Atmos Energy (ATO) 10-Q 2011 Q3 Quarterly report

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 ofRegulation 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” inRule 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 inRule 12b-2 of the Exchange Act) Yeso      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

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

1

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

2

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

3

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

4

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

5

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 regulationand/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:

•  thenatural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,

•  theregulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and

•  thenonregulated 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 onForm 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 toForm 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report onForm 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.

6

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 onForm 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.

7

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.

8

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 onForm 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.

9

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, primarilyover-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 the2010-2011 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 transportationand/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

10

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 variousover-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 the30-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 the30-year life of the senior notes.

Additionally, our original fiscal 2011 financing plans included the issuance of $250 million of30-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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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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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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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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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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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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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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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 onForm 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 onForm 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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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 asover-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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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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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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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 million180-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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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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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 stockand/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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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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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 noout-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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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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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 asavailable-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 theother-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 onForm 10-K for the fiscal year ended September 30,

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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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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 onForm 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 onForm 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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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 onForm 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 inManagement’s Discussion and Analysis — Recent Ratemaking DevelopmentsandRegulated 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 a23-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 a10-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 onForm 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.

31

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 onForm 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:

•  Thenatural gas distribution segment, which included our regulated natural gas distribution and related sales operations.

•  Theregulated transmission and storage segment, which included the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division.

•  Thenatural gas marketing segment, which included a variety of nonregulated natural gas management services.

•  Thepipeline, 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:

•  Thenatural gas distribution segment, remains unchanged and includes our regulated natural gas distribution and related sales operations.

•  Theregulated transmission and storage segment, remains unchanged and includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division.

•  Thenonregulated 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 onForm 10-K for the fiscal year ended September 30, 2010. We evaluate performance based on net income or loss of the respective operating units.

32

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

33

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

34

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

35

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

36

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

37

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

38

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

39

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 onForm 10-Q and Management’s Discussion and Analysis in our Annual Report onForm 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 onForm 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

40

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:

•  thenatural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,

•  theregulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and

•  thenonregulated 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 onForm 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,

41

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 theyear-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 prioryear-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 currentyear-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 the30-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 the30-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 million364-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 million364-day revolving credit agreement with a $200 million180-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

47

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 theyear-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		Effective
Division	Jurisdiction	Ended	Income		Date
			(In thousands)
2011 Filings:
Mid-Tex	Settled Cities	12/31/2009	$	23,122		10/01/2010
Louisiana	TransLa	09/30/2010		350		04/01/2011
Mid-Tex	Dallas	12/31/2010		1,598		07/01/2011
Total 2011 Filings			$	25,070

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the nine months ended June 30, 2011:

			Additional
			Annual
			Operating		Effective
Division	Jurisdiction	Rate Activity	Income		Date
			(In thousands)
2011 Other Rate Activity:
Kentucky/Mid-States	Georgia	PRP Surcharge	$	764	10/01/2010
Colorado-Kansas	Colorado	AMI(1)		349	12/01/2010
Colorado-Kansas	Kansas	Ad Valorem(2)		685	01/01/2011
Kentucky/Mid-States	Missouri	ISRS(3)		277	02/14/2011
Total 2011 Other Rate Activity			$	2,075

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(1)	Automated Meter Infrastructure (AMI) relates to a pilot program in the Weld County area of the Company’s service area.
(2)	The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in the Company’s base rates.
(3)	Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

Regulated Transmission and Storage Segment

Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking and lending arrangements and sales of inventory on hand.

Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Three Months Ended June 30, 2011 compared with Three Months Ended June 30, 2010

Financial and operational highlights for our regulated transmission and storage 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)
Mid-Tex transportation	$	32,098		$	21,908	$	10,190
Third-party transportation		16,518			17,521		(1,003	)
Storage and park and lend services		1,802			2,646		(844	)
Other		3,152			2,882		270
Gross profit		53,570			44,957		8,613
Operating expenses		29,305			24,231		5,074
Operating income		24,265			20,726		3,539
Miscellaneous income (expense)		(312	)		94		(406	)
Interest charges		7,653			7,667		(14	)
Income before income taxes		16,300			13,153		3,147
Income tax expense		5,748			4,688		1,060
Net income	$	10,552		$	8,465	$	2,087
Gross pipeline transportation volumes — MMcf		141,294			127,861		13,433
Consolidated pipeline transportation volumes — MMcf		112,564			100,770		11,794

On April 18, 2011, the Railroad Commission of Texas (RRC) issued an order in the rate case of Atmos Pipeline — Texas (APT) that was originally filed in September 2010. The RRC approved an annual operating

51

income increase of $20.4 million as well as the following major provisions that went into effect with bills rendered on and after May 1, 2011:

•  Authorized return on equity of 11.8 percent.

•  A capital structure of 49.5 percent debt/50.5 percent equity

•  Approval of a rate base of $807.7 million, compared to the $417.1 million rate base from the prior rate case.

•  An annual adjustment mechanism, which was approved for a three-year pilot program, that will adjust regulated rates up or down by 75 percent of the difference between APT’s non-regulated annual revenue and a pre-defined base credit.

•  Approval of a straight fixed variable rate design, under which all fixed costs associated with transportation and storage services are recovered through monthly customer charges.

The $8.6 million increase in regulated transmission and storage gross profit was attributable primarily to a net $8.7 million increase as a result of this rate case.

Operating expenses increased $5.1 million primarily due to the following:

•  $3.2 million due to higher levels of pipeline maintenance activities.

•  $1.6 million due to higher depreciation expense.

At June 30, 2011, a GRIP filing was in progress with the RRC in which $12.6 million of additional annual operating income was requested. On July 26, 2011, the RRC approved the GRIP filing.

Nine Months Ended June 30, 2011 compared with Nine Months Ended June 30, 2010

Financial and operational highlights for our regulated transmission and storage 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)
Mid-Tex transportation	$	92,729	$	81,833	$	10,896
Third-party transportation		49,841		49,098		743
Storage and park and lend services		6,191		7,924		(1,733	)
Other		8,792		8,143		649
Gross profit		157,553		146,998		10,555
Operating expenses		79,373		78,498		875
Operating income		78,180		68,500		9,680
Miscellaneous income		5,267		117		5,150
Interest charges		23,802		23,589		213
Income before income taxes		59,645		45,028		14,617
Income tax expense		21,252		16,039		5,213
Net income	$	38,393	$	28,989	$	9,404
Gross pipeline transportation volumes — MMcf		468,943		478,075		(9,132	)
Consolidated pipeline transportation volumes — MMcf		305,898		295,126		10,772

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The $10.6 million increase in regulated transmission and storage gross profit was attributable primarily due to the following:

•  $8.7 million net increase as a result of the rate case that was finalized and became effective in May 2011.

•  $6.2 million increase associated with our GRIP filings.

These increases were partially offset by the following:

•  $2.8 million decrease due to a decline in throughput to our Mid-Tex Division.

•  $2.4 million decrease due to decreased transportation fees.

Operating expenses increased $0.9 million primarily due to the following:

•  $3.0 million increase due to higher depreciation expense.

•  $1.8 million increase due to higher ad valorem taxes.

These increases were partially offset by a $1.3 million decrease related to lower levels of pipeline maintenance activities.

Miscellaneous income includes a $6.0 million gain recognized in March 2011 as a result of unwinding two Treasury locks.

Nonregulated Segment

Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.

AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. In addition, AEH utilizes proprietary and customer-owned transportation and storage assets to provide various delivered gas services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, AEH’s gas delivery and related services margins arise from the types of commercial transactions we have structured with our customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.

AEH’s storage and transportation margins arise from (i) utilizing its proprietary21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods.

AEH also seeks to enhance its gross profit margin by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity it owns or controls in our natural gas distribution and by its subsidiaries. We attempt to meet these objectives by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEH has access and selling financial instruments at advantageous prices to lock in a gross profit margin.

AEH continually manages its net physical position to attempt to increase the future economic profit that was created when the original transaction was executed. Therefore, AEH may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market

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conditions. If AEH elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to offset the original financial instruments. If AEH elects to defer the withdrawal of gas, it will execute new financial instruments to correspond to the revised withdrawal schedule and allow the original financial instrument to settle as contracted.

We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The hedged natural gas inventory is marked to market at the end of each month based on the Gas Daily index with changes in fair value recognized as unrealized gains and losses in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.

AEH also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.

Due to the nature of these operations, natural gas prices and differences in natural gas prices between the various markets that we serve (commonly referred to as basis differentials), have a significant impact on our nonregulated businesses. Within our delivered gas activities, basis differentials impact our ability to create value from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Further, higher natural gas prices may adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Higher gas prices, as well as competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.

Volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility often has a significant impact on the spreads between the market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. Volatility could also impact the basis differentials we capture in our delivered gas activities. However, increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.

Three Months Ended June 30, 2011 compared with Three Months Ended June 30, 2010

Financial and operational highlights for our nonregulated segment for the three months ended June 30, 2011 and 2010 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers, margins earned from storage and transportation services and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.

Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the

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unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

	Three Months Ended
	June 30
	2011			2010			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	11,631		$	12,550		$	(919	)
Storage and transportation services		4,042			3,319			723
Other		1,177			1,345			(168	)
		16,850			17,214			(364	)
Asset optimization(1)		(3,623	)		9,303			(12,926	)
Total realized margins		13,227			26,517			(13,290	)
Unrealized margins		178			(14,746	)		14,924
Gross profit		13,405			11,771			1,634
Operating expenses, excluding asset impairment		9,359			10,667			(1,308	)
Asset impairment		10,988			—			10,988
Operating income (loss)		(6,942	)		1,104			(8,046	)
Miscellaneous income		168			511			(343	)
Interest charges		283			1,912			(1,629	)
Loss before income taxes		(7,057	)		(297	)		(6,760	)
Income tax expense (benefit)		(3,160	)		420			(3,580	)
Net loss	$	(3,897	)	$	(717	)	$	(3,180	)
Gross nonregulated delivered gas sales volumes — MMcf		104,658			91,854			12,804
Consolidated nonregulated delivered gas sales volumes — MMcf		88,382			75,014			13,368
Net physical position (Bcf)		16.7			20.1			(3.4	)

⁽¹⁾ Net of storage fees of $3.8 million and $3.3 million.

Realized margins for gas delivery, storage and transportation services and other services were $16.9 million during the three months ended June 30, 2011 compared with $17.2 million for the prior-year quarter. The decrease primarily reflects a decrease of $0.03/Mcf for consolidated delivered gas margins in the current quarter, partially offset by an 18 percent increase in consolidated delivered gas volumes due to new customers in the power generation market.

The $12.9 million decrease in realized asset optimization margins from the prior-year quarter reflects the impact of continued weak natural gas market fundamentals, which have reduced price volatility and compressed spot to forward spread values resulting in less favorable trading opportunities. As a result, during the current quarter, AEH captured smaller spread values from its asset optimization activities. This contrasts to the prior-year quarter, when AEH recognized higher spread values that it had captured from rolling positions.

Weak market fundamentals have also reduced the demand and fees paid for storage. During the quarter, AEH started to capitalize on falling storage demand fees by replacing expiring storage contracts with new contracts with lower storage demand fees and allowing non-strategic contracts to expire without renewing them. This should improve AEH’s ability to realize gains from its asset optimization activities in future periods.

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The decrease in realized asset optimization margins was offset by a $14.9 million increase in unrealized margins that reflects thequarter-over-quarter timing of realized margins coupled with lower natural gas price volatility.

Operating expenses decreased $1.3 million primarily due to lower employee costs.

Asset impairment reflects the $11.0 million pre-tax impairment of certain natural gas gathering assets recorded in the current quarter.

Interest charges decreased $1.6 million primarily due to a decrease in intercompany borrowings.

Nine Months Ended June 30, 2011 compared with Nine Months Ended June 30, 2010

Financial and operational highlights for our natural gas marketing 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)
Realized margins
Gas delivery and related services	$	46,842		$	45,763		$	1,079
Storage and transportation services		10,913			9,746			1,167
Other		3,956			3,907			49
		61,711			59,416			2,295
Asset optimization(1)		(344	)		46,694			(47,038	)
Total realized margins		61,367			106,110			(44,743	)
Unrealized margins		(2,726	)		(10,403	)		7,677
Gross profit		58,641			95,707			(37,066	)
Operating expenses, excluding asset impairment		30,200			35,552			(5,352	)
Asset impairment		30,270			—			30,270
Operating income (loss)		(1,829	)		60,155			(61,984	)
Miscellaneous income		764			1,524			(760	)
Interest charges		1,759			8,035			(6,276	)
Income (loss) before income taxes		(2,824	)		53,644			(56,468	)
Income tax expense (benefit)		(1,364	)		21,608			(22,972	)
Net income (loss)	$	(1,460	)	$	32,036		$	(33,496	)
Gross nonregulated delivered gas sales volumes — MMcf		339,747			317,992			21,755
Consolidated nonregulated delivered gas sales
volumes — MMcf		290,486			267,136			23,350
Net physical position (Bcf)		16.7			20.1			(3.4	)

⁽¹⁾ Net of storage fees of $10.7 million and $10.0 million.

Realized margins for gas delivery, storage and transportation services and other services were $61.7 million during the nine months ended June 30, 2011 compared with $59.4 million for the prior-year period. The increase primarily reflects a nine percent increase in consolidated delivered gas sales volumes due to new customers in the power generation market and a $1.2 million increase in margins from storage and transportation services, attributable to new drilling projects in the Barnett Shale area.

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The $47.0 million decrease in realized asset optimization margins from the prior-year period primarily reflects greater intramonth trading gains realized in the prior-year period from more favorable trading opportunities in the daily cash market, combined with lower realized gains in the current-year period due to continued weak natural gas market fundamentals.

Unrealized margins increased $7.7 million in the current period compared to the prior-year period primarily due to the timing ofyear-over-year realized margins.

Operating expenses decreased $5.4 million primarily due to lower employee expenses.

Asset impairment includes the aforementioned $11.0 million pre-tax impairment charge related to certain natural gas gathering assets. In addition, an asset impairment charge of $19.3 million was recorded in March 2011 related to our investment in Fort Necessity. As we previously discussed in our Annual Report onForm 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. As such, we recorded a pretax noncash impairment to write off substantially all of our investment in the project during the second quarter of fiscal 2011.

Interest charges decreased $6.3 million primarily due to a decrease in intercompany borrowings.

Asset Optimization Activities

AEH monitors the impact of its asset optimization efforts by estimating the gross profit, before related fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic value, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement and related fees is referred to as the potential gross profit.

We define potential gross profit as the change in AEH’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include other operating expenses and associated income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic value or the potential gross profit will be fully realized in the future.

We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone. Because there is no assurance that the economic value or potential gross profit will be realized in the future, corresponding future GAAP amounts are not available.

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The following table presents AEH’s economic value and its potential gross profit (loss) at June 30, 2011 and 2010.

	June 30
	2011			2010
	(In millions, unless otherwise noted)
Economic value	$	(7.7	)	$	(8.5	)
Associated unrealized losses		8.3			16.5
Subtotal		0.6			8.0
Related fees(1)		(21.4	)		(13.8	)
Potential gross profit (loss)	$	(20.8	)	$	(5.8	)
Net physical position (Bcf)		16.7			20.1

⁽¹⁾ Related fees represent the contractual costs to acquire the storage capacity utilized in our nonregulated segment’s asset optimization activities. The fees primarily consist of demand fees and contractual obligations to sell gas below market index prices in exchange for the right to manage and optimize third party storage assets for the positions we have entered into as of June 30, 2011 and 2010.

During the nine months ended June 30, 2011, our nonregulated segment’s economic value decreased from ($7.5) million, or ($0.48)/Mcf at September 30, 2010 to ($7.7) million, or ($0.46)/Mcf. This compares favorably to economic value at June 30, 2010 of ($8.5) million, or ($0.42)/Mcf.

For the nine months ended June 30, 2011, the decrease in our economic value was primarily the result of withdrawing physical gas below our overall weighted average cost of gas while settling financial instruments with higher average prices.

The economic value is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEH actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic value or the potential gross profit calculated as of June 30, 2011 will be fully realized in the future nor can we predict in what time periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted.

Liquidity and Capital Resources

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.

We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require. During fiscal 2011, we have been executing our strategy of consolidating our short-term facilities used for our regulated operations into a single line of credit, including the following.

•  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 million364-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

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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 million364-day revolving credit agreement with a $200 million180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement.

As a result of these changes, we now have $975 million of availability from our commercial paper program and three committed revolving credit facilities with third parties.

Our $350 million 7.375% senior notes were paid on their maturity date on May 15, 2011 using funds drawn from commercial paper. We refinanced this debt on a long-term basis through the issuance of $400 million 5.50%30-year unsecured senior notes on June 10, 2011. On September 30, 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost of financing the anticipated issuances of senior notes. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the30-year Treasury lock rates between inception of the Treasury lock and settlement. 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. 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.

Additionally, we had planned to issue $250 million of30-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 agreements were unwound. A pretax cash gain of approximately $28 million was recorded in March 2011.

We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2011.

Cash Flows

Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating, investing and financing activities for the nine months ended June 30, 2011 and 2010 are presented below.

	Nine Months Ended June 30
	2011			2010			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	519,562		$	594,564		$	(75,002	)
Investing activities		(393,656	)		(362,787	)		(30,869	)
Financing activities		(140,429	)		(162,597	)		22,168
Change in cash and cash equivalents		(14,523	)		69,180			(83,703	)
Cash and cash equivalents at beginning of period		131,952			111,203			20,749
Cash and cash equivalents at end of period	$	117,429		$	180,383		$	(62,954	)

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Cash flows from operating activities

Period-over-period changes in our operating cash flows are primarily attributable to changes in net income and working capital changes, particularly within our natural gas distribution segment resulting from the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the nine months ended June 30, 2011, we generated operating cash flow of $519.6 million from operating activities compared with $594.6 million for the nine months ended June 30, 2010. The $75.0 million decrease in operating cash flows primarily reflects the timing of gas cost recoveries under our purchased gas cost mechanisms and other net working capital changes.

Cash flows from investing activities

In recent years, a substantial portion of our cash resources has been used to fund growth projects, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, rate designs in our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

Capital expenditures for fiscal 2011 are expected to range from $610 million to $625 million. For the nine months ended June 30, 2011, capital expenditures were $390.3 million compared with $362.3 million for the nine months ended June 30, 2010. The $28.0 million increase in capital expenditures primarily reflects spending for the steel service line replacement program in the Mid-Tex Division and the development of a new customer service system in the current year, partially offset by the costs incurred in the prior fiscal year to relocate the company’s information technology data center.

Cash flows from financing activities

For the nine months ended June 30, 2011, our financing activities used $140.4 million of cash compared with $162.6 million of cash used in the prior-year period, primarily due to higher proceeds from debt issuances in the current year, including the following:

•  $394.6 million net cash proceeds received in June 2011 related to the issuance of $400 million 5.50% senior notes due 2041.

•  $20.1 million cash received in June 2011 related to the settlement of three Treasury locks associated with the $400 million 5.50% senior notes offering.

•  $27.8 million cash received in March 2011 related to the unwinding of two Treasury locks.

These higher proceeds were partially offset by higher repayment activity, including the following:

•  $360.1 million for scheduled long-term debt repayments. In the current-year period, $360.1 million of long-term debt was repaid, including our $350 million 7.375% senior notes that were paid on their maturity date on May 15, 2011. In the prior-year period, $0.1 million of long-term debt was repaid.

•  $56.1 million for short-term debt repayments. In the current-year period, $132.1 million of short-term debt was repaid, compared with $76.0 million in the prior-year period.

•  $4.1 million for the repurchase of equity awards. In the current-year period, we repurchased $5.3 million equity awards, compared with $1.2 million in the prior-year period.

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The following table summarizes our share issuances for the nine months ended June 30, 2011 and 2010.

	Nine Months Ended
	June 30
	2011		2010
Shares issued:
Direct Stock Purchase Plan		—		103,529
Retirement Savings Plan and Trust		—		79,722
1998 Long-Term Incentive Plan		663,555		375,039
Outside DirectorsStock-for-Fee Plan		1,801		2,689
Total shares issued		665,356		560,979

Theyear-over-year change in the number of shares issued primarily reflects an increased number of shares issued under our 1998 Long-Term Incentive Plan due to the exercise of stock options during the current year. This increase was partially offset by the fact that we are purchasing shares in the open market rather than issuing new shares for the Direct Stock Purchase Plan and the Retirement Savings Plan. During the nine months ended June 30, 2011, we cancelled and retired 169,269 shares attributable to federal withholdings on equity awards and repurchased and retired 375,468 shares attributable to our accelerated share repurchase agreement, which are not included in the table above.

Share Repurchase Agreement

On, July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman Sachs & Co. under which we repurchased $100 million of our outstanding common stock in order to offset stock grants made under our various employee and director incentive compensation plans.

We paid $100 million to Goldman Sachs & Co. on July 7, 2010 for shares of Atmos Energy common stock in a share forward transaction and received 2,958,580 shares. 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 reduced by the number of shares received and the $100 million purchase price was recorded as a reduction in shareholders’ equity.

Credit Facilities

Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements. However, our short-term borrowings reach their highest levels in the winter months.

We finance our short-term borrowing requirements through a combination of a $750.0 million commercial paper program and three committed revolving credit facilities with third-party lenders that provided approximately $1.0 billion of working capital funding. As of June 30, 2011, the amount available to us under our credit facilities, net of outstanding letters of credit, was $900.2 million. These facilities are described in further detail in Note 6 to the unaudited condensed consolidated financial statements.

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 stockand/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

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were able to issue a total of $950 million in debt securities and $350 million in equity securities. At June 30, 2011, $900 million was 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.

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). On May 11, 2011, Moody’s upgraded our senior unsecured debt rating to Baa1 from Baa2, with a ratings outlook of stable, citing steady rate increases, improving credit metrics and a strategic focus on lower risk regulated activities as reasons for the upgrade. On June 2, 2011, Fitch upgraded our senior unsecured debt rating to A- from BBB+, with a ratings outlook of stable, citing a constructive regulatory environment, strategic focus on lower risk regulated activities and the geographic diversity of our regulated operations as key rating factors. As of June 30, 2011, S&P maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

	S&P		Moody’s		Fitch
Unsecured senior long-term debt		BBB+		Baa1		A-
Commercial paper		A-2		P-2		F-2

A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB-for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of June 30, 2011. Our debt covenants are described in greater detail in Note 6 to the unaudited condensed consolidated financial statements.

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Capitalization

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2011, September 30, 2010 and June 30, 2010:

	June 30, 2011				September 30, 2010				June 30, 2010
	(In thousands, except percentages)
Short-term debt	$	—	—		$	126,100	2.8	%	$	—	—
Long-term debt		2,208,540	48.6	%		2,169,682	48.5	%		2,169,677	48.4	%
Shareholders’ equity		2,335,824	51.4	%		2,178,348	48.7	%		2,313,730	51.6	%
Total	$	4,544,364	100.0	%	$	4,474,130	100.0	%	$	4,483,407	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 48.6 percent at June 30, 2011, 51.3 percent at September 30, 2010 and 48.4 percent at June 30, 2010. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 9 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2011.

Risk Management Activities

We conduct risk management activities through our natural gas distribution and nonregulated segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.

In our nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures,over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.

The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and nine months ended June 30, 2011 and 2010:

	Three Months Ended						Nine Months Ended
	June 30						June 30
	2011			2010			2011			2010
	(In thousands)
Fair value of contracts at beginning of period	$	30,533		$	(21,735	)	$	(49,600	)	$	(14,166	)
Contracts realized/settled		(13	)		(20	)		(51,058	)		(34,438	)
Fair value of new contracts		1,801			182			2,872			(2,054	)
Other changes in value		(34,845	)		1,183			95,262			30,268
Fair value of contracts at end of period	$	(2,524	)	$	(20,390	)	$	(2,524	)	$	(20,390	)

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The fair value of our natural gas distribution segment’s financial instruments at June 30, 2011 is presented below by time period and fair value source:

	Fair Value of Contracts at June 30, 2011
	Maturity in Years
	Less							Greater		Total Fair
Source of Fair Value	Than 1			1-3		4-5		Than 5		Value
	(In thousands)
Prices actively quoted	$	(3,235	)	$	711	$	—	$	—	$	(2,524	)
Prices based on models and other valuation methods		—			—		—		—		—
Total Fair Value	$	(3,235	)	$	711	$	—	$	—	$	(2,524	)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments 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)
Fair value of contracts at beginning of period	$	(12,942	)	$	14,227		$	(12,374	)	$	26,698
Contracts realized/settled		3,357			(8,100	)		3,282			(32,342	)
Fair value of new contracts		—			—			—			—
Other changes in value		(1,824	)		(8,337	)		(2,317	)		3,434
Fair value of contracts at end of period		(11,409	)		(2,210	)		(11,409	)		(2,210	)
Netting of cash collateral		15,382			18,017			15,382			18,017
Cash collateral and fair value of contracts at period end	$	3,973		$	15,807		$	3,973		$	15,807

The fair value of our nonregulated segment’s financial instruments at June 30, 2011 is presented below by time period and fair value source:

	Fair Value of Contracts at June 30, 2011
	Maturity in Years
	Less								Greater		Total Fair
Source of Fair Value	Than 1			1-3			4-5		Than 5		Value
	(In thousands)
Prices actively quoted	$	(5,336	)	$	(6,097	)	$	24	$	—	$	(11,409	)
Prices based on models and other valuation methods		—			—			—		—		—
Total Fair Value	$	(5,336	)	$	(6,097	)	$	24	$	—	$	(11,409	)

Pension and Postretirement Benefits Obligations

For the nine months ended June 30, 2011 and 2010, our total net periodic pension and other benefits costs were $42.7 million and $38.1 million. Those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 2011 costs were determined using a September 30, 2010 measurement date. As of September 30, 2010, interest and corporate bond rates utilized to determine our discount rates, were significantly higher than the interest and corporate bond rates as of September 30, 2009, the measurement date for our fiscal 2010 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2011 pension and benefit costs to 5.39 percent. We maintained the expected return on our pension plan assets

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at 8.25 percent, despite the recent decline in the financial markets as we believe this rate reflects the average rate of expected earnings on plan assets that will fund our projected benefit obligation. Accordingly, our fiscal 2011 pension and postretirement medical costs for the nine months ended June 30, 2011 were significantly higher than the prior-year period.

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. An immaterial curtailment gain was recorded in our second fiscal quarter. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective January 1, 2011 to 5.68 percent, which will reduce our net periodic pension cost by approximately $1.8 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.

In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2011. Based upon this valuation, we expect we will be required to contribute less than $2 million to our pension plans by September 15, 2011. The need for this funding reflects the decline in the fair value of the plans’ assets resulting from the unfavorable market conditions experienced during 2008 and 2009. This contribution will increase the level of our plan assets to achieve a desirable PPA funding threshold. With respect to our postretirement medical plans, we anticipate contributing a total of approximately $12 million to these plans during fiscal 2011.

The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plan are subject to change, depending upon the actuarial value of plan assets and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts will be determined by actual investment returns, changes in interest rates, values of assets in the plan and changes in the demographic composition of the participants in the plan.

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OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage and nonregulated segments for the three and nine month periods ended June 30, 2011 and 2010.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations

	Three Months Ended				Nine Months Ended
	June 30				June 30
	2011		2010		2011		2010
METERS IN SERVICE, end of period
Residential		2,845,554		2,841,716		2,845,554		2,841,716
Commercial		258,448		262,349		258,448		262,349
Industrial		2,319		2,359		2,319		2,359
Public authority and other		10,206		10,117		10,206		10,117
Total meters		3,116,527		3,116,541		3,116,527		3,116,541
INVENTORY STORAGE BALANCE — Bcf		36.3		32.8		36.3		32.8
SALES VOLUMES — MMcf(1)
Gas sales volumes
Residential		17,077		17,060		150,154		173,787
Commercial		14,149		13,690		79,632		88,260
Industrial		3,922		3,490		15,115		15,236
Public authority and other		1,863		1,373		8,764		8,713
Total gas sales volumes		37,011		35,613		253,665		285,996
Transportation volumes		31,036		28,678		102,824		101,449
Total throughput		68,047		64,291		356,489		387,445
OPERATING REVENUES (000’s)(1)
Gas sales revenues
Residential	$	232,725	$	230,333	$	1,379,223	$	1,602,510
Commercial		118,916		116,933		593,860		685,996
Industrial		22,525		19,108		85,641		90,468
Public authority and other		12,013		9,125		58,096		61,595
Total gas sales revenues		386,179		375,499		2,116,820		2,440,569
Transportation revenues		13,946		13,303		47,364		46,276
Other gas revenues		6,906		7,517		23,723		25,187
Total operating revenues	$	407,031	$	396,319	$	2,187,907	$	2,512,032
Average transportation revenue per Mcf	$	0.45	$	0.46	$	0.46	$	0.46
Average cost of gas per Mcf sold	$	5.59	$	5.76	$	5.19	$	5.80

See footnote following these tables.

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Natural Gas Distribution Sales and Statistical Data — Discontinued Operations

	Three Months Ended				Nine Months Ended
	June 30				June 30
	2011		2010		2011		2010
Meters in service, end of period		83,109		83,094		83,109		83,094
Inventory storage balance — Bcf		2.0		1.9		2.0		1.9
Sales volumes — MMcf
Total gas sales volumes		936		726		7,910		8,187
Transportation volumes		1,192		1,633		4,813		5,648
Total throughput		2,128		2,359		12,723		13,835
Operating revenues (000’s)	$	11,524	$	8,952	$	71,047	$	62,121

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data

	Three Months Ended				Nine Months Ended
	June 30				June 30
	2011		2010		2011		2010
CUSTOMERS, end of period
Industrial		764		732		764		732
Municipal		61		61		61		61
Other		511		507		511		507
Total		1,336		1,300		1,336		1,300
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf		21.4		21.9		21.4		21.9
REGULATED TRANSMISSION AND
STORAGE VOLUMES — MMcf(1)		141,294		127,861		468,943		478,075
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf(1)		104,658		91,854		339,747		317,992
OPERATING REVENUES (000’s)(1)
Regulated transmission and storage	$	53,570	$	44,957	$	157,553	$	146,998
Nonregulated		491,285		427,405		1,550,456		1,652,453
Total operating revenues	$	544,855	$	472,362	$	1,708,009	$	1,799,451

Note to preceding tables:

⁽¹⁾ Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

RECENT ACCOUNTING DEVELOPMENTS

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.

Item 3.   Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report onForm 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 quantitative and qualitative disclosures about market risk.

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Item 4.   Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined inRules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined inRules 13a-15(f) and15d-15(f) under the Exchange Act) during the third quarter of the fiscal year ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.   Legal Proceedings

During the nine months ended June 30, 2011, except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 12 to our Annual Report onForm 10-K for the fiscal year ended September 30, 2010. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

Item 6.   Exhibits

A list of exhibits required by Item 601 ofRegulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atmos Energy Corporation

       (Registrant)

By:  /s/  Fred E. Meisenheimer

Fred E. Meisenheimer

Senior Vice President and Chief

Financial Officer

(Duly authorized signatory)

Date: August 4, 2011

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EXHIBITS INDEX

Item 6

				Page Number or
Exhibit				Incorporation by
Number			Description	Reference to
	12		Computation of ratio of earnings to fixed charges
	15		Letter regarding unaudited interim financial information
	31		Rule 13a-14(a)/15d-14(a) Certifications
	32		Section 1350 Certifications*
	101	.INS	XBRL Instance Document**
	101	.SCH	XBRL Taxonomy Extension Schema**
	101	.CAL	XBRL Taxonomy Extension Calculation Linkbase**
	101	.DEF	XBRL Taxonomy Extension Definition Linkbase**
	101	.LAB	XBRL Taxonomy Extension Labels Linkbase**
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase**

*

These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report onForm 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

**

Pursuant to Rule 406T ofRegulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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