (6,427 )
                         
Total(1)
  $ (4,968 )   $ (7,734 )   $ (12,702 )
                         
 
 
(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 March 31, 2011 and 2010 was an increase (decrease) in revenue of $4.0 million and $(3.0) million. For the six months ended March 31, 2011 and 2010 revenue increased $8.2 million and $12.3 million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 from this presentation.
 
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 three and six months ended March 31, 2011, there were no changes in these methods.
 
Fair value measurements also apply to the valuation of our pension and postretirement 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 tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2011 and


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
September 30, 2010. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
                                         
    Quoted
    Significant
    Significant
             
    Prices in
    Other
    Other
             
    Active
    Observable
    Unobservable
    Netting and
       
    Markets
    Inputs
    Inputs
    Cash
    March 31,
 
    (Level 1)     (Level 2)(1)     (Level 3)     Collateral(2)     2011  
    (In thousands)  
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 33,923     $      —     $     $ 33,923  
Nonregulated segment
    4,375       21,802             (15,023 )     11,154  
                                         
Total financial instruments
    4,375       55,725             (15,023 )     45,077  
Hedged portion of gas stored underground
    84,629                         84,629  
Available-for-sale securities
    43,453                         43,453  
                                         
Total assets
  $ 132,457     $ 55,725     $     $ (15,023 )   $ 173,159  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 3,390     $     $     $ 3,390  
Nonregulated segment
    15,668       23,451             (32,076 )     7,043  
                                         
Total liabilities
  $ 15,668     $ 26,841     $   —     $ (32,076 )   $ 10,433  
                                         
 
                                         
    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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 March 31, 2011, we had $17.1 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $9.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $7.5 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.
 
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 March 31, 2011:
 
         
    March 31,
    2011
    (In thousands)
 
Carrying Amount
  $ 2,162,630  
Fair Value
  $ 2,370,532  


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
5.   Debt
 
Long-term debt
 
Long-term debt at March 31, 2011 and September 30, 2010 consisted of the following:
 
                 
    March 31,
    September 30,
 
    2011     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
    327       393  
                 
Total long-term debt
    2,162,630       2,172,696  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (2,873 )     (3,014 )
Current maturities
    (352,434 )     (360,131 )
                 
    $ 1,807,323     $ 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.
 
As of March 31, 2011, we financed 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 provided approximately $1.0 billion of working capital funding. On April 13, 2011, our $200 million 180-day unsecured credit facility expired and was not replaced. On May 2, 2011, we replaced our $566.7 million unsecured credit facility with a new five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion. As a result of these changes, we have $975 million of working capital funding from our commercial paper program and three committed revolving credit facilities with third-party lenders.
 
At March 31, 2011, there were no short-term debt borrowings outstanding. At September 30, 2010, there was a total of $126.1 million outstanding under our commercial paper program. We also use intercompany


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.
 
Regulated Operations
 
Through March 31, 2011 we funded our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provided approximately $800 million of working capital funding. The first facility was a five-year $566.7 million unsecured facility that was replaced on May 2, 2011 with a new five-year $750 million unsecured credit facility. The former facility bore 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. At March 31, 2011, there were no borrowings under this facility nor was there any commercial paper outstanding. The new credit facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 2 percent, based on the Company’s credit ratings. This new credit facility also serves as a backup liquidity facility for our commercial paper program.
 
The second facility was a $200 million unsecured 180-day facility that expired in April 2011 and was not replaced. The facility bore 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 March 31, 2011, 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. This facility was renewed effective April 1, 2011. At March 31, 2011, 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 March 31, 2011, our total-debt-to-total-capitalization ratio, as defined, was 50 percent. In addition, both the interest margin over the Eurodollar rate and the fees 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 $350 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 180-day 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. There was $163.9 million outstanding under this facility at March 31, 2011.
 
Nonregulated Operations
 
Atmos Energy Marketing, LLC (AEM), a wholly-owned subsidiary of AEH has a three-year $200 million committed revolving credit facility with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility is primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs.
 
At AEM’s option, borrowings made under the credit facility are based on a base rate or an offshore rate, in each case plus an applicable margin. The base rate is a floating rate equal to the higher of: (a) 0.50 percent per annum above the latest Federal Funds rate; (b) the per annum rate of interest established by BNP Paribas


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 March 31, 2011, there were no borrowings outstanding under this credit facility. However, at March 31, 2011, AEM letters of credit totaling $35.6 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 $114.4 million at March 31, 2011.
 
AEM is required by the financial covenants in this facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At March 31, 2011, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.4 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 March 31, 2011, AEM’s net working capital was $137.9 million and its tangible net worth was $150.6 million.
 
To supplement borrowings under this facility, AEH has a $350 million intercompany demand credit facility with AEC, which bears interest at a rate equal to the 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. Applicable state regulatory commissions have approved our use of this facility through December 31, 2011. There were no borrowings outstanding under this facility at March 31, 2011.
 
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 March 31, 2011, no securities have been issued under 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 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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 March 31, 2011. 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 and six months ended March 31, 2011 and 2010 are calculated as follows:
 
                                 
    Three Months Ended
    Six Months Ended
 
    March 31     March 31  
    2011     2010     2011     2010  
    (In thousands, except per share amounts)  
 
Basic Earnings Per Share
                               
Net income
  $ 132,209     $ 114,126     $ 206,206     $ 207,456  
Less: Income allocated to participating securities
    1,384       1,142       2,162       2,088  
                                 
Net income available to common shareholders
  $ 130,825     $ 112,984     $ 204,044     $ 205,368  
                                 
Basic weighted average shares outstanding
    90,246       92,518       90,157       92,336  
                                 
Net income per share — Basic
  $ 1.45     $ 1.22     $ 2.26     $ 2.22  
                                 
Diluted Earnings Per Share
                               
Net income available to common shareholders
  $ 130,825     $ 112,984     $ 204,044     $ 205,368  
Effect of dilutive stock options and other shares
    3       3       5       5  
                                 
Net income available to common shareholders
  $ 130,828     $ 112,987     $ 204,049     $ 205,373  
                                 
Basic weighted average shares outstanding
    90,246       92,518       90,157       92,336  
Additional dilutive stock options and other shares
    287       335       298       345  
                                 
Diluted weighted average shares outstanding
    90,533       92,853       90,455       92,681  
                                 
Net income per share — Diluted
  $ 1.45     $ 1.22     $ 2.26     $ 2.22  
                                 
 
There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2010 and 2011 as their exercise price was less than the average market price of the common stock during that period.
 
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.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 and retired 2,958,580 shares. On March 4, 2011, we received and retired an additional 375,468 common shares which concluded our share repurchase agreement. In total, we received and retired 3,334,048 common shares under the repurchase agreement. The final number of shares we ultimately repurchased in the transaction was based generally on the average of the daily volume-weighted average share price of our common stock over the duration of the agreement. 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.
 
7.   Interim Pension and Other Postretirement Benefit Plan Information
 
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and six months ended March 31, 2011 and 2010 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 election period, a limited number of participants chose 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 was 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 March 31  
    Pension Benefits     Other Benefits  
    2011     2010     2011     2010  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 4,257     $ 3,994     $ 3,601     $ 3,359  
Interest cost
    7,055       6,523       3,203       3,017  
Expected return on assets
    (6,285 )     (6,320 )     (682 )     (615 )
Amortization of transition asset
                378       378  
Amortization of prior service cost
    (105 )     (194 )     (363 )     (375 )
Amortization of actuarial loss
    2,748       2,823       86       94  
Curtailment gain
    (40 )                  
                                 
Net periodic pension cost
  $ 7,630     $ 6,826     $ 6,223     $ 5,858  
                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Six Months Ended March 31  
    Pension Benefits     Other Benefits  
    2011     2010     2011     2010  
    (In thousands)  
 
Components of net periodic pension cost:
                               
Service cost
  $ 8,637     $ 7,987     $ 7,202     $ 6,719  
Interest cost
    13,979       13,047       6,406       6,035  
Expected return on assets
    (12,248 )     (12,640 )     (1,364 )     (1,230 )
Amortization of transition asset
                756       756  
Amortization of prior service cost
    (217 )     (387 )     (725 )     (750 )
Amortization of actuarial loss
    6,242       5,645       173       187  
Curtailment gain
    (40 )                  
                                 
Net periodic pension cost
  $ 16,353     $ 13,652     $ 12,448     $ 11,717  
                                 
 
The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2011 and 2010 are as follows:
 
                                                 
    Pension
  Other
   
    Account Plan   Pension Benefits   Other Benefits
    2011   2010   2011   2010   2011   2010
 
Discount rate
    5.68 %     5.52 %     5.39 %     5.52 %     5.39 %     5.52 %
Rate of compensation increase
    4.00 %     4.00 %     4.00 %     4.00 %     4.00 %     4.00 %
Expected return on plan assets
    8.25 %     8.25 %     8.25 %     8.25 %     5.00 %     5.00 %
 
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 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 $5.6 million to our other post-retirement benefit plans during the six months ended March 31, 2011. 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.

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 March 31, 2011:
                               
Domestic equity mutual funds
  $ 29,118     $ 7,744     $     —     $ 36,862  
Foreign equity mutual funds
    4,515       1,448             5,963  
Money market funds
    628                   628  
                                 
    $ 34,261     $ 9,192     $     $ 43,453  
                                 
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 six months ended March 31, 2011. 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.
 
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 was held 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. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
March 30, 2011, we filed a notice of appeal of this ruling. 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 March 31, 2011, AEH was committed to purchase 92.8 Bcf within one year, 37.6 Bcf within one to three years and 4.5 Bcf after three years under indexed contracts. AEH is committed to purchase 1.6 Bcf within one year and 0.4 Bcf within one to three years under fixed price contracts with prices ranging from $4.02 to $6.36 per Mcf. Purchases under these contracts totaled $438.9 million and $538.6 million for the three months ended March 31, 2011 and 2010 and $773.1 million and $892.7 million for the six months ended March 31, 2011 and 2010.
 
Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
 
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of March 31, 2011 are as follows (in thousands):
 
         
2011
  $ 67,814  
2012
    94,485  
2013
    5,294  
2014
    1,863  
2015
     
Thereafter
     
         
    $ 169,456  
         
 
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 six months ended March 31, 2011.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 six months ended March 31, 2011. 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 14,939 lines for a cost of $21.7 million as of March 31, 2011. 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 March 31, 2011, rate cases were in progress in our Atmos Pipeline — Texas service area and an annual rate filing mechanism was in progress in our Mississippi service area. In addition, there were other ratemaking activities in progress in our Mid-Tex, West Texas, Georgia and Louisiana service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments and Regulated Transmission and Storage Segment.
 
Other Matters
 
As we previously discussed in Note 9 to the consolidated financial statements 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 agreed with the third party to extend the option period to March 2011. 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 have evaluated our strategic alternatives and concluded the project’s returns do not meet our investment objectives. Accordingly, in March 2011, we recorded a $19.3 million pretax noncash impairment loss to write off substantially all of our investment in the project.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
9.   Concentration of Credit Risk
 
Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010. During the six months ended March 31, 2011, 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 and six month periods ended March 31, 2011 and 2010 by segment are presented in the following tables to reflect our business structure as of March 31, 2011. Prior-year amounts have been restated accordingly.
 
                                         
    Three Months Ended March 31, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,112,968     $ 21,597     $ 482,722     $     $ 1,617,287  
Intersegment revenues
    236       33,379       100,809       (134,424 )      
                                         
      1,113,204       54,976       583,531       (134,424 )     1,617,287  
Purchased gas cost
    723,046             563,473       (134,054 )     1,152,465  
                                         
Gross profit
    390,158       54,976       20,058       (370 )     464,822  
Operating expenses
                                       
Operation and maintenance
    94,483       15,231       7,035       (370 )     116,379  
Depreciation and amortization
    50,224       5,798       1,114             57,136  
Taxes, other than income
    50,633       4,113       (643 )           54,103  
Asset impairment
                19,282             19,282  
                                         
Total operating expenses
    195,340       25,142       26,788       (370 )     246,900  
                                         
Operating income (loss)
    194,818       29,834       (6,730 )           217,922  
Miscellaneous income (expense)
    20,141       5,861       306       (121 )     26,187  
Interest charges
    29,622       8,085       306       (121 )     37,892  
                                         
Income (loss) before income taxes
    185,337       27,610       (6,730 )           206,217  
Income tax expense (benefit)
    66,727       9,871       (2,590 )           74,008  
                                         
Net income (loss)
  $ 118,610     $ 17,739     $ (4,140 )   $     $ 132,209  
                                         
Capital expenditures
  $ 109,762     $ 11,818     $ 1,921     $     $ 123,501  
                                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Three Months Ended March 31, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,365,736     $ 21,643     $ 552,887     $     $ 1,940,266  
Intersegment revenues
    252       33,538       124,145       (157,935 )      
                                         
      1,365,988       55,181       677,032       (157,935 )     1,940,266  
Purchased gas cost
    980,603             662,871       (157,529 )     1,485,945  
                                         
Gross profit
    385,385       55,181       14,161       (406 )     454,321  
Operating expenses
                                       
Operation and maintenance
    87,542       20,248       9,704       (406 )     117,088  
Depreciation and amortization
    46,748       5,282       1,050             53,080  
Taxes, other than income
    55,531       2,949       1,133             59,613  
                                         
Total operating expenses
    189,821       28,479       11,887       (406 )     229,781  
                                         
Operating income
    195,564       26,702       2,274             224,540  
Miscellaneous income (expense)
    776       (20 )     637       (1,344 )     49  
Interest charges
    29,256       7,954       3,716       (1,344 )     39,582  
                                         
Income (loss) before income taxes
    167,084       18,728       (805 )           185,007  
Income tax expense (benefit)
    64,353       6,658       (130 )           70,881  
                                         
Net income (loss)
  $ 102,731     $ 12,070     $ (675 )   $     $ 114,126  
                                         
Capital expenditures
  $ 95,765     $ 20,063     $ 1,362     $     $ 117,190  
                                         

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Six Months Ended March 31, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 1,839,962     $ 42,830     $ 891,490     $     $ 2,774,282  
Intersegment revenues
    437       61,153       167,681       (229,271 )      
                                         
      1,840,399       103,983       1,059,171       (229,271 )     2,774,282  
Purchased gas cost
    1,150,469             1,013,935       (228,504 )     1,935,900  
                                         
Gross profit
    689,930       103,983       45,236       (767 )     838,382  
Operating expenses
                                       
Operation and maintenance
    185,816       30,805       17,119       (767 )     232,973  
Depreciation and amortization
    99,502       11,597       2,198             113,297  
Taxes, other than income
    85,609       7,666       1,524             94,799  
Asset impairment
                19,282             19,282  
                                         
Total operating expenses
    370,927       50,068       40,123       (767 )     460,351  
                                         
Operating income
    319,003       53,915       5,113             378,031  
Miscellaneous income
    19,432       5,579       596       (157 )     25,450  
Interest charges
    59,341       16,149       1,476       (157 )     76,809  
                                         
Income before income taxes
    279,094       43,345       4,233             326,672  
Income tax expense
    103,166       15,504       1,796             120,466  
                                         
Net income
  $ 175,928     $ 27,841     $ 2,437     $     $ 206,206  
                                         
Capital expenditures
  $ 219,261     $ 24,557     $ 2,845     $     $ 246,663  
                                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Six Months Ended March 31, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
                (In thousands)        
 
Operating revenues from external parties
  $ 2,168,422     $ 41,485     $ 1,023,211     $     $ 3,233,118  
Intersegment revenues
    460       60,556       201,837       (262,853 )      
                                         
      2,168,882       102,041       1,225,048       (262,853 )     3,233,118  
Purchased gas cost
    1,488,870             1,141,112       (262,034 )     2,367,948  
                                         
Gross profit
    680,012       102,041       83,936       (819 )     865,170  
Operating expenses
                                       
Operation and maintenance
    183,575       37,827       20,367       (819 )     240,950  
Depreciation and amortization
    94,605       10,224       2,090             106,919  
Taxes, other than income
    93,521       6,216       2,428             102,165  
                                         
Total operating expenses
    371,701       54,267       24,885       (819 )     450,034  
                                         
Operating income
    308,311       47,774       59,051             415,136  
Miscellaneous income (expense)
    1,433       23       1,013       (2,689 )     (220 )
Interest charges
    58,934       15,922       6,123       (2,689 )     78,290  
                                         
Income before income taxes
    250,810       31,875       53,941             336,626  
Income tax expense
    96,631       11,351       21,188             129,170  
                                         
Net income
  $ 154,179     $ 20,524     $ 32,753     $     $ 207,456  
                                         
Capital expenditures
  $ 196,227     $ 33,822     $ 2,580     $     $ 232,629  
                                         

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at March 31, 2011 and September 30, 2010 by segment is presented to reflect our business structure as of March 31, 2011 in the following tables. Prior-year amounts have been restated accordingly.
 
                                         
    March 31, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
                                       
Property, plant and equipment, net
  $ 4,087,399     $ 760,221     $ 67,030     $     $ 4,914,650  
Investment in subsidiaries
    665,515             (2,096 )     (663,419 )      
Current assets
                                       
Cash and cash equivalents
    41,436             111,810             153,246  
Assets from risk management activities
    33,923             10,692             44,615  
Other current assets
    519,521       11,810       432,606       (177,710 )     786,227  
Intercompany receivables
    505,915                   (505,915 )      
                                         
Total current assets
    1,100,795       11,810       555,108       (683,625 )     984,088  
Intangible assets
                520             520  
Goodwill
    572,262       132,341       34,711             739,314  
Noncurrent assets from risk management activities
                462             462  
Deferred charges and other assets
    330,253       11,487       15,050             356,790  
                                         
    $ 6,756,224     $ 915,859     $ 670,785     $ (1,347,044 )   $ 6,995,824  
                                         
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
  $ 2,373,979     $ 240,528     $ 424,987     $ (665,515 )   $ 2,373,979  
Long-term debt
    1,807,127             196             1,807,323  
                                         
Total capitalization
    4,181,106       240,528       425,183       (665,515 )     4,181,302  
Current liabilities
                                       
Current maturities of long-term debt
    352,303             131             352,434  
Short-term debt
    163,900                   (163,900 )      
Liabilities from risk management activities
    3,390             2,760             6,150  
Other current liabilities
    494,037       5,340       231,737       (11,714 )     719,400  
Intercompany payables
          505,019       896       (505,915 )      
                                         
Total current liabilities
    1,013,630       510,359       235,524       (681,529 )     1,077,984  
Deferred income taxes
    779,026       159,764       5,815             944,605  
Noncurrent liabilities from risk management activities
                4,283             4,283  
Regulatory cost of removal obligation
    364,709                         364,709  
Deferred credits and other liabilities
    417,753       5,208       (20 )           422,941  
                                         
    $ 6,756,224     $ 915,859     $ 670,785     $ (1,347,044 )   $ 6,995,824  
                                         
 


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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 March 31, 2011, the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2011 and 2010, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2011 and 2010. 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
May 5, 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 our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to 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 primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties. 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, 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.
 
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 six months ended March 31, 2011.
 
RESULTS OF OPERATIONS
 
We reported net income of $132.2 million, or $1.45 per diluted share for the three months ended March 31, 2011 compared with net income of $114.1 million, or $1.22 per diluted share in the prior-year quarter. Unrealized losses reduced net income by $2.1 million, or $0.02 per diluted share for the three months ended March 31, 2011, compared with net unrealized losses of $25.5 million, or $0.27 per diluted share for the prior-year quarter. In addition, net income for the second quarter includes the impact of several one-time items totaling $11.1 million, or $0.12 per diluted share related to the following pre-tax amounts:
 
  •  $27.8 million favorable impact related to the cash gain recorded in association with the unwinding of two Treasury locks in conjunction with the cancellation of a planned debt offering in November 2011.
 
  •  $19.3 million unfavorable impact related to the non-cash impairment of assets in the Ft. Necessity storage project.
 
  •  $5.0 million favorable impact related to the administrative settlement of various income tax positions.


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Excluding the impact of unrealized margins and one-time items, diluted earnings per share decreased from $1.44 in the prior-year quarter to $1.35 in the current-year quarter, primarily due to decreased asset optimization margins in our nonregulated segment and a decline of 11 percent in consolidated throughput in our natural gas distribution segment.
 
We reported net income of $206.2 million, or $2.26 per diluted share for the six months ended March 31, 2011 compared with net income of $207.5 million, or $2.22 per diluted share in the prior-year period. Unrealized losses reduced net income by $1.7 million, or $0.02 per diluted share for the six months ended March 31, 2011. Regulated operations contributed 99 percent of our net income during this period with our nonregulated operations contributing the remaining 1 percent. The primary driver in the year-over-year decrease in net income was decreased asset optimization margins in our nonregulated segment and a decline of 11 percent in consolidated throughput in our natural gas distribution segment.
 
On March 4, 2011, we received and retired 375,468 common shares from Goldman Sachs & Co under our accelerated share repurchase agreement that commenced in the fourth quarter of fiscal 2010. The receipt and retirement of these additional shares concluded our share repurchase agreement under which we paid a total of $100 million and received and retired an aggregate of 3,334,048 common shares. As a result of this transaction, our weighted-average shares outstanding used to calculate our earnings per share were reduced by the number of shares repurchased as they were delivered to us.
 
During the six months ended March 31, 2011, 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, which expired in April 2011. As planned, we did not replace or extend this 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. Finally, on May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility that contains an accordion feature that could increase our borrowing capacity to $1.0 billion. After giving effect to these changes, we now have $975 million of liquidity available to us from our commercial paper program and three committed credit facilities and have reduced our financing costs. We believe this availability provides sufficient liquidity to fund our working capital needs.
 
The following table presents our consolidated financial highlights for the three and six months ended March 31, 2011 and 2010:
 
                                 
    Three Months Ended
  Six Months Ended
    March 31   March 31
    2011   2010   2011   2010
    (In thousands, except per share data)
 
Operating revenues
  $ 1,617,287     $ 1,940,266     $ 2,774,282     $ 3,233,118  
Gross profit
    464,822       454,321       838,382       865,170  
Operating expenses
    246,900       229,781       460,351       450,034  
Operating income
    217,922       224,540       378,031       415,136  
Miscellaneous income (expense)
    26,187       49       25,450       (220 )
Interest charges
    37,892       39,582       76,809       78,290  
Income before income taxes
    206,217       185,007       326,672       336,626  
Income tax expense
    74,008       70,881       120,466       129,170  
Net income
  $ 132,209     $ 114,126     $ 206,206     $ 207,456  
Diluted net income per share
  $ 1.45     $ 1.22     $ 2.26     $ 2.22  


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Our consolidated net income during the three and six months ended March 31, 2011 and 2010 was earned in each of our business segments as follows:
 
                         
    Three Months Ended March 31  
    2011     2010     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 118,610     $ 102,731     $ 15,879  
Regulated transmission and storage segment
    17,739       12,070       5,669  
Nonregulated segment
    (4,140 )     (675 )     (3,465 )
                         
Net income
  $ 132,209     $ 114,126     $ 18,083  
                         
 
                         
    Six Months Ended March 31  
    2011     2010     Change  
    (In thousands)  
 
Natural gas distribution segment
  $ 175,928     $ 154,179     $ 21,749  
Regulated transmission and storage segment
    27,841       20,524       7,317  
Nonregulated segment
    2,437       32,753       (30,316 )
                         
Net income
  $ 206,206     $ 207,456     $ (1,250 )
                         
 
The following tables segregate our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    Three Months Ended March 31  
    2011     2010     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 136,349     $ 114,801     $ 21,548  
Nonregulated operations
    (4,140 )     (675 )     (3,465 )
                         
Consolidated net income
  $ 132,209     $ 114,126     $ 18,083  
                         
Diluted EPS from regulated operations
  $ 1.49     $ 1.23     $ 0.26  
Diluted EPS from nonregulated operations
    (0.04 )     (0.01 )     (0.03 )
                         
Consolidated diluted EPS
  $ 1.45     $ 1.22     $ 0.23  
                         
 
                         
    Six Months Ended March 31  
    2011     2010     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 203,769     $ 174,703     $ 29,066  
Nonregulated operations
    2,437       32,753       (30,316 )
                         
Consolidated net income
  $ 206,206     $ 207,456     $ (1,250 )
                         
Diluted EPS from regulated operations
  $ 2.23     $ 1.87     $ 0.36  
Diluted EPS from nonregulated operations
    0.03       0.35       (0.32 )
                         
Consolidated diluted EPS
  $ 2.26     $ 2.22     $ 0.04  
                         
 
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,


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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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Three Months Ended March 31, 2011 compared with Three Months Ended March 31, 2010
 
Financial and operational highlights for our natural gas distribution segment for the three months ended March 31, 2011 and 2010 are presented below.
 
                         
    Three Months Ended March 31  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 390,158     $ 385,385     $ 4,773  
Operating expenses
    195,340       189,821       5,519  
                         
Operating income
    194,818       195,564       (746 )
Miscellaneous income
    20,141       776       19,365  
Interest charges
    29,622       29,256       366  
                         
Income before income taxes
    185,337       167,084       18,253  
Income tax expense
    66,727       64,353       2,374  
                         
Net income
  $ 118,610     $ 102,731     $ 15,879  
                         
Consolidated natural gas distribution sales volumes — MMcf
    136,838       158,530       (21,692 )
Consolidated natural gas distribution transportation volumes — MMcf
    39,463       39,294       169  
                         
Total consolidated natural gas distribution throughput — MMcf
    176,301       197,824       (21,523 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.47     $ 0.46     $ 0.01  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 5.28     $ 6.19     $ (0.91 )
 
The following table shows our operating income by natural gas distribution division, in order of total rate base, for the three months ended March 31, 2011 and 2010. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Three Months Ended March 31  
    2011     2010     Change  
    (In thousands)  
 
Mid-Tex
  $ 82,476     $ 79,843     $ 2,633  
Kentucky/Mid-States
    35,177       31,000       4,177  
Louisiana
    23,235       22,831       404  
West Texas
    19,280       21,400       (2,120 )
Colorado-Kansas
    15,633       14,267       1,366  
Mississippi
    18,004       17,852       152  
Other
    1,013       8,371       (7,358 )
                         
Total
  $ 194,818     $ 195,564     $ (746 )
                         
 
The $4.8 million increase in natural gas distribution gross profit primarily reflects a $17.7 million net increase in rate adjustments, primarily in the Mid-Tex, Missouri, Louisiana, Kentucky, Kansas and Georgia service areas.
 
These increases in rate adjustments were partially offset by:
 
  •  $7.9 million decrease due to an 11 percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather this fiscal year compared to the same period last year in most of our service areas.


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  •  $4.2 million decrease in revenue-related taxes, primarily due to lower revenues on which the tax is calculated.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $5.5 million, primarily due to the following:
 
  •  $7.4 million increase due to the absence of a state sales tax refund received in the prior year.
 
  •  $3.5 million increase in depreciation and amortization expense.
 
These increases were partially offset by:
 
  •  $4.9 million decrease in taxes, other than income, primarily due to lower revenue-related taxes.
 
Net income for this segment was also favorably impacted by a $21.8 million gain recognized in March 2011 as a result of unwinding two Treasury locks and a $5.0 million income tax benefit related to the administrative settlement of various income tax positions.
 
Six Months Ended March 31, 2011 compared with Six Months Ended March 31, 2010
 
Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2011 and 2010 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 689,930     $ 680,012     $ 9,918  
Operating expenses
    370,927       371,701       (774 )
                         
Operating income
    319,003       308,311       10,692  
Miscellaneous income
    19,432       1,433       17,999  
Interest charges
    59,341       58,934       407  
                         
Income before income taxes
    279,094       250,810       28,284  
Income tax expense
    103,166       96,631       6,535  
                         
Net income
  $ 175,928     $ 154,179     $ 21,749  
                         
Consolidated natural gas distribution sales volumes — MMcf
    223,628       257,844       (34,216 )
Consolidated natural gas distribution transportation volumes —
                       
MMcf
    73,217       74,501       (1,284 )
                         
Total consolidated natural gas distribution throughput —
                       
MMcf
    296,845       332,345       (35,500 )
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.48     $ 0.46     $ 0.02  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 5.14     $ 5.77     $ (0.63 )


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The following table shows our operating income by natural gas distribution division, in order of total rate base, for the six months ended March 31, 2011 and 2010. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Six Months Ended
 
    March 31  
    2011     2010     Change  
    (In thousands)  
 
Mid-Tex
  $ 139,915     $ 130,224     $ 9,691  
Kentucky/Mid-States
    56,540       48,803       7,737  
Louisiana
    38,196       36,238       1,958  
West Texas
    28,800       33,157       (4,357 )
Colorado-Kansas
    23,645       22,873       772  
Mississippi
    28,219       27,654       565  
Other
    3,688       9,362       (5,674 )
                         
Total
  $ 319,003     $ 308,311     $ 10,692  
                         
 
The $9.9 million increase in natural gas distribution gross profit primarily reflects a $31.8 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Missouri, Kentucky, Kansas and Georgia service areas.
 
These increases were partially offset by:
 
  •  $13.2 million decrease due to an 11 percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather this fiscal year compared to the same period last year in most of our service areas.
 
  •  $7.0 million decrease in revenue-related taxes, primarily due to lower revenues on which the tax is calculated.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income decreased $0.8 million, primarily due to the following:
 
  •  $7.9 million decrease in taxes, other than income, due to lower revenue-related taxes.
 
  •  $5.3 million decrease in employee-related expenses.
 
  •  $1.4 million decrease in legal and other administrative costs.
 
These decreases were partially offset by:
 
  •  $7.4 million increase due to the absence of a state sales tax refund received in the prior year.
 
  •  $4.9 million increase in depreciation and amortization expense.
 
Net income also reflects the aforementioned Treasury lock gain and income tax benefit.
 
Recent Ratemaking Developments
 
Significant ratemaking developments that occurred during the six months ended March 31, 2011 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.


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Annual net operating income increases totaling $25.2 million resulting from ratemaking activity became effective in the six months ended March 31, 2011 as summarized below:
 
         
    Annual Increase to
 
Rate Action
  Operating Income  
    (In thousands)  
 
Annual rate filing mechanisms
  $ 23,122  
Other rate activity
    2,075  
         
    $ 25,197  
         
 
Additionally, the following ratemaking efforts were in progress during the second quarter of fiscal 2011 but had not been completed as of March 31, 2011.
 
                 
            Operating
 
            Income
 
Division
 
Rate Action
 
Jurisdiction
  Requested  
            (In thousands)  
 
Kentucky/Mid-States
  PRP(1)   Georgia   $ 1,192  
Louisiana
  TransLA RSC(2)   Louisiana     431  
    LGS RSC   Louisiana     4,600  
Mid-Tex
  GRIP(3)(4)   Dallas & RRC     3,519  
    Rate Review Mechanism (RRM)   Settled Cities     7,687  
Mississippi
  Annual Rate Filing(5)   Mississippi      
West Texas
  Environs Rate Case   Amarillo     78  
    RRM   Lubbock     2,136  
    RRM   WT Cities     2,552  
    GRIP(3)   RRC     342  
                 
            $ 22,537  
                 
 
 
(1) The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.
 
(2) The Louisiana Commission Staff recommended an increase of $0.4 million effective April 1, 2011, which the Commission accepted.
 
(3) Gas Reliability Infrastructure Program (GRIP) is a rate adjustment that allows utilities to recover additional invested capital without filing a full rate case.
 
(4) This GRIP filing is based on a Mid-Tex system-wide basis and made concurrently with the City of Dallas and the Texas Railroad Commission (RRC) for approval of their respective jurisdictional customers.
 
(5) On April 5, 2011 the Mississippi Public Service Commission approved a Stipulation and Agreement for no increase in operating income.
 
Rate Filings
 
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 rate cases completed during the first two quarters of fiscal 2011.
 
GRIP Filings
 
GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years. There were no GRIP filings completed during the first two quarters of fiscal 2011.


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Annual Rate Filing Mechanisms
 
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 (RRM) 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 six months ended March 31, 2011.
 
                         
              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      
                         
 
Other Ratemaking Activity
 
The following table summarizes other ratemaking activity during the six months ended March 31, 2011:
 
                     
            Additional
     
            Annual
     
            Operating
    Effective
Division
  Jurisdiction   Rate Activity   Income     Date
            (In thousands)      
 
2011 Other Rate Activity:
                   
Kentucky/Mid-States
  Georgia   PRP Surcharge   $ 764     10/01/2010
Colorado-Kansas
  Colorado   AMI(1)     349     12/01/2010
Colorado-Kansas
  Kansas   Ad Valorem(2)     685     01/01/2011
Kentucky/Mid-States
  Missouri   ISRS(3)     277     02/14/2011
                     
Total 2011 Other Rate Activity
          $ 2,075      
                     
 
 
(1) Automated Meter Infrastructure (AMI) relates to a pilot program in the Weld County area of the Company’s service area.
 
(2) The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in the Company’s base rates.
 
(3) Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.
 
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


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may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
 
Three Months Ended March 31, 2011 compared with Three Months Ended March 31, 2010
 
Financial and operational highlights for our regulated transmission and storage segment for the three months ended March 31, 2011 and 2010 are presented below.
 
                         
    Three Months Ended
 
    March 31  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 33,096     $ 33,214     $ (118 )
Third-party transportation
    16,811       16,335       476  
Storage and park and lend services
    2,219       2,673       (454 )
Other
    2,850       2,959       (109 )
                         
Gross profit
    54,976       55,181       (205 )
Operating expenses
    25,142       28,479       (3,337 )
                         
Operating income
    29,834       26,702       3,132  
Miscellaneous income (expense)
    5,861       (20 )     5,881  
Interest charges
    8,085       7,954       131  
                         
Income before income taxes
    27,610       18,728       8,882  
Income tax expense
    9,871       6,658       3,213  
                         
Net income
  $ 17,739     $ 12,070     $ 5,669  
                         
Gross pipeline transportation volumes — MMcf
    174,471       192,441       (17,970 )
                         
Consolidated pipeline transportation volumes — MMcf
    93,493       98,418       (4,925 )
                         
 
The $0.2 million decrease in regulated transmission and storage gross profit was attributable primarily to a $2.7 million decrease due to a nine percent decrease in through-system volumes primarily associated with declines in basis differentials, electric generation demand and Barnett Shale activity and a $0.8 million quarter-over-quarter decrease from lower per-unit transportation margins, partially offset by a $3.1 million increase associated with our GRIP filings.
 
Operating expenses decreased $3.3 million primarily due to timing of pipeline maintenance activities and other operating expenses.
 
Miscellaneous income includes a $6.0 million gain recognized in March 2011 as a result of unwinding two Treasury locks.
 
On April 18, 2011, the RRC issued an order in the rate case of Atmos Pipeline — Texas that was originally filed in September 2010. The Commission approved an annual operating income increase of $20.4 million as well as the following major provisions that will go into effect with bills rendered on and after May 1, 2011:
 
  •  Authorized return on equity of 11.8 percent.
 
  •  A capital structure of 49.5 percent debt/50.5 percent equity
 
  •  Approval of a rate base of $807.7 million, compared to the $417.1 million rate base from the prior rate case.
 
  •  Approval of a straight fixed variable rate design, under which all fixed costs associated with transportation and storage services are recovered through monthly charges.


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Six Months Ended March 31, 2011 compared with Six Months Ended March 31, 2010
 
Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2011 and 2010 are presented below.
 
                         
    Six Months Ended
 
    March 31  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Mid-Tex transportation
  $ 60,631     $ 59,925     $ 706  
Third-party transportation
    33,323       31,577       1,746  
Storage and park and lend services
    4,389       5,278       (889 )
Other
    5,640       5,261       379  
                         
Gross profit
    103,983       102,041       1,942  
Operating expenses
    50,068       54,267       (4,199 )
                         
Operating income
    53,915       47,774       6,141  
Miscellaneous income
    5,579       23       5,556  
Interest charges
    16,149       15,922       227  
                         
Income before income taxes
    43,345       31,875       11,470  
Income tax expense
    15,504       11,351       4,153  
                         
Net income
  $ 27,841     $ 20,524     $ 7,317  
                         
Gross pipeline transportation volumes — MMcf
    327,649       350,214       (22,565 )
                         
Consolidated pipeline transportation volumes — MMcf
    193,334       194,356       (1,022 )
                         
 
The $1.9 million increase in regulated transmission and storage gross profit was attributable primarily to the following factors:
 
  •  $6.2 million increase associated with our GRIP filings.
 
  •  $2.4 million increase in fixed fee services.
 
These increases were partially offset by the following:
 
  •  $3.7 million decrease due to a decline in throughput to our Mid-Tex Division and a reduction in production.
 
  •  $2.3 million decrease resulting from lower per-unit transportation margins.
 
Operating expenses decreased $4.2 million primarily due to timing of pipeline maintenance activities and other expenses.
 
Miscellaneous income reflects the aforementioned treasury lock gain recognized in March 2011.
 
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


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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 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, for 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


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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, 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.
 
Three Months Ended March 31, 2011 compared with Three Months Ended March 31, 2010
 
Financial and operational highlights for our nonregulated segment for the three months ended March 31, 2011 and 2010 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
 
    March 31  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Realized margins
                       
Gas delivery and related services
  $ 19,170     $ 17,126     $ 2,044  
Storage and transportation services
    3,522       3,093       429  
Other
    1,460       2,098       (638 )
                         
      24,152       22,317       1,835  
Asset optimization(1)
    (686 )     31,385       (32,071 )
                         
Total realized margins
    23,466       53,702       (30,236 )
Unrealized margins
    (3,408 )     (39,541 )     36,133  
                         
Gross profit
    20,058       14,161       5,897  
Operating expenses, excluding asset impairment
    7,506       11,887       (4,381 )
Asset impairment
    19,282             19,282  
                         
Operating income (loss)
    (6,730 )     2,274       (9,004 )
Miscellaneous income
    306       637       (331 )
Interest charges
    306       3,716       (3,410 )