10-Q 1 d83924e10vq.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 June 30, 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 July 29, 2011.
 
     
Class
 
Shares Outstanding
 
No Par Value
  90,285,306
 


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
EX-101 DEFINITION LINKBASE DOCUMENT


Table of Contents

 
GLOSSARY OF KEY TERMS
 
     
AEC
  Atmos Energy Corporation
AEH
  Atmos Energy Holdings, Inc.
AEM
  Atmos Energy Marketing, LLC
AOCI
  Accumulated other comprehensive income
APS
  Atmos Pipeline and Storage, LLC
Bcf
  Billion cubic feet
FASB
  Financial Accounting Standards Board
Fitch
  Fitch Ratings, Ltd.
GRIP
  Gas Reliability Infrastructure Program
GSRS
  Gas System Reliability Surcharge
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
 
                 
    June 30,
    September 30,
 
    2011     2010  
    (Unaudited)        
    (In thousands, except
 
    share data)  
 
ASSETS
Property, plant and equipment
  $ 6,599,950     $ 6,542,318  
Less accumulated depreciation and amortization
    1,683,899       1,749,243  
                 
Net property, plant and equipment
    4,916,051       4,793,075  
Current assets
               
Cash and cash equivalents
    117,429       131,952  
Accounts receivable, net
    342,092       273,207  
Gas stored underground
    256,768       319,038  
Other current assets
    273,459       150,995  
                 
Total current assets
    989,748       875,192  
Goodwill and intangible assets
    739,677       740,148  
Deferred charges and other assets
    347,994       355,376  
                 
    $ 6,993,470     $ 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:
               
June 30, 2011 — 90,284,722 shares;
               
September 30, 2010 — 90,164,103 shares
  $ 451     $ 451  
Additional paid-in capital
    1,730,121       1,714,364  
Retained earnings
    599,506       486,905  
Accumulated other comprehensive income (loss)
    5,746       (23,372 )
                 
Shareholders’ equity
    2,335,824       2,178,348  
Long-term debt
    2,206,106       1,809,551  
                 
Total capitalization
    4,541,930       3,987,899  
Current liabilities
               
Accounts payable and accrued liabilities
    312,205       266,208  
Other current liabilities
    333,643       413,640  
Short-term debt
          126,100  
Current maturities of long-term debt
    2,434       360,131  
                 
Total current liabilities
    648,282       1,166,079  
Deferred income taxes
    967,607       829,128  
Regulatory cost of removal obligation
    396,201       350,521  
Deferred credits and other liabilities
    439,450       430,164  
                 
    $ 6,993,470     $ 6,763,791  
                 
 
See accompanying notes to condensed consolidated financial statements


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Table of Contents

ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Three Months Ended
 
    June 30  
    2011     2010  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 407,031     $ 396,319  
Regulated transmission and storage segment
    53,570       44,957  
Nonregulated segment
    491,285       427,405  
Intersegment eliminations
    (108,271 )     (107,376 )
                 
      843,615       761,305  
Purchased gas cost
               
Natural gas distribution segment
    206,839       204,988  
Regulated transmission and storage segment
           
Nonregulated segment
    477,880       415,634  
Intersegment eliminations
    (107,909 )     (106,983 )
                 
      576,810       513,639  
                 
Gross profit
    266,805       247,666  
Operating expenses
               
Operation and maintenance
    112,665       111,559  
Depreciation and amortization
    56,932       51,940  
Taxes, other than income
    52,142       51,908  
Asset impairments
    10,988        
                 
Total operating expenses
    232,727       215,407  
                 
Operating income
    34,078       32,259  
Miscellaneous expense
    (1,430 )     (798 )
Interest charges
    35,845       37,267  
                 
Loss from continuing operations before income taxes
    (3,197 )     (5,806 )
Income tax benefit
    (1,723 )     (1,577 )
                 
Loss from continuing operations
    (1,474 )     (4,229 )
Income from discontinued operations, net of tax ($590 and $700)
    908       1,075  
                 
Net loss
  $ (566 )   $ (3,154 )
                 
Basic earning per share
               
Loss per share from continuing operations
  $ (0.02 )   $ (0.04 )
Income per share from discontinued operations
    0.01       0.01  
                 
Net loss per share — basic
  $ (0.01 )   $ (0.03 )
                 
Diluted earnings per share
               
Loss per share from continuing operations
  $ (0.02 )   $ (0.04 )
Income per share from discontinued operations
    0.01       0.01  
                 
Net loss per share — diluted
  $ (0.01 )   $ (0.03 )
                 
Cash dividends per share
  $ 0.34     $ 0.335  
                 
Weighted average shares outstanding:
               
Basic
    90,127       92,648  
                 
Diluted
    90,127       92,648  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
                 
    Nine Months Ended
 
    June 30  
    2011     2010  
    (Unaudited)
 
    (In thousands, except
 
    per share data)  
 
Operating revenues
               
Natural gas distribution segment
  $ 2,187,907     $ 2,512,032  
Regulated transmission and storage segment
    157,553       146,998  
Nonregulated segment
    1,550,456       1,652,453  
Intersegment eliminations
    (337,542 )     (370,229 )
                 
      3,558,374       3,941,254  
Purchased gas cost
               
Natural gas distribution segment
    1,317,775       1,657,412  
Regulated transmission and storage segment
           
Nonregulated segment
    1,491,815       1,556,746  
Intersegment eliminations
    (336,413 )     (369,017 )
                 
      2,473,177       2,845,141  
                 
Gross profit
    1,085,197       1,096,113  
Operating expenses
               
Operation and maintenance
    341,317       348,458  
Depreciation and amortization
    167,176       156,201  
Taxes, other than income
    145,868       152,840  
Asset impairments
    30,270        
                 
Total operating expenses
    684,631       657,499  
                 
Operating income
    400,566       438,614  
Miscellaneous income (expense)
    24,046       (905 )
Interest charges
    112,615       115,481  
                 
Income from continuing operations before income taxes
    311,997       322,228  
Income tax expense
    114,211       124,199  
                 
Income from continuing operations
    197,786       198,029  
Income from discontinued operations, net of tax ($5,122 and $4,094)
    7,854       6,273  
                 
Net income
  $ 205,640     $ 204,302  
                 
Basic earning per share
               
Income per share from continuing operations
  $ 2.17     $ 2.12  
Income per share from discontinued operations
    0.09       0.07  
                 
Net income per share — basic
  $ 2.26     $ 2.19  
                 
Diluted earnings per share
               
Income per share from continuing operations
  $ 2.16     $ 2.11  
Income per share from discontinued operations
    0.09       0.07  
                 
Net income per share — diluted
  $ 2.25     $ 2.18  
                 
Cash dividends per share
  $ 1.02     $ 1.005  
                 
Weighted average shares outstanding:
               
Basic
    90,233       92,513  
                 
Diluted
    90,530       92,856  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Nine Months Ended
 
    June 30  
    2011     2010  
    (Unaudited)
 
    (In thousands)  
 
Cash Flows From Operating Activities
               
Net income
  $ 205,640     $ 204,302  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Asset impairments
    30,270        
Depreciation and amortization:
               
Charged to depreciation and amortization
    171,726       160,207  
Charged to other accounts
    149       116  
Deferred income taxes
    115,488       186,325  
Other
    15,927       18,425  
Net assets/liabilities from risk management activities
    (15,869 )     3,429  
Net change in operating assets and liabilities
    (3,769 )     21,760  
                 
Net cash provided by operating activities
    519,562       594,564  
Cash Flows From Investing Activities
               
Capital expenditures
    (390,283 )     (362,349 )
Other, net
    (3,373 )     (438 )
                 
Net cash used in investing activities
    (393,656 )     (362,787 )
Cash Flows From Financing Activities
               
Net decrease in short-term debt
    (132,072 )     (76,019 )
Net proceeds from issuance of long-term debt
    394,618        
Settlement of Treasury lock agreements
    20,079        
Unwinding of Treasury lock agreements
    27,803        
Repayment of long-term debt
    (360,066 )     (66 )
Cash dividends paid
    (93,039 )     (93,913 )
Repurchase of equity awards
    (5,300 )     (1,173 )
Issuance of common stock
    7,548       8,574  
                 
Net cash used in financing activities
    (140,429 )     (162,597 )
                 
Net increase (decrease) in cash and cash equivalents
    (14,523 )     69,180  
Cash and cash equivalents at beginning of period
    131,952       111,203  
                 
Cash and cash equivalents at end of period
  $ 117,429     $ 180,383  
                 
 
See accompanying notes to condensed consolidated financial statements


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 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 currently cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers. After the closing of this transaction, we will operate in nine states. 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 11, 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 nine-month period ended June 30, 2011 are not indicative of our results of operations for the full 2011 fiscal year, which ends September 30, 2011.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Our earnings have been impacted by several one-time items in the current year, including the following pre-tax amounts:
 
  •  $27.8 million 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 non-cash impairment of assets in the Ft. Necessity storage project.
 
  •  $11.0 million non-cash impairment of certain natural gas gathering assets.
 
  •  $5.0 million one-time tax benefit related to the administrative settlement of various income tax positions.
 
We have evaluated subsequent events from the June 30, 2011 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). 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.
 
As a result of discontinued operations, certain prior-year amounts have been reclassified to conform with the current year presentation.
 
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 nine months ended June 30, 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 had no impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the nine months ended June 30, 2011.
 
In May 2011, the Financial Accounting Standards Board (FASB) issued guidance that will provide a consistent definition of fair value and ensure that fair value measurements and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards. This guidance will change certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements and is effective prospectively for the Company for interim and annual periods beginning after December 15, 2011. We currently do not have any recurring Level 3 fair value measurements; accordingly, the adoption of this guidance will not impact our financial position, results of operations or cash flows.
 
In June 2011, the FASB issued guidance related to the presentation of other comprehensive income which will require that all nonowner changes in shareholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. This guidance is effective retrospectively for the Company for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of this guidance will not impact our financial position, results of operations or cash flows.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Regulatory assets and liabilities
 
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
 
Significant regulatory assets and liabilities as of June 30, 2011 and September 30, 2010 included the following:
 
                 
    June 30,
    September 30,
 
    2011     2010  
    (In thousands)  
 
Regulatory assets:
               
Pension and postretirement benefit costs
  $ 200,393     $ 209,564  
Merger and integration costs, net
    6,360       6,714  
Deferred gas costs
    22,083       22,701  
Regulatory cost of removal asset
    32,691       31,014  
Environmental costs
    434       805  
Rate case costs
    5,321       4,505  
Deferred franchise fees
    393       1,161  
Other
    3,940       1,046  
                 
    $ 271,615     $ 277,510  
                 
Regulatory liabilities:
               
Deferred gas costs
  $ 18,739     $ 43,333  
Deferred franchise fees
    629        
Regulatory cost of removal obligation
    429,354       381,474  
Other
    9,166       6,112  
                 
    $ 457,888     $ 430,919  
                 
 
The June 30, 2011 amounts above do not include regulatory assets and liabilities related to our Missouri, Illinois and Iowa service areas, which are classified as assets held for sale as discussed in Note 5.
 
Currently, our authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from various state regulatory commissions.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Comprehensive income
 
The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and nine-month periods ended June 30, 2011 and 2010:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2011     2010     2011     2010  
    (In thousands)  
 
Net income (loss)
  $ (566 )   $ (3,154 )   $ 205,640     $ 204,302  
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(56) and $(996) for the three months ended June 30, 2011 and 2010 and of $876 and $(198) for the nine months ended June 30, 2011 and 2010
    (94 )     (1,696 )     1,492       (337 )
Amortization, unrealized gain and unwinding of interest rate hedging transactions, net of tax expense (benefit) of $(4,629) and $247 for the three months ended June 30, 2011 and 2010 and $7,950 and $743 for the nine month ended June 30, 2011 and 2010
    (7,884 )     422       13,536       1,265  
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $(182) and $5,066 for the three months ended June 30, 2011 and 2010 and $9,008 and $2,999 for the nine months ended June 30, 2011 and 2010
    (285 )     7,921       14,090       4,690  
                                 
Comprehensive income (loss)
  $ (8,829 )   $ 3,493     $ 234,758     $ 209,920  
                                 
 
Accumulated other comprehensive income (loss), net of tax, as of June 30, 2011 and September 30, 2010 consisted of the following unrealized gains (losses):
 
                 
    June 30,
    September 30,
 
    2011     2010  
    (In thousands)  
 
Accumulated other comprehensive income (loss):
               
Unrealized holding gains on investments
  $ 5,697     $ 4,205  
Treasury lock agreements
    8,068       (5,468 )
Cash flow hedges
    (8,019 )     (22,109 )
                 
    $ 5,746     $ (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 third 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 (generally October through March), 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 obligation, to buy or sell the commodity at a fixed


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 65 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 June 30, 2011, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 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.
 
In September 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $300 million of a total $400 million of senior notes that were issued in June 2011. This offering is discussed in Note 6. We designated these Treasury locks as cash flow hedges of an anticipated transaction. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the net $12.6 million unrealized gain was recorded as a component of accumulated other comprehensive income and will be recognized as a component of interest expense over the 30-year life of the senior notes.
 
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 was eliminated and the related Treasury lock


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
agreements were unwound in March 2011. As a result of unwinding these Treasury locks, we recognized a pre-tax cash gain of $27.8 million during the second quarter.
 
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, as well as the Treasury locks discussed above, 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 2041.
 
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 June 30, 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 June 30, 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           (20,915 )        
    Cash Flow           28,317          
    Not designated     16,340       18,140          
                             
          16,340       25,542          
                             
 
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 June 30, 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 $15.4 million and $24.9 million of cash held on deposit in margin accounts as of June 30, 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 amounts below


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.
 
                             
        Natural
             
        Gas
             
    Balance Sheet Location   Distribution     Nonregulated     Total  
        (In thousands)  
 
June 30, 2011
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 11,529     $ 11,529  
Noncurrent commodity contracts
  Deferred charges and other assets           241       241  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (15,930 )     (15,930 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (6,237 )     (6,237 )
                             
Total
              (10,397 )     (10,397 )
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets     1,972       19,174       21,146  
Noncurrent commodity contracts
  Deferred charges and other assets     767       7,093       7,860  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (5,207 )     (20,109 )     (25,316 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (56 )     (7,170 )     (7,226 )
                             
Total
        (2,524 )     (1,012 )     (3,536 )
                             
Total Financial Instruments
      $ (2,524 )   $ (11,409 )   $ (13,933 )
                             
 
                             
        Natural
             
        Gas
             
    Balance Sheet Location   Distribution     Nonregulated     Total  
        (In thousands)  
 
September 30, 2010
                           
Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets   $     $ 40,030     $ 40,030  
Noncurrent commodity contracts
  Deferred charges and other assets           2,461       2,461  
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities           (56,575 )     (56,575 )
Noncurrent commodity contracts
  Deferred credits and other liabilities           (9,222 )     (9,222 )
                             
Total
              (23,306 )     (23,306 )
                             
Not Designated As Hedges:
                           
Asset Financial Instruments
                           
Current commodity contracts
  Other current assets     2,219       16,459       18,678  
Noncurrent commodity contracts
  Deferred charges and other assets     47       2,056       2,103  
                             
Liability Financial Instruments
                           
Current commodity contracts
  Other current liabilities     (48,942 )     (7,178 )     (56,120 )
Noncurrent commodity contracts
  Deferred credits and other liabilities     (2,924 )     (405 )     (3,329 )
                             
Total
        (49,600 )     10,932       (38,668 )
                             
Total Financial Instruments
      $ (49,600 )   $ (12,374 )   $ (61,974 )
                             
 
Impact of Financial Instruments on the Income Statement
 
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended June 30, 2011 and 2010 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $5.8 million and $3.8 million. For the nine months ended June 30, 2011 and 2010 we


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
recognized a gain arising from fair value and cash flow hedge ineffectiveness of $23.3 million and $44.2 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 nine months ended June 30, 2011 and 2010 is presented below.
 
                 
    Three Months Ended June 30  
    2011     2010  
    (In thousands)  
 
Commodity contracts
  $ 7,837     $ (10,525 )
Fair value adjustment for natural gas inventory designated as the hedged item
    (1,781 )     14,678  
                 
Total impact on revenue
  $ 6,056     $ 4,153  
                 
The impact on revenue is comprised of the following:
               
Basis ineffectiveness
  $ 853     $ (235 )
Timing ineffectiveness
    5,203       4,388  
                 
    $ 6,056     $ 4,153  
                 
 
                 
    Nine Months Ended June 30  
    2011     2010  
    (In thousands)  
 
Commodity contracts
  $ 4,834     $ 20,296  
Fair value adjustment for natural gas inventory designated as the hedged item
    19,430       26,195  
                 
Total impact on revenue
  $ 24,264     $ 46,491  
                 
The impact on revenue is comprised of the following:
               
Basis ineffectiveness
  $ 1,265     $ (684 )
Timing ineffectiveness
    22,999       47,175  
                 
    $ 24,264     $ 46,491  
                 
 
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 nine months ended June 30, 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 June 30, 2011  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     —     $ (3,907 )   $ (3,907 )
Loss arising from ineffective portion of commodity contracts
                (281 )     (281 )
                                 
Total impact on revenue
                (4,188 )     (4,188 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (614 )                 (614 )
                                 
Total Impact from Cash Flow Hedges
  $ (614 )   $     $ (4,188 )   $ (4,802 )
                                 
 
                                 
    Three Months Ended June 30, 2010  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     —     $ (8,523 )   $ (8,523 )
Loss arising from ineffective portion of commodity contracts
                (350 )     (350 )
                                 
Total impact on revenue
                (8,873 )     (8,873 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (669 )                 (669 )
                                 
Total Impact from Cash Flow Hedges
  $ (669 )   $     $ (8,873 )   $ (9,542 )
                                 
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Nine Months Ended June 30, 2011  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue
                               
for effective portion of commodity contracts
  $     $     $ (25,488 )   $ (25,488 )
Loss arising from ineffective portion of commodity contracts
                (958 )     (958 )
                                 
Total impact on revenue
                (26,446 )     (26,446 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (1,953 )                 (1,953 )
Gain on unwinding of Treasury lock reclassified from AOCI into miscellaneous income
    21,803       6,000             27,803  
                                 
Total Impact from Cash Flow Hedges
  $ 19,850     $ 6,000     $ (26,446 )   $ (596 )
                                 
 
                                 
    Nine Months Ended June 30, 2010  
    Natural
    Regulated
             
    Gas
    Transmission
             
    Distribution     and Storage     Nonregulated     Consolidated  
    (In thousands)  
 
Loss reclassified from AOCI into revenue for effective portion of commodity contracts
  $     $     —     $ (40,196 )   $ (40,196 )
Loss arising from ineffective portion of commodity contracts
                (2,307 )     (2,307 )
                                 
Total impact on revenue
                (42,503 )     (42,503 )
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense
    (2,008 )                 (2,008 )
                                 
Total Impact from Cash Flow Hedges
  $ (2,008 )   $     $ (42,503 )   $ (44,511 )
                                 

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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 nine months ended June 30, 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
    Nine Months Ended
 
    June 30     June 30  
    2011     2010     2011     2010  
    (In thousands)  
 
Increase (decrease) in fair value:
                               
Treasury lock agreements
  $ (8,270 )   $     $ 29,822     $  
Forward commodity contracts
    (2,668 )     2,722       (1,457 )     (19,829 )
Recognition of (gains) losses in earnings due to settlements:
                               
Treasury lock agreements
    386       422       (16,286 )     1,265  
Forward commodity contracts
    2,383       5,199       15,547       24,519  
                                 
Total other comprehensive income (loss) from hedging, net of tax(1)
  $ (8,169 )   $ 8,343     $ 27,626     $ 5,955  
                                 
 
 
(1) Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
 
Deferred gains (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 gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 2011.
 
                         
    Treasury
             
    Lock
    Commodity
       
    Agreements     Contracts     Total  
    (In thousands)  
 
Next twelve months
  $ (1,266 )   $ (3,905 )   $ (5,171 )
Thereafter
    9,334       (4,114 )     5,220  
                         
Total(1)
  $ 8,068     $ (8,019 )   $ 49  
                         
 
 
(1) Utilizing an income tax rate ranging from 37 percent to 39 percent based on 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 June 30, 2011 and 2010 was an increase (decrease) in revenue of $(4.3) million and $0.7 million. For the nine months ended June 30, 2011 and 2010 revenue increased $3.9 million and $13.0 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 nine months ended June 30, 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 June 30, 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
    June 30,
 
    (Level 1)     (Level 2)(1)     (Level 3)     Collateral(2)     2011  
    (In thousands)  
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 2,739     $      —     $     $ 2,739  
Nonregulated segment
    3,696       34,367             (25,006 )     13,057  
                                         
Total financial instruments
    3,696       37,106             (25,006 )     15,796  
Hedged portion of gas stored underground
    86,544                         86,544  
Available-for-sale securities
    44,045                         44,045  
                                         
Total assets
  $ 134,285     $ 37,106     $     $ (25,006 )   $ 146,385  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 5,263     $     $     $ 5,263  
Nonregulated segment
    10,645       38,827             (40,388 )     9,084  
                                         
Total liabilities
  $ 10,645     $ 44,090     $     $ (40,388 )   $ 14,347  
                                         
 
                                         
    Quoted
    Significant
    Significant
             
    Prices in
    Other
    Other
             
    Active
    Observable
    Unobservable
    Netting and
       
    Markets
    Inputs
    Inputs
    Cash
    September 30,
 
    (Level 1)     (Level 2)(1)     (Level 3)     Collateral(3)     2010  
    (In thousands)        
 
Assets:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 2,266     $      —     $     $ 2,266  
Nonregulated segment
    18,544       42,462             (41,760 )     19,246  
                                         
Total financial instruments
    18,544       44,728             (41,760 )     21,512  
Hedged portion of gas stored underground
    57,507                         57,507  
Available-for-sale securities
    41,466                         41,466  
                                         
Total assets
  $ 117,517     $ 44,728     $     $ (41,760 )   $ 120,485  
                                         
Liabilities:
                                       
Financial instruments
                                       
Natural gas distribution segment
  $     $ 51,866     $     $     $ 51,866  
Nonregulated segment
    41,430       31,950             (66,649 )     6,731  
                                         
Total liabilities
  $ 41,430     $ 83,816     $     $ (66,649 )   $ 58,597  
                                         
 
 
(1) Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 June 30, 2011, we had $15.4 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $4.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $11.0 million is classified as current risk management assets.
 
(3) This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2010 we had $24.9 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $12.3 million is classified as current risk management assets.
 
Nonrecurring Fair Value Measurements
 
As discussed in Note 9, during the third quarter we performed an impairment assessment of certain natural gas gathering assets in our nonregulated segment. We used a combination of a market and income approach in a weighted average discounted cash flow analysis that included significant inputs such as our weighted average cost of capital and assumptions regarding future natural gas prices. This is a Level 3 fair value measurement because the inputs used are unobservable. Based on this analysis, we determined the assets to be impaired. We reduced the carrying value of the assets to their estimated fair value of approximately $6 million and recorded a pre-tax noncash impairment loss of approximately $11 million.
 
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 June 30, 2011:
 
         
    June 30,
    2011
    (In thousands)
 
Carrying Amount
  $ 2,212,630  
Fair Value
  $ 2,474,064  
 
5.   Discontinued Operations
 
On May 12, 2011, we entered into a definitive agreement to sell all of our natural gas distribution assets located in Missouri, Illinois and Iowa to Liberty Energy (Midstates) Corporation, an affiliate of Algonquin Power & Utilities Corp. for an all cash price of approximately $124 million. The agreement contains terms and conditions customary for transactions of this type, including typical adjustments to the purchase price at closing, if applicable. The closing of the transaction is subject to the satisfaction of customary conditions including the receipt of applicable regulatory approvals.
 
As required under generally accepted accounting principles, the operating results of our Missouri, Illinois and Iowa operations have been aggregated and reported on the condensed consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations. Additionally, assets and liabilities related to our Missouri, Illinois and Iowa operations are classified as “held for sale” in other current assets and liabilities in our condensed consolidated balance sheets at June 30, 2011. Prior period revenues and expenses associated with these assets have been reclassified into discontinued operations. This reclassification had no impact on previously reported net income.
 
The following table presents statement of income data related to discontinued operations.
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2011     2010     2011     2010  
    (In thousands)  
 
Operating revenues
  $ 11,524     $ 8,952     $ 71,047     $ 62,121  
Purchased gas cost
    5,460       3,390       44,993       39,836  
                                 
Gross profit
    6,064       5,562       26,054       22,285  
Operating expenses
    4,472       3,712       12,919       11,654  
                                 
Operating income
    1,592       1,850       13,135       10,631  
Other nonoperating expense
    (94 )     (75 )     (159 )     (264 )
                                 
Income from discontinued operations before income taxes
    1,498       1,775       12,976       10,367  
Income tax expense
    590       700       5,122       4,094  
                                 
Net income
  $ 908     $ 1,075     $ 7,854     $ 6,273  
                                 
 
The following table presents balance sheet data related to assets held for sale.
 
         
    June 30,
 
    2011  
    (In thousands)  
 
Net plant, property & equipment
  $ 126,375  
Gas stored underground
    5,938  
Other current assets
    431  
Deferred charges and other assets
    197  
         
Assets held for sale
  $ 132,941  
         
Accounts payable and accrued liabilities
  $ 1,808  
Other current liabilities
    5,086  
Regulatory cost of removal obligation
    11,435  
Deferred credits and other liabilities
    810  
         
Liabilities held for sale
  $ 19,139  
         


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
6.   Debt
 
Long-term debt
 
Long-term debt at June 30, 2011 and September 30, 2010 consisted of the following:
 
                 
    June 30,
    September 30,
 
    2011     2010  
    (In thousands)  
 
Unsecured 7.375% Senior Notes, redeemed May 2011
  $     $ 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  
Unsecured 5.50% Senior Notes, due 2041
    400,000        
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
    2,212,630       2,172,696  
Less:
               
Original issue discount on unsecured senior notes and debentures
    (4,090 )     (3,014 )
Current maturities
    (2,434 )     (360,131 )
                 
    $ 2,206,106     $ 1,809,551  
                 
 
As noted above, our unsecured 10% notes will mature in December 2011; accordingly, these have been classified within the current maturities of long-term debt.
 
Our $350 million 7.375% senior notes were paid on their maturity date on May 15, 2011, using funds drawn from commercial paper. We replaced these senior notes on June 10, 2011 with $400 million 5.50% senior notes. The effective interest rate on these notes is 5.381 percent, after giving effect to offering costs and the settlement of the $300 million Treasury locks discussed in Note 3. The majority of the net proceeds of approximately $394 million was used to repay $350 million of outstanding commercial paper. The remainder of the net proceeds was used for general corporate purposes.
 
Short-term debt
 
Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
 
Prior to the third quarter of fiscal 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 June 30, 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 credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.
 
Regulated Operations
 
We fund our regulated operations as needed, primarily through our commercial paper program and two committed revolving credit facilities with third-party lenders that provide approximately $775 million of working capital funding. The first facility is a five-year $750 million unsecured credit facility, expiring May 2016, that 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 credit facility serves as a backup liquidity facility for our commercial paper program. At June 30, 2011, there were no borrowings under this facility nor was there any commercial paper outstanding.
 
The second 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 June 30, 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 June 30, 2011, our total-debt-to-total-capitalization ratio, as defined, was 51 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 or (ii) 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 $173.8 million outstanding under this facility at June 30, 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 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 June 30, 2011, there were no borrowings outstanding under this credit facility. However, at June 30, 2011, AEM letters of credit totaling $24.8 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $125.2 million at June 30, 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 June 30, 2011, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.34 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 June 30, 2011, AEM’s net working capital was $139.5 million and its tangible net worth was $150.9 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 June 30, 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 were able to issue a total of $950 million in debt securities and $350 million in equity securities prior to our $400 million senior notes offering in June 2011. At June 30, 2011, $900 million remains available for issuance. Of this amount, $550 million is available for the issuance of debt securities and $350 million remains available for the issuance of equity securities under the shelf until March 2013.
 
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 Baa1. 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 June 30, 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.
 
7.   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 nine months ended June 30, 2011 and 2010 are calculated as follows:
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2011     2010     2011     2010  
    (In thousands, except per share amounts)  
 
Basic Earnings Per Share from continuing operations
                               
Income (loss) from continuing operations
  $ (1,474 )   $ (4,229 )   $ 197,786     $ 198,029  
Less: Income (loss) from continuing operations allocated to participating securities
    (32 )     (51 )     2,076       2,018  
                                 
Income (loss) from continuing operations available to common shareholders
  $ (1,442 )   $ (4,178 )   $ 195,710     $ 196,011  
                                 
Basic weighted average shares outstanding
    90,127       92,648       90,233       92,513  
                                 
Income (loss) from continuing operations per share — Basic
  $ (0.02 )   $ (0.04 )   $ 2.17     $ 2.12  
                                 
Basic Earnings Per Share from discontinued operations
                               
Income from discontinued operations
  $ 908     $ 1,075     $ 7,854     $ 6,273  
Less: Income from discontinued operations allocated to participating securities
    20       13       82       64  
                                 
Income from discontinued operations available to common shareholders
  $ 888     $ 1,062     $ 7,772     $ 6,209  
                                 
Basic weighted average shares outstanding
    90,127       92,648       90,233       92,513  
                                 
Income from discontinued operations per share — Basic
  $ 0.01     $ 0.01     $ 0.09     $ 0.07  
                                 
Net income (loss) per share — Basic
  $ (0.01 )   $ (0.03 )   $ 2.26     $ 2.19  
                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
    Three Months Ended
    Nine Months Ended
 
    June 30     June 30  
    2011     2010     2011     2010  
    (In thousands, except per share amounts)  
 
Diluted Earnings Per Share from continuing operations
                               
Income (loss) from continuing operations available to common shareholders
  $ (1,442 )   $ (4,178 )   $ 195,710     $ 196,011  
Effect of dilutive stock options and other shares
                4       4  
                                 
Income (loss) from continuing operations available to common shareholders
  $ (1,442 )   $ (4,178 )   $ 195,714     $ 196,015  
                                 
Basic weighted average shares outstanding
    90,127       92,648       90,233       92,513  
Additional dilutive stock options and other shares
                297       343  
                                 
Diluted weighted average shares outstanding
    90,127       92,648       90,530       92,856  
                                 
Income (loss) from continuing operations per share — Diluted
  $ (0.02 )   $ (0.04 )   $ 2.16     $ 2.11  
                                 
Diluted Earnings Per Share from discontinued operations
                               
Income from discontinued operations available to common shareholders
  $ 888     $ 1,062     $ 7,772     $ 6,209  
Effect of dilutive stock options and other shares
    2                    
                                 
Income from discontinued operations available to common shareholders
  $ 890     $ 1,062     $ 7,772     $ 6,209  
                                 
Basic weighted average shares outstanding
    90,127       92,648       90,233       92,513  
Additional dilutive stock options and other shares
                297       343  
                                 
Diluted weighted average shares outstanding
    90,127       92,648       90,530       92,856  
                                 
Income from discontinued operations per share — Diluted
  $ 0.01     $ 0.01     $ 0.09     $ 0.07  
                                 
Net income (loss) per share — Diluted
  $ (0.01 )   $ (0.03 )   $ 2.25     $ 2.18  
                                 
 
There were approximately 288,000 and 333,000 stock options and other shares excluded from the computation of diluted earnings per share for the three months ended June 30, 2011 and 2010 as their inclusion in the computation would be anti-dilutive.
 
There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2011 and 2010 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. 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 quarter of fiscal 2010, the number of outstanding shares used to calculate our earnings per share was

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
reduced by the number of shares received and the $100 million purchase price was recorded as a reduction in shareholders’ equity.
 
8.   Interim Pension and Other Postretirement Benefit Plan Information
 
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended June 30, 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 unchanged.
 
                                 
    Three Months Ended June 30  
    Pension Benefits     Other Benefits  
    2011     2010     2011     2010  
          (In thousands)        
 
Components of net periodic pension cost:
                               
Service cost
  $ 4,257     $ 3,993     $ 3,601     $ 3,360  
Interest cost
    7,055       6,524       3,204       3,018  
Expected return on assets
    (6,285 )     (6,320 )     (681 )     (615 )
Amortization of transition asset
                377       377  
Amortization of prior service cost
    (106 )     (193 )     (362 )     (375 )
Amortization of actuarial loss
    2,748       2,822       87       93  
                                 
Net periodic pension cost
  $ 7,669     $ 6,826     $ 6,226     $ 5,858  
                                 
 
                                 
    Nine Months Ended June 30  
    Pension Benefits     Other Benefits  
    2011     2010     2011     2010  
          (In thousands)        
 
Components of net periodic pension cost:
                               
Service cost
  $ 12,894     $ 11,982     $ 10,803     $ 10,077  
Interest cost
    21,034       19,569       9,610       9,051  
Expected return on assets
    (18,533 )     (18,960 )     (2,045 )     (1,845 )
Amortization of transition asset
                1,133       1,134  
Amortization of prior service cost
    (323 )     (582 )     (1,087 )     (1,125 )
Amortization of actuarial loss
    8,990       8,469       260       282  
Curtailment gain
    (40 )                  
                                 
Net periodic pension cost
  $ 24,022     $ 20,478     $ 18,674     $ 17,574  
                                 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 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 will be required to contribute less than $2 million to our pension plans during fiscal 2011.
 
We contributed $8.7 million to our other post-retirement benefit plans during the nine months ended June 30, 2011. We expect to contribute a total of approximately $12 million to these plans during fiscal 2011.
 
For our Supplemental Executive Retirement Plans, we own equity securities that are classified as available-for-sale securities. These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.
 
Assets for the supplemental plans are held in separate rabbi trusts and comprise the following:
 
                                 
          Gross
    Gross
       
    Amortized
    Unrealized
    Unrealized
       
    Cost     Gain     Loss     Fair Value  
    (In thousands)  
 
As of June 30, 2011:
                               
Domestic equity mutual funds
  $ 27,593     $ 7,627     $      —     $ 35,220  
Foreign equity mutual funds
    4,597       1,416             6,013  
Money market funds
    2,812                   2,812  
                                 
    $ 35,002     $ 9,043     $     $ 44,045  
                                 
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  
                                 
 
9.   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,


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
2010, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 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 (AGC) (collectively, the Atmos Entities), 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 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 will be overturned on appeal.
 
In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009.
 
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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 June 30, 2011, AEH was committed to purchase 104.5 Bcf within one year, 52.4 Bcf within one to three years and 2.4 Bcf after three years under indexed contracts. AEH is committed to purchase 2.6 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $4.13 to $6.36 per Mcf. Purchases under these contracts totaled $356.8 million and $315.6 million for the three months ended June 30, 2011 and 2010 and $1,130.0 million and $1,208.4 million for the nine months ended June 30, 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 June 30, 2011 are as follows (in thousands):
 
         
2011
  $ 52,703  
2012
    307,694  
2013
    112,319  
2014
    86,994  
2015
     
Thereafter
     
         
    $ 559,710  
         
 
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 nine months ended June 30, 2011.
 
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 nine months ended June 30, 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


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 in our Mid-Tex Division 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 25,311 lines for a cost of $34.0 million as of June 30, 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 June 30, 2011, administrative reviews of our rate review mechanisms in our Mid-Tex and West Texas service areas were in progress and a gas reliability infrastructure program (GRIP) filing was in progress in our Atmos Pipeline — Texas service area. In addition, there were other ratemaking activities in progress in our Kentucky/Mid-States, West Texas 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
 
AGC owns and operates the Park City and Shrewsbury gathering systems in Kentucky. The Park City gathering system consists of a 23-mile low pressure pipeline and a nitrogen removal unit that was constructed in 2008. The Shrewsbury production, gathering and processing assets were acquired in 2008 at which time we sold the production assets to a third party. As a result of the sale of the production assets, we obtained a 10-year production payment note under which we are to be paid from future production generated from the assets.
 
As noted above, AGC is involved in an ongoing lawsuit with the Park City gathering system. Due to the lawsuit and a low natural gas price environment, the assets have generated operating losses. As a result of these developments, we performed an impairment assessment of these assets during the third fiscal quarter and determined the assets to be impaired. We reduced the carrying value of the assets to their estimated fair value based on the results of a weighted average discounted cash flow analysis and recorded a pretax noncash impairment loss of $11.0 million.
 
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 evaluated our strategic alternatives and concluded the project’s returns did 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)
 
10.   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 nine months ended June 30, 2011, there were no material changes in our concentration of credit risk.
 
11.   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 nine month periods ended June 30, 2011 and 2010 by segment are presented in the following tables. Prior-year amounts have been restated to reflect the new operating segments.
 
                                         
    Three Months Ended June 30, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 406,817     $ 19,772     $ 417,026     $     $ 843,615  
Intersegment revenues
    214       33,798       74,259       (108,271 )      
                                         
      407,031       53,570       491,285       (108,271 )     843,615  
Purchased gas cost
    206,839             477,880       (107,909 )     576,810  
                                         
Gross profit
    200,192       53,570       13,405       (362 )     266,805  
Operating expenses
                                       
Operation and maintenance
    86,804       18,786       7,437       (362 )     112,665  
Depreciation and amortization
    49,099       6,790       1,043             56,932  
Taxes, other than income
    47,534       3,729       879             52,142  
Asset impairments
                10,988             10,988  
                                         
Total operating expenses
    183,437       29,305       20,347       (362 )     232,727  
                                         
Operating income (loss)
    16,755       24,265       (6,942 )           34,078  
Miscellaneous income (expense)
    (1,153 )     (312 )     168       (133 )     (1,430 )
Interest charges
    28,042       7,653       283       (133 )     35,845  
                                         
Income (loss) from continuing operations before income taxes
    (12,440 )     16,300       (7,057 )           (3,197 )
Income tax expense (benefit)
    (4,311 )     5,748       (3,160 )           (1,723 )
                                         
Income (loss) from continuing operations
    (8,129 )     10,552       (3,897 )           (1,474 )
Income from discontinued operations, net of tax
    908                         908  
                                         
Net income (loss)
  $ (7,221 )   $ 10,552     $ (3,897 )   $     $ (566 )
                                         
Capital expenditures
  $ 121,452     $ 20,239     $ 1,929     $     $ 143,620  
                                         
 


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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Three Months Ended June 30, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 396,097     $ 22,796     $ 342,412     $     $ 761,305  
Intersegment revenues
    222       22,161       84,993       (107,376 )      
                                         
      396,319       44,957       427,405       (107,376 )     761,305  
Purchased gas cost
    204,988             415,634       (106,983 )     513,639  
                                         
Gross profit
    191,331       44,957       11,771       (393 )     247,666  
Operating expenses
                                       
Operation and maintenance
    87,323       16,050       8,579       (393 )     111,559  
Depreciation and amortization
    45,633       5,171       1,136             51,940  
Taxes, other than income
    47,946       3,010       952             51,908  
                                         
Total operating expenses
    180,902       24,231       10,667       (393 )     215,407  
                                         
Operating income
    10,429       20,726       1,104             32,259  
Miscellaneous income (expense)
    (72 )     94       511       (1,331 )     (798 )
Interest charges
    29,019       7,667       1,912       (1,331 )     37,267  
                                         
Income (loss) from continuing operations before income taxes
    (18,662 )     13,153       (297 )           (5,806 )
Income tax expense (benefit)
    (6,685 )     4,688       420             (1,577 )
                                         
Income (loss) from continuing operations
    (11,977 )     8,465       (717 )           (4,229 )
Income from discontinued operations, net of tax
    1,075                         1,075  
                                         
Net income (loss)
  $ (10,902 )   $ 8,465     $ (717 )   $     $ (3,154 )
                                         
Capital expenditures
  $ 106,394     $ 22,964     $ 362     $     $ 129,720  
                                         
 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Nine Months Ended June 30, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,187,256     $ 62,602     $ 1,308,516     $     $ 3,558,374  
Intersegment revenues
    651       94,951       241,940       (337,542 )      
                                         
      2,187,907       157,553       1,550,456       (337,542 )     3,558,374  
Purchased gas cost
    1,317,775             1,491,815       (336,413 )     2,473,177  
                                         
Gross profit
    870,132       157,553       58,641       (1,129 )     1,085,197  
Operating expenses
                                       
Operation and maintenance
    268,299       49,591       24,556       (1,129 )     341,317  
Depreciation and amortization
    145,548       18,387       3,241             167,176  
Taxes, other than income
    132,070       11,395       2,403             145,868  
Asset impairments
                30,270             30,270  
                                         
Total operating expenses
    545,917       79,373       60,470       (1,129 )     684,631  
                                         
Operating income (loss)
    324,215       78,180       (1,829 )           400,566  
Miscellaneous income
    18,305       5,267       764       (290 )     24,046  
Interest charges
    87,344       23,802       1,759       (290 )     112,615  
                                         
Income (loss) from continuing operations before income taxes
    255,176       59,645       (2,824 )           311,997  
Income tax expense (benefit)
    94,323       21,252       (1,364 )           114,211  
                                         
Income (loss) from continuing operations
    160,853       38,393       (1,460 )           197,786  
Income from discontinued operations, net of tax
    7,854                         7,854  
                                         
Net income (loss)
  $ 168,707     $ 38,393     $ (1,460 )   $     $ 205,640  
                                         
Capital expenditures
  $ 340,713     $ 44,796     $ 4,774     $     $ 390,283  
                                         
 

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                         
    Nine Months Ended June 30, 2010  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
Operating revenues from external parties
  $ 2,511,350     $ 64,281     $ 1,365,623     $     $ 3,941,254  
Intersegment revenues
    682       82,717       286,830       (370,229 )      
                                         
      2,512,032       146,998       1,652,453       (370,229 )     3,941,254  
Purchased gas cost
    1,657,412             1,556,746       (369,017 )     2,845,141  
                                         
Gross profit
    854,620       146,998       95,707       (1,212 )     1,096,113  
Operating expenses
                                       
Operation and maintenance
    266,847       53,877       28,946       (1,212 )     348,458  
Depreciation and amortization
    137,580       15,395       3,226             156,201  
Taxes, other than income
    140,234       9,226       3,380             152,840  
                                         
Total operating expenses
    544,661       78,498       35,552       (1,212 )     657,499  
                                         
Operating income
    309,959       68,500       60,155             438,614  
Miscellaneous income (expense)
    1,474       117       1,524       (4,020 )     (905 )
Interest charges
    87,877       23,589       8,035       (4,020 )     115,481  
                                         
Income from continuing operations before income taxes
    223,556       45,028       53,644             322,228  
Income tax expense
    86,552       16,039       21,608             124,199  
                                         
Income from continuing operations
    137,004       28,989       32,036             198,029  
Income from discontinued operations, net of tax
    6,273                         6,273  
                                         
Net income
  $ 143,277     $ 28,989     $ 32,036     $     $ 204,302  
                                         
Capital expenditures
  $ 302,621     $ 56,786     $ 2,942     $     $ 362,349  
                                         

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ATMOS ENERGY CORPORATION
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Balance sheet information at June 30, 2011 and September 30, 2010 by segment is presented to reflect our business structure as of June 30, 2011 in the following tables. Prior-year amounts have been restated accordingly.
 
                                         
    June 30, 2011  
    Natural
    Regulated
                   
    Gas
    Transmission
                   
    Distribution     and Storage     Nonregulated     Eliminations     Consolidated  
    (In thousands)  
 
ASSETS
Property, plant and equipment, net
  $ 4,085,081     $ 771,777     $ 59,193     $     $ 4,916,051  
Investment in subsidiaries
    671,885             (2,096 )     (669,789 )      
Current assets
                                       
Cash and cash equivalents
    39,446             77,983             117,429  
Assets from risk management activities
    1,972             13,041             15,013  
Other current assets
    565,265       15,822       469,576       (193,357 )     857,306  
Intercompany receivables
    505,709                   (505,709 )      
                                         
Total current assets
    1,112,392       15,822       560,600       (699,066 )     989,748  
Intangible assets
                363             363  
Goodwill
    572,262       132,341       34,711             739,314  
Noncurrent assets from risk management activities
    767             16             783  
Deferred charges and other assets
    319,019       16,137       12,055             347,211  
                                         
    $ 6,761,406     $ 936,077     $ 664,842     $ (1,368,855 )   $ 6,993,470  
                                         
 
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
  $ 2,335,824     $ 251,080     $ 420,805     $ (671,885 )   $ 2,335,824  
Long-term debt
    2,205,910             196             2,206,106  
                                         
Total capitalization
    4,541,734       251,080       421,001       (671,885 )     4,541,930  
Current liabilities
                                       
Current maturities of long-term debt
    2,303             131             2,434  
Short-term debt
    173,845                   (173,845 )      
Liabilities from risk management activities
    5,207             2,995             8,202  
Other current liabilities
    419,848       8,862       226,352       (17,416 )     637,646  
Intercompany payables
          503,857       1,852       (505,709 )      
                                         
Total current liabilities
    601,203       512,719       231,330       (696,970 )     648,282  
Deferred income taxes
    798,433       163,540       5,634             967,607  
Noncurrent liabilities from risk management activities
    56             6,089             6,145  
Regulatory cost of removal obligation
    396,201                         396,201  
Deferred credits and other liabilities
    423,779       8,738       788             433,305  
                                         
    $ 6,761,406     $ 936,077     $ 664,842     $ (1,368,855 )   $ 6,993,470  
                                         
 


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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 June 30, 2011, the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2011 and 2010, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 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
August 4, 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 currently located in 12 states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers. After the closing of this transaction, we will operate in nine states.
 
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


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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.
 
As discussed in Note 11, 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 nine months ended June 30, 2011.
 
RESULTS OF OPERATIONS
 
Due to the seasonality of our distribution business, we typically incur a net loss in our fiscal third quarter. For the three months ended June 30, 2011, we reported a net loss of $0.6 million, or $0.01 per diluted share compared to a net loss of $3.2 million, or $0.03 per diluted share in the prior-year quarter. The net loss for the three months ended June 30, 2011 includes noncash, unrealized net gains of $0.1 million, or $0.00 per diluted share compared with net losses of $11.1 million, or $0.12 per diluted share for the three months ended June 30, 2010. The net loss for the third quarter includes the impact of the non-cash impairment charge related to Atmos Gathering System assets, totaling $6.1 million or $0.06 per diluted share.
 
Excluding the impact of unrealized margins and one-time items, diluted earnings per share decreased from income of $0.09 per diluted share in the prior-year quarter to income of $0.05 per diluted share in the current-year quarter, primarily due a decrease in asset optimization margins in our nonregulated segment,


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partially offset by rate increases in our natural gas distribution and regulated transmission and storage segments.
 
During the current quarter, we announced the sale of our natural gas distribution operations in our Missouri, Illinois and Iowa service areas. Due to the pending sales transaction, the results of operations for these three service areas are shown in discontinued operations. During the current-year quarter, discontinued operations generated net income of $0.9 million, or $0.01 per diluted share, compared with net income of $1.1 million, or $0.01 per diluted share in the prior-year quarter. Continuing operations in the current quarter generated a net loss of $1.5 million or $0.02 per diluted share, compared with a net loss of $4.2 million or $0.04 per diluted share from continuing operations in the prior-year quarter.
 
We reported net income of $205.6 million, or $2.25 per diluted share for the nine months ended June 30, 2011, compared with net income of $204.3 million or $2.18 per diluted share in the prior-year period. Income from continuing operations was $197.8 million, or $2.16 per diluted share compared with $198.0 million, or $2.11 per diluted share in the prior-year period. Income from discontinued operations was $7.9 million or $0.09 per diluted share for the year-to-date period, compared with $6.3 million or $0.07 per diluted share in the prior year. Unrealized losses in our nonregulated operations during the current period reduced net income by $1.4 million or $0.02 per diluted share compared with net losses recorded in the prior-year period of $6.2 million, or $0.07 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In the prior year-to-date period, net income included the net positive impact of a state sales tax refund of $4.5 million, or $0.05 per diluted share. In the current year-to-date period, net income includes the net positive impact of several one-time items totaling $6.5 million, or $0.07 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.
 
  •  $30.3 million unfavorable impact related to the non-cash impairment of certain assets in our nonregulated business.
 
  •  $5.0 million favorable impact related to the administrative settlement of various income tax positions.
 
On June 10, 2011 we issued $400 million of 5.50% senior notes. The effective interest rate on these notes is 5.381 percent, after giving effect to the settlement of the $300 million Treasury locks associated with the offering. The majority of the net proceeds of approximately $394 million was used to repay $350 million of outstanding commercial paper. The remainder of the net proceeds was used for general corporate purposes. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the net $12.6 million unrealized gain was recorded as a component of accumulated other comprehensive income and will be recognized as a component of interest expense over the 30-year life of the senior notes.
 
During the nine months ended June 30, 2011, we executed on our strategy to streamline our credit facilities, as follows.
 
  •  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 with an accordion feature that could increase our borrowing capacity to $1.0 billion.
 
  •  In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and certain regulatory restrictions; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million.
 
  •  In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement.


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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 nine months ended June 30, 2011 and 2010:
 
                                 
    Three Months Ended
  Nine Months Ended
    June 30   June 30
    2011   2010   2011   2010
    (In thousands, except per share data)
 
Operating revenues
  $ 843,615     $ 761,305     $ 3,558,374     $ 3,941,254  
Gross profit
    266,805       247,666       1,085,197       1,096,113  
Operating expenses
    232,727       215,407       684,631       657,499  
Operating income
    34,078       32,259       400,566       438,614  
Miscellaneous income (expense)
    (1,430 )     (798 )     24,046       (905 )
Interest charges
    35,845       37,267       112,615       115,481  
Income (loss) from continuing operations before income taxes
    (3,197 )     (5,806 )     311,997       322,228  
Income tax expense (benefit)
    (1,723 )     (1,577 )     114,211       124,199  
Income (loss) from continuing operations
    (1,474 )     (4,229 )     197,786       198,029  
Income (loss) from discontinued operations, net of tax
    908       1,075       7,854       6,273  
Net income (loss)
  $ (566 )   $ (3,154 )   $ 205,640     $ 204,302  
Diluted net income (loss) per share from continuing operations
  $ (0.02 )   $ (0.04 )   $ 2.16     $ 2.11  
Diluted net income per share from discontinued operations
    0.01       0.01       0.09       0.07  
Diluted net income (loss) per share
  $ (0.01 )   $ (0.03 )   $ 2.25     $ 2.18  
 
The following tables segregate our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:
 
                         
    Three Months Ended June 30  
    2011     2010     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 2,423     $ (3,512 )   $ 5,935  
Nonregulated operations
    (3,897 )     (717 )     (3,180 )
                         
Net loss from continuing operations
    (1,474 )     (4,229 )     2,755  
Net income from discontinued operations
    908       1,075       (167 )
                         
Net loss
  $ (566 )   $ (3,154 )   $ 2,588  
                         
Diluted EPS from continuing regulated operations
  $ 0.02     $ (0.03 )   $ 0.05  
Diluted EPS from nonregulated operations
    (0.04 )     (0.01 )     (0.03 )
                         
Diluted EPS from continuing operations
    (0.02 )     (0.04 )     0.02  
Diluted EPS from discontinued operations
    0.01       0.01        
                         
Consolidated diluted EPS
  $ (0.01 )   $ (0.03 )   $ 0.02  
                         
 


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    Nine Months Ended June 30  
    2011     2010     Change  
    (In thousands, except per share data)  
 
Regulated operations
  $ 199,246     $ 165,993     $ 33,253  
Nonregulated operations
    (1,460 )     32,036       (33,496 )
                         
Net income from continuing operations
    197,786       198,029       (243 )
Net income from discontinued operations
    7,854       6,273       1,581  
                         
Net income
  $ 205,640     $ 204,302     $ 1,338  
                         
Diluted EPS from continuing regulated operations
  $ 2.18     $ 1.77     $ 0.41  
Diluted EPS from nonregulated operations
    (0.02 )     0.34       (0.36 )
                         
Diluted EPS from continuing operations
    2.16       2.11       0.05  
Diluted EPS from discontinued operations
    0.09       0.07       0.02  
                         
Consolidated diluted EPS
  $ 2.25     $ 2.18     $ 0.07  
                         
 
Natural Gas Distribution Segment
 
The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
 
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
 
Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 90 percent of our residential and commercial meters in the following states for the following time periods:
 
     
Georgia, Kansas, West Texas
  October — May
Kentucky, Mississippi, Tennessee, Mid-Tex
  November — April
Louisiana
  December — March
Virginia
  January — December
 
Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas includes franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
 
Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.
 
In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa. The results of these operations have been separately

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reported in the following tables and exclude general corporate overhead and interest expense that would normally be allocated to these operations.
 
Three Months Ended June 30, 2011 compared with Three Months Ended June 30, 2010
 
Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2011 and 2010 are presented below.
 
                         
    Three Months Ended June 30  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 200,192     $ 191,331     $ 8,861  
Operating expenses
    183,437       180,902       2,535  
                         
Operating income
    16,755       10,429       6,326  
Miscellaneous expense
    (1,153 )     (72 )     (1,081 )
Interest charges
    28,042       29,019       (977 )
                         
Loss from continuing operations before income taxes
    (12,440 )     (18,662 )     6,222  
Income tax benefit
    (4,311 )     (6,685 )     2,374  
                         
Loss from continuing operations
    (8,129 )     (11,977 )     3,848  
Income from discontinued operations, net of tax
    908       1,075       (167 )
                         
Net loss
  $ (7,221 )   $ (10,902 )   $ 3,681  
                         
Consolidated natural gas distribution sales volumes from continuing operations — MMcf
    37,011       35,613       1,398  
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
    29,955       27,956       1,999  
                         
Consolidated natural gas distribution throughput from continuing operations — MMcf
    66,966       63,569       3,397  
Consolidated natural gas distribution throughput from discontinued operations — MMcf
    2,128       2,359       (231 )
                         
Total consolidated natural gas distribution throughput — MMcf
    69,094       65,928       3,166  
                         
Consolidated natural gas distribution average transportation revenue per Mcf
  $ 0.46     $ 0.46     $  
Consolidated natural gas distribution average cost of gas per Mcf sold
  $ 5.59     $ 5.73     $ (0.14 )


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The following table shows our operating income (loss) from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended June 30, 2011 and 2010. The presentation of our natural gas distribution operating income (loss) is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Three Months Ended June 30  
    2011     2010     Change  
    (In thousands)  
 
Mid-Tex
  $ 759     $ (2,179 )   $ 2,938  
Kentucky/Mid-States
    4,832       3,344       1,488  
Louisiana
    6,779       6,537       242  
West Texas
    605       (104 )     709  
Colorado-Kansas
    3,304       1,623       1,681  
Mississippi
    (615 )     950       (1,565 )
Other
    1,091       258       833  
                         
Total
  $ 16,755     $ 10,429     $ 6,326  
                         
 
The $8.9 million increase in natural gas distribution gross profit was primarily due to the following:
 
  •  $7.5 million net increase in rate adjustments, primarily in the Mid-Tex, Kentucky and Kansas service areas.
 
  •  $1.2 million increase in consolidated throughput due to a five percent increase in consolidated distribution throughput, primarily from higher consumption.
 
  •  $1.5 million decrease due to lower revenue-related taxes, offset by a decrease in taxes, other than income.
 
Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $2.5 million due primarily to a $3.5 million increase in depreciation and amortization expense, partially offset by $1.4 million lower employee expenses.


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Nine Months Ended June 30, 2011 compared with Nine Months Ended June 30, 2010
 
Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2011 and 2010 are presented below.
 
                         
    Nine Months Ended
 
    June 30  
    2011     2010     Change  
    (In thousands, unless otherwise noted)  
 
Gross profit
  $ 870,132     $ 854,620     $ 15,512  
Operating expenses
    545,917       544,661       1,256  
                         
Operating income
    324,215       309,959       14,256  
Miscellaneous income
    18,305       1,474       16,831  
Interest charges
    87,344       87,877       (533 )
                         
Income from continuing operations before income taxes
    255,176       223,556       31,620  
Income tax expense
    94,323       86,552       7,771  
                         
Income from continuing operations
    160,853       137,004       23,849  
Income from discontinued operations, net of tax
    7,854       6,273       1,581  
                         
Net income
  $ 168,707     $ 143,277     $ 25,430  
                         
Consolidated natural gas distribution sales volumes from continuing operations — MMcf
    253,665       285,996       (32,331 )
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf
    99,551       98,442       1,109  
                         
Consolidated natural gas distribution throughput from continuing operations — MMcf
    353,216       384,438       (31,222 )
Consolidated natural gas distribution throughput from discontinued operations — MMcf
    12,723       13,835       (1,112 )
                         
Total consolidated natural gas distribution throughput — MMcf
    365,939       398,273       (32,334 )
                         
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
  $ 5.21     $ 5.77     $ (0.56 )
 
The following table shows our operating income from continuing operations by natural gas distribution division, in order of rate base, for the nine months ended June 30, 2011 and 2010. The presentation of our


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natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
                         
    Nine Months Ended
 
    June 30  
    2011     2010     Change  
    (In thousands)  
 
Mid-Tex
  $ 140,674     $ 128,045     $ 12,629  
Kentucky/Mid-States
    50,522       43,791       6,731  
Louisiana
    44,975       42,775       2,200  
West Texas
    29,405       33,053       (3,648 )
Colorado-Kansas
    26,256       24,071       2,185  
Mississippi
    27,604       28,604       (1,000 )
Other
    4,779       9,620       (4,841 )
                         
Total
  $ 324,215     $ 309,959     $ 14,256  
                         
 
The $15.5 million increase in natural gas distribution gross profit primarily reflects a $35.8 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Kentucky, Kansas and Georgia service areas.
 
These increases were partially offset by:
 
  •  $11.2 million decrease due to an eight 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.
 
  •  $8.5 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 $1.3 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.
 
  •  $8.0 million increase in depreciation and amortization expense.
 
  •  $1.2 million increase in vehicles and equipment expense.
 
These increases were partially offset by:
 
  •  $8.2 million decrease in taxes, other than income, due to lower revenue-related taxes.
 
  •  $6.8 million decrease in employee-related expenses.
 
Net income for this segment for the year-to-date period 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.
 
Recent Ratemaking Developments
 
Significant ratemaking developments that occurred during the nine months ended June 30, 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 $28.1 million resulting from ratemaking activity became effective in the nine months ended June 30, 2011 as summarized below:
 
         
    Annual Increase to
 
Rate Action
  Operating Income  
    (In thousands)  
 
GRIP filings
  $ 919  
Annual rate filing mechanisms
    25,070  
Other rate activity
    2,075  
         
    $ 28,064  
         
 
Additionally, the following ratemaking efforts were in progress during the third quarter of fiscal 2011 but had not been completed as of June 30, 2011.
 
                 
            Operating
 
            Income
 
Division
 
Rate Action
 
Jurisdiction
  Requested  
            (In thousands)  
 
Kentucky/Mid-States
  PRP(1)   Georgia   $ 1,192  
Louisiana
  LGS RSC(2)   Louisiana     4,600  
Mid-Tex
  Rate Review Mechanism (RRM)(3)   Settled Cities(4)     13,152  
West Texas
  Environs Rate Case(5)   Amarillo     78  
    RRM   Lubbock     2,136  
    RRM(6)   WT Cities     2,552  
    Special Contract   Triangle     641  
                 
            $ 24,351  
                 
 
 
(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 $4.1 million effective July 1, 2011, which the Commission accepted.
 
(3) The amount requested represents an increase of $7.7 million under the RRM and $5.5 million related to year two of our steel service line program. In July 2011, the Company and representatives of the Settled Cities agreed to no change in operating income under the RRM and an operating income increase of $5.5 million related to the steel service line program to be implemented on September 1, 2011.
 
(4) Represents 439 of the 440 incorporated cities, or approximately 80 percent of the Mid-Tex Division’s customers, with whom a settlement agreement was reached during the fiscal 2008 second quarter.
 
(5) The Railroad Commission of Texas (RRC) approved the requested increase in operating income on July 26, 2011.
 
(6) On August 1, 2011, the Company and representatives of the West Texas Cities agreed to resolve the 2010 RRM with no change to 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 within our natural gas distribution segment for the first three quarters of fiscal 2011.


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GRIP Filings
 
The Gas Reliability Infrastructure Program (GRIP) in Texas 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. The following table summarizes our GRIP filings with effective dates during the nine months ended June 30, 2011.
 
                         
              Additional
     
        Incremental
    Annual
     
    Calendar
  Net Utility Plant
    Operating
    Effective
Division
  Year   Investment     Income     Date
        (In thousands)     (In thousands)      
 
2011 GRIP:
                       
West Texas/Lubbock & WT Cities Environs
  2010   $ 17,677     $ 343     06/01/2011
Mid-Tex/Environs
  2010     107,840       576     06/27/2011
                         
Total 2011 GRIP
      $ 125,517     $ 919      
                         
 
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 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 nine months ended June 30, 2011.
 
                         
            Additional
       
            Annual
       
        Test Year
  Operating