10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2011

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission File Number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)

Texas and Virginia	75-1743247
(State or other jurisdiction of incorporation or organization)	(IRS employer identification no.)
Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas	75240 (Zip code)
(Address of principal executive offices)

(972) 934-9227

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes   þ     No   ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes   þ     No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer  þ Accelerated Filer  ¨ Non-Accelerated Filer  ¨ Smaller Reporting Company   ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes   ¨     No   þ

Number of shares outstanding of each of the issuer’s classes of common stock, as of February 3, 2012.

Class	Shares Outstanding
No Par Value	90,016,074

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
CFTC	Commodity Futures Trading Commission
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings, Ltd.
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
ISRS	Infrastructure System Replacement Surcharge
LPSC	Louisiana Public Service Commission
Mcf	Thousand cubic feet
MMcf	Million cubic feet
MPSC	Mississippi Public Service Commission
Moody’s	Moody’s Investors Services, Inc.
NYMEX	New York Mercantile Exchange, Inc.
PPA	Pension Protection Act of 2006
PRP	Pipeline Replacement Program
RRC	Railroad Commission of Texas
RRM	Rate Review Mechanism
S&P	Standard & Poor’s Corporation
SEC	United States Securities and Exchange Commission
WNA	Weather Normalization Adjustment

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	December 31, 2011			September 30, 2011
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	6,896,521		$	6,816,794
Less accumulated depreciation and amortization		1,650,308			1,668,876
Net property, plant and equipment		5,246,213			5,147,918
Current assets
Cash and cash equivalents		85,160			131,419
Accounts receivable, net		489,797			273,303
Gas stored underground		325,669			289,760
Other current assets		360,615			316,471
Total current assets		1,261,241			1,010,953
Goodwill and intangible assets		740,196			740,207
Deferred charges and other assets		387,982			383,793
	$	7,635,632		$	7,282,871
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding:
December 31, 2011 — 90,007,057 shares
September 30, 2011 — 90,296,482 shares	$	448		$	451
Additional paid-in capital		1,725,050			1,732,935
Retained earnings		607,485			570,495
Accumulated other comprehensive loss		(65,221	)		(48,460	)
Shareholders’ equity		2,267,762			2,255,421
Long-term debt		2,206,193			2,206,117
Total capitalization		4,473,955			4,461,538
Current liabilities
Accounts payable and accrued liabilities		432,332			291,205
Other current liabilities		357,353			367,563
Short-term debt		389,985			206,396
Current maturities of long-term debt		131			2,434
Total current liabilities		1,179,801			867,598
Deferred income taxes		981,559			960,093
Regulatory cost of removal obligation		437,660			428,947
Deferred credits and other liabilities		562,657			564,695
	$	7,635,632		$	7,282,871

See accompanying notes to condensed consolidated financial statements

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended December 31
	2011			2010
	(Unaudited) (In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	693,292		$	703,462
Regulated transmission and storage segment		56,759			49,007
Nonregulated segment		444,176			475,640
Intersegment eliminations		(93,054	)		(94,847	)
		1,101,173			1,133,262
Purchased gas cost
Natural gas distribution segment		402,207			412,526
Regulated transmission and storage segment		—			—
Nonregulated segment		428,771			450,462
Intersegment eliminations		(92,687	)		(94,450	)
		738,291			768,538
Gross profit		362,882			364,724
Operating expenses
Operation and maintenance		116,062			114,490
Depreciation and amortization		59,215			54,777
Taxes, other than income		43,198			40,168
Total operating expenses		218,475			209,435
Operating income		144,407			155,289
Miscellaneous expense		(1,875	)		(726	)
Interest charges		35,442			38,895
Income from continuing operations before income taxes		107,090			115,668
Income tax expense		41,302			44,568
Income from continuing operations		65,788			71,100
Income from discontinued operations, net of tax ($1,559 and $1,890)		2,719			2,897
Net income	$	68,507		$	73,997
Basic earnings per share
Income per share from continuing operations	$	0.72		$	0.78
Income per share from discontinued operations		0.03			0.03
Net income per share — basic	$	0.75		$	0.81
Diluted earnings per share
Income per share from continuing operations	$	0.72		$	0.78
Income per share from discontinued operations		0.03			0.03
Net income per share — diluted	$	0.75		$	0.81
Cash dividends per share	$	0.345		$	0.340
Weighted average shares outstanding:
Basic		90,254			90,082
Diluted		90,546			90,408

See accompanying notes to condensed consolidated financial statements

3

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended December 31
	2011			2010
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	68,507		$	73,997
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		60,733			56,161
Charged to other accounts		78			46
Deferred income taxes		40,042			43,423
Other		4,692			4,712
Net assets / liabilities from risk management activities		(8,426	)		5,304
Net change in operating assets and liabilities		(180,917	)		(137,819	)
Net cash provided (used) by operating activities		(15,291	)		45,824
Cash Flows From Investing Activities
Capital expenditures		(154,394	)		(123,162	)
Other, net		(1,080	)		(370	)
Net cash used in investing activities		(155,474	)		(123,532	)
Cash Flows From Financing Activities
Net increase in short-term debt		173,905			112,628
Repayment of long-term debt		(2,303	)		(10,000	)
Cash dividends paid		(31,517	)		(31,002	)
Repurchase of common stock		(12,535	)		—
Repurchase of equity awards		(3,120	)		(3,231	)
Issuance of common stock		76			7,253
Net cash provided by financing activities		124,506			75,648
Net decrease in cash and cash equivalents		(46,259	)		(2,060	)
Cash and cash equivalents at beginning of period		131,419			131,952
Cash and cash equivalents at end of period	$	85,160		$	129,892

See accompanying notes to condensed consolidated financial statements

4

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

December 31, 2011

1.    Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Our corporate headquarters and shared-services function are located in Dallas, Texas and our customer support centers are located in Amarillo and Waco, Texas.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. 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, which we currently anticipate will occur during fiscal 2012, we will operate in nine states. Our regulated activities also include our regulated pipeline and storage operations, which include the transportation of natural gas to our distribution system and the management of our underground storage facilities. Our regulated businesses are subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate.

Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties. AEH also seeks to maximize, through asset optimization activities, the economic value associated with storage and transportation capacity it owns or controls. Certain of these arrangements are with regulated affiliates of the Company, which have been approved by applicable state regulatory commissions.

We operate the Company through the following three segments:

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

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

• the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

2.    Unaudited Interim Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2011 are not indicative of our results of operations for the full 2012 fiscal year, which ends September 30, 2012.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We have evaluated subsequent events from the December 31, 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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three months ended December 31, 2011, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard requires enhanced disclosure of offsetting arrangements for financial instruments and will become effective for annual periods beginning after January 1, 2013 and for interim periods within those annual periods. The second standard defers the effective date for amendments to the presentation of reclassifications of items out of accumulated other comprehensive income as prescribed by a previously issued standard, which were initially to be effective for interim and annual periods beginning after December 15, 2011. The adoption of these standards should not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the quarter ended December 31, 2011.

Regulatory assets and liabilities

Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities, and the regulatory cost of removal obligation is reported separately.

6

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant regulatory assets and liabilities as of December 31, 2011 and September 30, 2011 included the following:

	December 31, 2011		September 30, 2011
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs	$	249,882	$	254,666
Merger and integration costs, net		6,120		6,242
Deferred gas costs		88,799		33,976
Regulatory cost of removal asset		9,875		8,852
Environmental costs		288		385
Rate case costs		4,493		4,862
Deferred franchise fees		365		379
Other		3,345		3,534
	$	363,167	$	312,896
Regulatory liabilities:
Deferred gas costs	$	1,871	$	8,130
Regulatory cost of removal obligation		469,685		464,025
Other		14,558		14,025
	$	486,114	$	486,180

The 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.

During the prior fiscal year, the Railroad Commission of Texas’ Division of Public Safety issued a new rule requiring natural gas distribution companies to develop and implement a risk-based program for the renewal or replacement of distribution facilities, including steel service lines. The rule allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing) at which time investment and costs would be recovered through base rates. As of December 31, 2011, we had deferred $0.1 million associated with the requirements of this rule which are recorded as other costs in the regulatory assets table above.

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from applicable state regulatory commissions.

7

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive income

The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2011 and 2010:

	Three Months Ended December 31
	2011			2010
	(In thousands)
Net income	$	68,507		$	73,997
Unrealized holding gains on investments, net of tax expense of $514 and $455 for the three months ended December 31, 2011 and 2010		901			776
Amortization and unrealized gain (loss) on treasury lock agreements, net of tax expense (benefit) of $(638) and $18,704 for the three months ended December 31, 2011 and 2010		(1,087	)		31,847
Net unrealized gains (losses) on cash flow hedging transactions, net of tax expense (benefit) of $(10,597) and $6,617 for the three months ended December 31, 2011 and 2010		(16,575	)		10,350
Comprehensive income	$	51,746		$	116,970

Accumulated other comprehensive loss, net of tax, as of December 31, 2011 and September 30, 2011 consisted of the following unrealized gains (losses):

	December 31, 2011			September 30, 2011
	(In thousands)
Accumulated other comprehensive loss:
Unrealized holding gains on investments	$	3,459		$	2,558
Treasury lock agreements		(35,244	)		(34,157	)
Cash flow hedges		(33,436	)		(16,861	)
	$	(65,221	)	$	(48,460	)

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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the first quarter there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions.

Regulated Commodity Risk Management Activities

Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We

8

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2011-2012 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 25 percent, or 25.7 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges.

The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas costs adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas costs 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

The primary business in our nonregulated operations is to aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. We utilize proprietary and customer-owned transportation and storage assets to serve these customers, and will seek to maximize the value of this storage capacity through the arbitrage of pricing differences that occur over time by selling financial instruments at advantageous prices to lock in a gross profit margin to enhance our gross profit by maximizing the economic value associated with the storage and transportation capacity we own or control.

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. Future contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.

We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 59 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.

Also, in our nonregulated operations, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges.

9

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

As of December 31, 2011, we had three Treasury lock agreements outstanding to fix the Treasury yield component of $350 million 30-year unsecured notes, which we plan to issue to refinance our $250 million unsecured 5.125% Senior Notes that mature in January 2013.

In prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled 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 December 31, 2011, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2011, we had net long/(short) commodity contracts outstanding in the following quantities:

Contract Type	Hedge Designation	Natural Gas Distribution		Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value		—		(26,690	)
	Cash Flow		—		44,428
	Not designated		13,964		46,944
			13,964		64,682

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2011 and September 30, 2011. 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 $22.1 million and $28.8 million of cash held on deposit as of December 31, 2011 and September 30, 2011 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.

	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
December 31, 2011:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	60,222		$	60,222
Noncurrent commodity contracts	Deferred charges and other assets		—			58			58
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(57,988	)		(57,988	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(69,755	)		(12,012	)		(81,767	)
Total			(69,755	)		(9,720	)		(79,475	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		292			148,669			148,961
Noncurrent commodity contracts	Deferred charges and other assets		180			80,916			81,096
Liability Financial Instruments
Current commodity contracts	Other current liabilities(1)		(16,196	)		(166,878	)		(183,074	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(350	)		(68,250	)		(68,600	)
Total			(16,074	)		(5,543	)		(21,617	)
Total Financial Instruments		$	(85,829	)	$	(15,263	)	$	(101,092	)

⁽¹⁾  Other current liabilities not designated as hedges in our natural gas distribution segment include $1.7 million related to risk management liabilities that were classified as assets held for sale at December 31, 2011.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
September 30, 2011:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	22,396		$	22,396
Noncurrent commodity contracts	Deferred charges and other assets		—			174			174
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(31,064	)		(31,064	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(67,527	)		(7,709	)		(75,236	)
Total			(67,527	)		(16,203	)		(83,730	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		843			67,710			68,553
Noncurrent commodity contracts	Deferred charges and other assets		998			22,379			23,377
Liability Financial Instruments
Current commodity contracts	Other current liabilities(1)		(13,256	)		(73,865	)		(87,121	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(335	)		(25,071	)		(25,406	)
Total			(11,750	)		(8,847	)		(20,597	)
Total Financial Instruments		$	(79,277	)	$	(25,050	)	$	(104,327	)

⁽¹⁾  Other current liabilities not designated as hedges in our natural gas distribution segment include $1.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2011.

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 December 31, 2011 and 2010 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $8.4 million and $13.5 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

12

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2011 and 2010 is presented below.

	Three Months Ended December 31
	2011			2010
	(In thousands)
Commodity contracts	$	24,064		$	(1,723	)
Fair value adjustment for natural gas inventory designated as the hedged item		(15,249	)		15,625
Total impact on revenue	$	8,815		$	13,902
The impact on revenue is comprised of the following:
Basis ineffectiveness	$	841		$	921
Timing ineffectiveness		7,974			12,981
	$	8,815		$	13,902

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.

To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. During the three months ended December 31, 2011, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market. We did not record a writedown for nonqualifying natural gas inventory for the three months ended December 31, 2010.

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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 months ended December 31, 2011 and 2010 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	Three Months Ended December 31, 2011
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(11,642	)	$	(11,642	)
Loss arising from ineffective portion of commodity contracts		—			(430	)		(430	)
Total impact on revenue		—			(12,072	)		(12,072	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(502	)		—			(502	)
Total Impact from Cash Flow Hedges	$	(502	)	$	(12,072	)	$	(12,574	)

	Three Months Ended December 31, 2010
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(14,253	)	$	(14,253	)
Loss arising from ineffective portion of commodity contracts		—			(444	)		(444	)
Total impact on revenue		—			(14,697	)		(14,697	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(670	)		—			(670	)
Total Impact from Cash Flow Hedges	$	(670	)	$	(14,697	)	$	(15,367	)

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three months ended December 31, 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 December 31
	2011			2010
	(In thousands)
Increase (decrease) in fair value:
Treasury lock agreements	$	(1,403	)	$	31,425
Forward commodity contracts		(23,678	)		1,657
Recognition of losses in earnings due to settlements:
Treasury lock agreements		316			422
Forward commodity contracts		7,103			8,693
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(17,662	)	$	42,197

⁽¹⁾  Utilizing an income tax rate ranging from 37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with our Treasury lock agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, 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 December 31, 2011. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock agreements as those instruments have not yet settled.

	Treasury Lock Agreements			Commodity Contracts			Total
	(In thousands)
Next twelve months	$	(1,266	)	$	(25,900	)	$	(27,166	)
Thereafter		9,967			(7,536	)		2,431
Total(1)	$	8,701		$	(33,436	)	$	(24,735	)

⁽¹⁾  Utilizing an income tax rate ranging from 37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statement for the three months ended December 31, 2011 and 2010 was an increase (decrease) in revenue of ($2.2) million and $4.2 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.

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

15

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.

4.    Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the first quarter of fiscal 2012, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 9 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2011.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and September 30, 2011. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(2)			December 31, 2011
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	472	$	—	$	—		$	472
Nonregulated segment		33,768		256,098		—		(272,938	)		16,928
Total financial instruments		33,768		256,570		—		(272,938	)		17,400
Hedged portion of gas stored underground		77,551		—		—		—			77,551
Available-for-sale securities
Money market funds		—		1,151		—		—			1,151
Registered investment companies		38,008		—		—		—			38,008
Bonds		—		18,346		—		—			18,346
Total available-for-sale securities		38,008		19,497		—		—			57,505
Total assets	$	149,327	$	276,067	$	—	$	(272,938	)	$	152,456
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	86,301	$	—	$	—		$	86,301
Nonregulated segment		51,117		254,012		—		(295,022	)		10,107
Total liabilities	$	51,117	$	340,313	$	—	$	(295,022	)	$	96,408

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(3)			September 30, 2011
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	1,841	$	—	$	—		$	1,841
Nonregulated segment		15,262		97,396		—		(95,156	)		17,502
Total financial instruments		15,262		99,237		—		(95,156	)		19,343
Hedged portion of gas stored underground		47,940		—		—		—			47,940
Available-for-sale securities
Money market funds		—		1,823		—		—			1,823
Registered investment companies		36,444		—		—		—			36,444
Bonds		—		14,366		—		—			14,366
Total available-for-sale securities		36,444		16,189		—		—			52,633
Total assets	$	99,646	$	115,426	$	—	$	(95,156	)	$	119,916
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	81,118	$	—	$	—		$	81,118
Nonregulated segment		22,091		115,617		—		(123,943	)		13,765
Total liabilities	$	22,091	$	196,735	$	—	$	(123,943	)	$	94,883

⁽¹⁾  Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences. This level also includes municipal and corporate bonds where market data for pricing is observable.

⁽²⁾  This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of December 31, 2011, we had $22.1 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $11.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $10.7 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, 2011 we had $28.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.4 million is classified as current risk management assets.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Available-for-sale securities are comprised of the following:

	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of December 31, 2011
Domestic equity mutual funds	$	27,881	$	5,447	$	—		$	33,328
Foreign equity mutual funds		4,659		305		(284	)		4,680
Bonds		18,323		45		(22	)		18,346
Money market funds		1,151		—		—			1,151
	$	52,014	$	5,797	$	(306	)	$	57,505
As of September 30, 2011
Domestic equity mutual funds	$	27,748	$	4,074	$	—		$	31,822
Foreign equity mutual funds		4,597		267		(242	)		4,622
Bonds		14,390		10		(34	)		14,366
Money market funds		1,823		—		—			1,823
	$	48,558	$	4,351	$	(276	)	$	52,633

At December 31, 2011 and September 30, 2011, our available-for-sale securities included $39.2 million and $38.3 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2011 we maintained investments in bonds that have contractual maturity dates ranging from January 2012 through July 2016.

These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.

We maintained an investment in one foreign equity mutual fund with a fair value of $2.2 million in an unrealized loss position of $0.3 million as of December 31, 2011. This fund has been in an unrealized loss position for less than twelve months. Because this fund is only used to fund the supplemental plans, we evaluate investment performance over a long-term horizon. Based upon our intent and ability to hold this investment, our ability to direct the source of the payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that this fund continues to receive good ratings from mutual fund rating companies, we do not consider this impairment to be other than temporary as of December 31, 2011. We also maintained several bonds with a cumulative fair value of $6.5 million in an unrealized loss position of less than $0.1 million as of December 31, 2011. These bonds have been in an unrealized loss position for less than twelve months. Based upon our intent and ability to hold these investments, our ability to direct the source of payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that these bonds are investment grade, we do not consider this impairment to be other than temporary as of December 31, 2011.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of December 31, 2011:

	December 31, 2011
	(In thousands)
Carrying Amount	$	2,210,262
Fair Value	$	2,572,094

5.    Discontinued Operations

On May 12, 2011, we entered into a definitive agreement to sell substantially 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 a 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, which we currently anticipate will occur during fiscal 2012.

As required under generally accepted accounting principles, the operating results of our Missouri, Illinois and Iowa operations have been aggregated and reported on the 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.

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 consolidated balance sheets at December 31, 2011 and September 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 December 31
	2011			2010
	(In thousands)
Operating revenues	$	23,451		$	23,733
Purchased gas cost		14,951			14,897
Gross profit		8,500			8,836
Operating expenses		4,174			4,016
Operating income		4,326			4,820
Other nonoperating expense		(48	)		(33	)
Income from discontinued operations before income taxes		4,278			4,787
Income tax expense		1,559			1,890
Net income	$	2,719		$	2,897

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents balance sheet data related to assets held for sale.

	December 31, 2011		September 30, 2011
	(In thousands)
Net plant, property & equipment	$	127,227	$	127,577
Gas stored underground		14,257		11,931
Other current assets		3,773		786
Deferred charges and other assets		62		277
Assets held for sale	$	145,319	$	140,571
Accounts payable and accrued liabilities	$	9,945	$	1,917
Other current liabilities		5,459		4,877
Regulatory cost of removal obligation		10,367		10,498
Deferred credits and other liabilities		1,175		1,153
Liabilities held for sale	$	26,946	$	18,445

6.    Debt

The nature and terms of our debt instruments are described in detail in Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes in the terms of our debt instruments during the three months ended December 31, 2011.

Long-term debt

Long-term debt at December 31, 2011 and September 30, 2011 consisted of the following:

	December 31, 2011			September 30, 2011
	(In thousands)
Unsecured 10% Notes, redeemed December 2011	$	—		$	2,303
Unsecured 5.125% Senior Notes, due January 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			400,000
Medium term notes
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		262			262
Total long-term debt		2,210,262			2,212,565
Less:
Original issue discount on unsecured senior notes and debentures		(3,938	)		(4,014	)
Current maturities		(131	)		(2,434	)
	$	2,206,193		$	2,206,117

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our unsecured 10% notes were paid on their maturity date on December 31, 2011, and were not replaced.

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.

We finance our short-term borrowing requirements through a combination of a $750 million commercial paper program and four committed revolving credit facilities with third-party lenders. As a result, we have approximately $985 million of working capital funding. Additionally, our $750 million unsecured credit facility has an accordion feature which, if utilized, would increase borrowing capacity to $1.0 billion. At December 31, 2011 and September 30, 2011, there was $390.0 million and $206.4 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.

Regulated Operations

We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $785 million of working capital funding, including a five-year $750 million unsecured facility, a $25 million unsecured facility and a $10 million revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.2 million at December 31, 2011.

In addition to these third-party facilities, our regulated operations had a $350 million intercompany revolving credit facility with AEH. This facility was replaced on January 1, 2012 with a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) 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, 2012.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, has a three-year $200 million committed revolving credit facility, expiring in December 2013, 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. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH. Due to outstanding letters of credit and various covenants, including covenants based on working capital, the amount available to AEM under this credit facility was $110.0 million at December 31, 2011.

To supplement borrowings under this facility, AEH had a $350 million intercompany demand credit facility with AEC. This facility was replaced on January 1, 2012 with a $500 million intercompany 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, 2012.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

has been approved by all requisite state regulatory commissions. At December 31, 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

The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2011, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 56 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

AEM is required by the financial covenants in its facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At December 31, 2011, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.39 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at December 31, 2011, AEM’s net working capital was $118.2 million and its tangible net worth was $147.8 million.

In addition to these financial covenants, 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.

Finally, AEM’s credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2. We have no other triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.

We were in compliance with all of our debt covenants as of December 31, 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.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 months ended December 31, 2011 and 2010 are calculated as follows:

	Three Months Ended December 31
	2011		2010
	(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	65,788	$	71,100
Less: Income from continuing operations allocated to participating securities		685		748
Income from continuing operations available to common shareholders	$	65,103	$	70,352
Basic weighted average shares outstanding		90,254		90,082
Income from continuing operations per share — Basic	$	0.72	$	0.78
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	2,719	$	2,897
Less: Income from discontinued operations allocated to participating securities		28		31
Income from discontinued operations available to common shareholders	$	2,691	$	2,866
Basic weighted average shares outstanding		90,254		90,082
Income from discontinued operations per share — Basic	$	0.03	$	0.03
Net income per share — Basic	$	0.75	$	0.81
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	65,103	$	70,352
Effect of dilutive stock options and other shares		1		2
Income from continuing operations available to common shareholders	$	65,104	$	70,354
Basic weighted average shares outstanding		90,254		90,082
Additional dilutive stock options and other shares		292		326
Diluted weighted average shares outstanding		90,546		90,408
Income from continuing operations per share — Diluted	$	0.72	$	0.78

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended December 31
	2011		2010
	(In thousands, except per share amounts)
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	2,691	$	2,866
Effect of dilutive stock options and other shares		—		—
Income from discontinued operations available to common shareholders	$	2,691	$	2,866
Basic weighted average shares outstanding		90,254		90,082
Additional dilutive stock options and other shares		292		326
Diluted weighted average shares outstanding		90,546		90,408
Income from discontinued operations per share — Diluted	$	0.03	$	0.03
Net income per share — Diluted	$	0.75	$	0.81

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2011 and 2010 as their exercise price was less than the average market price of the common stock during that period.

Share Repurchase Program

On September 28, 2011, the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. Although the program is authorized for a five-year period, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the company deems appropriate. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the company. As of December 31, 2011, 387,991 shares had been repurchased for an aggregate value of $12.5 million.

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 months ended December 31, 2011 and 2010 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2011			2010			2011			2010
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,298		$	4,380		$	4,088		$	3,601
Interest cost		6,677			6,924			3,465			3,203
Expected return on assets		(5,368	)		(5,963	)		(652	)		(682	)
Amortization of transition asset		—			—			378			378
Amortization of prior service cost		(35	)		(112	)		(362	)		(362	)
Amortization of actuarial loss		4,142			3,494			662			87
Net periodic pension cost	$	9,714		$	8,723		$	7,579		$	6,225

25

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2011 and 2010 are as follows:

	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Discount rate		5.05	%		5.39	%		5.05	%		5.39	%
Rate of compensation increase		3.50	%		4.00	%		N/A			N/A
Expected return on plan assets		7.75	%		8.25	%		4.70	%		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, 2012. Based upon this valuation, we expect we will be required to contribute between $25 million and $30 million to our pension plans by September 15, 2012.

We contributed $4.8 million to our other post-retirement benefit plans during the three months ended December 31, 2011. We expect to contribute between $20 million and $25 million to these plans during fiscal 2012.

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 13 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2011.

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, Billy Joe Honeycutt et al. vs. Atmos Energy Corporation, et al., which is 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.

26

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals, appealing the verdict of the trial court. The appellees in this case subsequently filed their reply brief with the Court of Appeals on January 16, 2012, with our reply brief due to be filed with the Court by March 16, 2012.

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, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, 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. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. As of this date, the Court has not yet ruled on the motion.

We have accrued what we believe is an adequate amount for the anticipated resolution of this matter; however, the amount accrued is less than 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 continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

We are a party to other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

Purchase Commitments

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2011, AEH was committed to purchase 103.1 Bcf within one year, 35.3 Bcf within one to three years and 0.3 Bcf after three years under indexed contracts. AEH is committed to purchase 3.4 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $2.82 to $6.36 per Mcf. Purchases under these contracts totaled $312.1 million and $334.2 million for the three months ended December 31, 2011 and 2010.

Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

27

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of December 31, 2011 are as follows (in thousands):

2012	$	149,788
2013		82,778
2014		68,124
Thereafter		—
	$	300,690

Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes to the estimated storage and transportation fees for the quarter ended December 31, 2011.

Regulatory Matters

As previously described in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, 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. Since that time, we have fully cooperated with the Commission during this investigation.

The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission’s findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company has paid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company’s financial position, results of operations or cash flows and none of the payments were charged to any of the Company’s customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.

As discussed in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, in 2010, our Mid-Tex Division agreed to install 100,000 steel service line replacements by September 30, 2012. As of December 31, 2011, we had replaced 60,184 lines and are on schedule for completion in September 2012. Under the terms of the agreement, special rate recovery of the associated return, depreciation and taxes is approved for lines replaced between October 1, 2010 and September 30, 2012. Since October 1, 2010, we have spent $64.0 million on steel service line replacements.

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 (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the CFTC and SEC have issued a number of rules and regulations, we expect additional rules and regulations to be issued, which should 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 and related rules and regulations. We also anticipate additional reporting and disclosure obligations will be imposed.

28

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2011, annual rate filing mechanisms were in progress in our Louisiana and Mississippi service areas and there was one other ratemaking activity in progress in our Kansas service area. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

10.    Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three months ended December 31, 2011, there were no material changes in our concentration of credit risk.

11.    Segment Information

As discussed in Note 1 above, we operate the Company through the following three segments:

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

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

• The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. We evaluate performance based on net income or loss of the respective operating units.

29

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income statements for the three month periods ended December 31, 2011 and 2010 by segment are presented in the following tables:

	Three Months Ended December 31, 2011
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	693,068		$	19,440		$	388,665	$	—		$	1,101,173
Intersegment revenues		224			37,319			55,511		(93,054	)		—
		693,292			56,759			444,176		(93,054	)		1,101,173
Purchased gas cost		402,207			—			428,771		(92,687	)		738,291
Gross profit		291,085			56,759			15,405		(367	)		362,882
Operating expenses
Operation and maintenance		93,414			16,965			6,051		(368	)		116,062
Depreciation and amortization		50,831			7,651			733		—			59,215
Taxes, other than income		38,479			3,784			935		—			43,198
Total operating expenses		182,724			28,400			7,719		(368	)		218,475
Operating income		108,361			28,359			7,686		1			144,407
Miscellaneous income (expense)		(1,756	)		(280	)		36		125			(1,875	)
Interest charges		27,855			7,209			252		126			35,442
Income from continuing operations before income taxes		78,750			20,870			7,470		—			107,090
Income tax expense		30,845			7,456			3,001		—			41,302
Income from continuing operations		47,905			13,414			4,469		—			65,788
Income from discontinued operations, net of tax		2,719			—			—		—			2,719
Net income	$	50,624		$	13,414		$	4,469	$	—		$	68,507
Capital expenditures	$	128,733		$	24,120		$	1,541	$	—		$	154,394

30

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended December 31, 2010
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	703,261		$	21,233		$	408,768	$	—		$	1,133,262
Intersegment revenues		201			27,774			66,872		(94,847	)		—
		703,462			49,007			475,640		(94,847	)		1,133,262
Purchased gas cost		412,526			—			450,462		(94,450	)		768,538
Gross profit		290,936			49,007			25,178		(397	)		364,724
Operating expenses
Operation and maintenance		89,229			15,574			10,084		(397	)		114,490
Depreciation and amortization		47,894			5,799			1,084		—			54,777
Taxes, other than income		34,448			3,553			2,167		—			40,168
Total operating expenses		171,571			24,926			13,335		(397	)		209,435
Operating income		119,365			24,081			11,843		—			155,289
Miscellaneous income (expense)		(698	)		(282	)		290		(36	)		(726	)
Interest charges		29,697			8,064			1,170		(36	)		38,895
Income from continuing operations before income taxes		88,970			15,735			10,963		—			115,668
Income tax expense		34,549			5,633			4,386		—			44,568
Income from continuing operations		54,421			10,102			6,577		—			71,100
Income from discontinued operations, net of tax		2,897			—			—		—			2,897
Net income	$	57,318		$	10,102		$	6,577	$	—		$	73,997
Capital expenditures	$	109,499		$	12,739		$	924	$	—		$	123,162

31

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at December 31, 2011 and September 30, 2011 by segment is presented in the following tables.

	December 31, 2011
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,328,612	$	855,245	$	62,356		$	—		$	5,246,213
Investment in subsidiaries		672,300		—		(2,096	)		(670,204	)		—
Current assets
Cash and cash equivalents		63,031		—		22,129			—			85,160
Assets from risk management activities		292		—		10,732			—			11,024
Other current assets		912,185		13,418		453,571			(214,117	)		1,165,057
Intercompany receivables		567,587		—		—			(567,587	)		—
Total current assets		1,543,095		13,418		486,432			(781,704	)		1,261,241
Intangible assets		—		—		196			—			196
Goodwill		572,908		132,381		34,711			—			740,000
Noncurrent assets from risk management activities		180		—		6,196			—			6,376
Deferred charges and other assets		359,860		11,297		10,449			—			381,606
	$	7,476,955	$	1,012,341	$	598,244		$	(1,451,908	)	$	7,635,632
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,267,762	$	278,515	$	393,785		$	(672,300	)	$	2,267,762
Long-term debt		2,206,062		—		131			—			2,206,193
Total capitalization		4,473,824		278,515		393,916			(672,300	)		4,473,955
Current liabilities
Current maturities of long-term debt		—		—		131			—			131
Short-term debt		583,980		—		—			(193,995	)		389,985
Liabilities from risk management activities		14,521		—		4,623			—			19,144
Other current liabilities		606,357		11,929		170,281			(18,026	)		770,541
Intercompany payables		—		531,126		36,461			(567,587	)		—
Total current liabilities		1,204,858		543,055		211,496			(779,608	)		1,179,801
Deferred income taxes		813,423		181,641		(13,505	)		—			981,559
Noncurrent liabilities from risk management activities		70,105		—		5,484			—			75,589
Regulatory cost of removal obligation		437,660		—		—			—			437,660
Deferred credits and other liabilities		477,085		9,130		853			—			487,068
	$	7,476,955	$	1,012,341	$	598,244		$	(1,451,908	)	$	7,635,632

32

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	September 30, 2011
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,248,198	$	838,302	$	61,418		$	—		$	5,147,918
Investment in subsidiaries		670,993		—		(2,096	)		(668,897	)		—
Current assets
Cash and cash equivalents		24,646		—		106,773			—			131,419
Assets from risk management activities		843		—		17,501			—			18,344
Other current assets		655,716		15,413		386,215			(196,154	)		861,190
Intercompany receivables		569,898		—		—			(569,898	)		—
Total current assets		1,251,103		15,413		510,489			(766,052	)		1,010,953
Intangible assets		—		—		207			—			207
Goodwill		572,908		132,381		34,711			—			740,000
Noncurrent assets from risk management activities		998		—		—			—			998
Deferred charges and other assets		353,960		18,028		10,807			—			382,795
	$	7,098,160	$	1,004,124	$	615,536		$	(1,434,949	)	$	7,282,871
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,255,421	$	265,102	$	405,891		$	(670,993	)	$	2,255,421
Long-term debt		2,205,986		—		131			—			2,206,117
Total capitalization		4,461,407		265,102		406,022			(670,993	)		4,461,538
Current liabilities
Current maturities of long-term debt		2,303		—		131			—			2,434
Short-term debt		387,691		—		—			(181,295	)		206,396
Liabilities from risk management activities		11,916		—		3,537			—			15,453
Other current liabilities		474,783		10,369		170,926			(12,763	)		643,315
Intercompany payables		—		543,084		26,814			(569,898	)		—
Total current liabilities		876,693		553,453		201,408			(763,956	)		867,598
Deferred income taxes		789,649		173,351		(2,907	)		—			960,093
Noncurrent liabilities from risk management activities		67,862		—		10,227			—			78,089
Regulatory cost of removal obligation		428,947		—		—			—			428,947
Deferred credits and other liabilities		473,602		12,218		786			—			486,606
	$	7,098,160	$	1,004,124	$	615,536		$	(1,434,949	)	$	7,282,871

33

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 and subsidiaries as of December 31, 2011, the related condensed consolidated statements of income for the three-month periods ended December 31, 2011 and 2010, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2011 and 2010. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2011, 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 22, 2011, 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, 2011, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/    ERNST & YOUNG LLP

Dallas, Texas

February 8, 2012

34

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2011.

Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events, and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy and its subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. 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, which we currently anticipate will occur during fiscal 2012, we will operate in nine states.

Through our nonregulated businesses, we provide natural gas management and transportation services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and

35

Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties. Through our asset optimization activities, we also seek to maximize the economic value associated with the storage and transportation capacity we own or control.

As discussed in Note 11, we operate the Company through the following three segments:

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

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

• the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011 and include the following:

• Regulation

• Revenue Recognition

• Allowance for Doubtful Accounts

• Financial Instruments and Hedging Activities

• Impairment Assessments

• Pension and Other Postretirement Plans

• Fair Value Measurements

Our critical accounting policies are reviewed quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the three months ended December 31, 2011.

RESULTS OF OPERATIONS

We reported net income of $68.5 million, or $0.75 per diluted share for the three months ended December 31, 2011 compared with net income of $74.0 million, or $0.81 per diluted share in the prior-year quarter. Regulated operations contributed 93 percent of our net income during this period with our nonregulated operations contributing the remaining seven percent. Excluding the impact of unrealized margins, diluted earnings per share decreased $0.20 compared with the prior-year quarter. The $0.20 per diluted share decrease primarily reflects the adverse impact of unfavorable natural gas market conditions on our nonregulated segment and increased operating expenses in our natural gas distribution segment. These decreases were partially offset by a five percent increase in consolidated throughput in our regulated transmission and storage segment and the favorable impact of ratemaking efforts in our natural gas distribution segment.

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Due to the pending sale of our Missouri, Illinois and Iowa service areas, 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 $2.7 million, or $0.03 per diluted share, compared with net income of $2.9 million, or $0.03 per diluted share in the prior-year quarter. Continuing operations in the current quarter generated net income of $65.8 million, or $0.72 per diluted share, compared with net income of $71.1 million, or $0.78 per diluted share from continuing operations in the prior-year quarter.

The following table presents our consolidated financial highlights for the three months ended December 31, 2011 and 2010:

	Three Months Ended December 31
	2011			2010
	(In thousands, except per share data)
Operating revenues	$	1,101,173		$	1,133,262
Gross profit		362,882			364,724
Operating expenses		218,475			209,435
Operating income		144,407			155,289
Miscellaneous expense		(1,875	)		(726	)
Interest charges		35,442			38,895
Income from continuing operations before income taxes		107,090			115,668
Income tax expense		41,302			44,568
Income from continuing operations		65,788			71,100
Income from discontinued operations, net of tax		2,719			2,897
Net income	$	68,507		$	73,997
Diluted net income per share from continuing operations	$	0.72		$	0.78
Diluted net income per share from discontinued operations		0.03			0.03
Diluted net income per share	$	0.75		$	0.81

The following table reflects our consolidated net income and diluted earnings per share in our regulated and nonregulated operations:

	Three Months Ended December 31
	2011		2010		Change
	(In thousands, except per share data)
Regulated operations	$	61,319	$	64,523	$	(3,204	)
Nonregulated operations		4,469		6,577		(2,108	)
Net income from continuing operations		65,788		71,100		(5,312	)
Net income from discontinued operations		2,719		2,897		(178	)
Net income	$	68,507	$	73,997	$	(5,490	)
Diluted EPS from continuing regulated operations	$	0.67	$	0.71	$	(0.04	)
Diluted EPS from nonregulated operations		0.05		0.07		(0.02	)
Diluted EPS from continuing operations		0.72		0.78		(0.06	)
Diluted EPS from discontinued operations		0.03		0.03		—
Consolidated diluted EPS	$	0.75	$	0.81	$	(0.06	)

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Three Months Ended December 31, 2011 compared with Three Months Ended December 31, 2010

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 over 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 substantially all of our natural gas distribution operations in Missouri, Illinois and Iowa. The results of these operations have been separately reported in the following tables as discontinued operations and exclude general corporate overhead and interest expense that would normally be allocated to these operations.

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Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the three months ended December 31, 2011 and 2010 are presented below.

	Three Months Ended December 31
	2011			2010			Change
	(In thousands, unless otherwise noted)
Gross profit	$	291,085		$	290,936		$	149
Operating expenses		182,724			171,571			11,153
Operating income		108,361			119,365			(11,004	)
Miscellaneous expense		(1,756	)		(698	)		(1,058	)
Interest charges		27,855			29,697			(1,842	)
Income from continuing operations before income taxes		78,750			88,970			(10,220	)
Income tax expense		30,845			34,549			(3,704	)
Income from continuing operations		47,905			54,421			(6,516	)
Income from discontinued operations, net of tax		2,719			2,897			(178	)
Net income	$	50,624		$	57,318		$	(6,694	)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf		84,890			84,137			753
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf		32,832			32,218			614
Consolidated natural gas distribution throughput from continuing operations — MMcf		117,722			116,355			1,367
Consolidated natural gas distribution throughput from discontinued operations — MMcf		4,026			4,189			(163	)
Total consolidated natural gas distribution throughput — MMcf		121,748			120,544			1,204
Consolidated natural gas distribution average transportation revenue per Mcf	$	0.45		$	0.49		$	(0.04	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	4.78		$	4.92		$	(0.14	)

The $0.1 million increase in natural gas distribution gross profit primarily reflects the following:

• $4.6 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana and Kentucky service areas.

• A two percent rise in transportation volumes resulting in a $0.5 million increase in transportation margins.

These increases were largely offset by the quarter-over-quarter negative effect of the weather normalization adjustment in the Mid-Tex Division, which required utilizing updated weather data in the calculation of the adjustment in the current quarter.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $11.2 million, primarily due to the following:

• $2.9 million increase in depreciation and amortization and a $2.6 million increase in ad valorem taxes associated with an increase in our net plant as a result of our capital investments in the prior year.

• $3.5 million net increase in legal and other administrative costs.

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The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended December 31, 2011 and 2010. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	Three Months Ended
	December 31
	2011			2010		Change
	(In thousands)
Mid-Tex	$	48,449		$	57,439	$	(8,990	)
Kentucky/Mid-States		16,318			16,853		(535	)
Louisiana		15,201			14,961		240
West Texas		10,675			9,520		1,155
Mississippi		10,132			10,215		(83	)
Colorado-Kansas		8,179			7,702		477
Other		(593	)		2,675		(3,268	)
Total	$	108,361		$	119,365	$	(11,004	)

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the three months ended December 31, 2011 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a final order from a commission or other governmental authority.

Annual net operating income increases totaling $4.3 million resulting from ratemaking activity became effective in the quarter ended December 31, 2011 as summarized below:

Rate Action	Annual Increase to Operating Income
	(In thousands)
Rate case filings	$	545
Infrastructure programs		3,744
	$	4,289

Additionally, the following ratemaking efforts were in progress during the first quarter of fiscal 2012 but had not been completed as of December 31, 2011.

Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Ad Valorem(1)	Kansas	$	167
Louisiana	Rate Stabilization Clause	TransLa		—
Mississippi	Stable Rate Filing(2)	Mississippi		5,303
			$	5,470

⁽¹⁾  The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service area’s base rates. The Kansas Commission approved the filing on January 14, 2012.

⁽²⁾  The Mississippi Commission issued a final order on January 11, 2012 approving a $4.3 million increase to operating income.

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Subsequent to December 31, 2011, we filed five rate actions requesting a total increase in annual operating income of $66.8 million in our Mid-Tex, West Texas, Kansas and Georgia service areas. In our Mid-Tex service area, we filed a rate case requesting a $46.0 million annual increase in operating income as well as our first City of Dallas Annual Rate Review filing in which we requested a $2.5 million increase to operating income. In our West Texas and Kansas service areas, we filed rate cases requesting an increase in annual operating income of $11.1 million and $6.1 million. In our Georgia service area, we requested an increase in annual operating income of $1.1 million under the annual pipeline replacement program.

Rate Case 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 for our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes the rate case that was completed during the three months ended December 31, 2011.

Division	State		Increase in Annual Operating Income		Effective Date
			(In thousands)
2012 Rate Case Filings:
West Texas — Environs		Texas	$	545		11/08/2011
Total 2012 Rate Case Filings			$	545

Infrastructure Programs

Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow natural gas distribution companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. We currently have infrastructure programs in Texas, Georgia, Missouri and Kentucky. The following table summarizes our infrastructure program filings with effective dates during the three months ended December 31, 2011.

Division	Period End	Incremental Net Utility Plant Investment		Increase in Annual Operating Income		Effective Date
		(In thousands)		(In thousands)
2012 Infrastructure Programs:
Kentucky/Mid-States — Georgia	09/2010	$	7,160	$	1,215		10/01/2011
Kentucky/Mid-States — Kentucky	09/2012		17,347		2,529		10/01/2011
Total 2012 Infrastructure Programs		$	24,507	$	3,744

Annual Rate Filing Mechanism

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, Georgia and Mississippi service areas 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, Georgia rate adjustment mechanism in Kentucky/Mid-States and a rate stabilization clause in the Louisiana Division. There were no annual rate filing mechanisms completed during the three months ended December 31, 2011.

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Other Ratemaking Activity

There was no other ratemaking activity completed during the three months ended December 31, 2011.

Regulated Transmission and Storage Segment

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

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

Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the three months ended December 31, 2011 and 2010 are presented below.

	Three Months  Ended December 31
	2011			2010			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	37,343		$	27,535		$	9,808
Third-party transportation		14,939			16,512			(1,573	)
Storage and park and lend services		1,806			2,170			(364	)
Other		2,671			2,790			(119	)
Gross profit		56,759			49,007			7,752
Operating expenses		28,400			24,926			3,474
Operating income		28,359			24,081			4,278
Miscellaneous expense		(280	)		(282	)		2
Interest charges		7,209			8,064			(855	)
Income before income taxes		20,870			15,735			5,135
Income tax expense		7,456			5,633			1,823
Net income	$	13,414		$	10,102		$	3,312
Gross pipeline transportation volumes — MMcf		160,829			153,178			7,651
Consolidated pipeline transportation volumes — MMcf		105,037			99,841			5,196

The $7.8 million increase in regulated transmission and storage gross profit was primarily a result of rate design changes approved in the rate case in the prior year. The current rate design allows us to recover fixed costs associated with transportation and storage services through monthly customer charges rather than through a volumetric charge, which should allow us to earn margin more ratably during the fiscal year. Additionally, consolidated throughput increased about five percent due to increased through-system demand and the execution of new delivery contracts with local producers.

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Operating expenses increased $3.5 million primarily due to the following:

• $1.3 million increase due to higher levels of pipeline maintenance activities.

• $1.9 million increase due to higher depreciation expense, resulting from the rate case and a higher investment in net plant.

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. This business is significantly influenced by competitive factors in the industry, general economic conditions and other factors that could affect the demand for natural gas. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of gas used to serve those customers. Further, delivered gas margins can be affected by the price of natural gas in the different locations where we buy and sell gas.

AEH also earns storage and transportation margins from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods. The majority of these margins are generated through demand fees established under contracts with certain of our natural gas distribution divisions that are renewed periodically and subject to regulatory oversight.

AEH utilizes customer-owned or contracted storage capacity to serve its customers. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments in an effort to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Margins earned from these activities and the related storage demand fees are reported as asset optimization margins. Certain of these arrangements are with regulated affiliates, which have been approved by applicable state regulatory commissions. These margins are influenced by natural gas market conditions including, but not limited to, the price of natural gas, demand for natural gas, the level of domestic natural gas inventory levels and the level of volatility between current (spot) and future natural gas prices. These margins are also impacted by our ability to minimize the demand fees paid to contract for storage capacity.

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 may also cause customers to conserve or use alternative energy sources. Lower natural gas prices generally reduce these risks.

The level of volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility influences the spreads between the current (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads and basis differentials from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Conversely, a lack of price volatility reduces opportunities to create value from arbitrage spreads and basis differentials.

Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment will include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. 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 generally record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

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Review of Financial and Operating Results

Financial and operational highlights for our nonregulated segment for the three months ended December 31, 2011 and 2010 are presented below.

	Three Months Ended December 31
	2011			2010		Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	11,113		$	16,041	$	(4,928	)
Storage and transportation services		3,189			3,349		(160	)
Other		1,017			1,319		(302	)
		15,319			20,709		(5,390	)
Asset optimization(1)		(21,594	)		3,965		(25,559	)
Total realized margins		(6,275	)		24,674		(30,949	)
Unrealized margins		21,680			504		21,176
Gross profit		15,405			25,178		(9,773	)
Operating expenses		7,719			13,335		(5,616	)
Operating income		7,686			11,843		(4,157	)
Miscellaneous income		36			290		(254	)
Interest charges		252			1,170		(918	)
Income before income taxes		7,470			10,963		(3,493	)
Income tax expense		3,001			4,386		(1,385	)
Net income	$	4,469		$	6,577	$	(2,108	)
Gross nonregulated delivered gas sales volumes — MMcf		106,462			107,712		(1,250	)
Consolidated nonregulated delivered gas sales volumes — MMcf		90,870			94,538		(3,668	)
Net physical position (Bcf)		35.6			19.6		16.0

⁽¹⁾  Net of storage fees of $4.7 million and $3.3 million.

Results for our nonregulated operations during the first fiscal quarter were adversely influenced by continued unfavorable natural gas market conditions. Historically high natural gas storage levels caused by growing domestic natural gas production coupled with an unseasonably warm start to the 2011-2012 winter heating season caused natural gas prices to fall and for spot to forward spread values and basis differentials to remain compressed. Further, unseasonably warm weather reduced the demand for natural gas.

We anticipate natural gas storage levels will remain high for an extended period of time and for unseasonably warm weather to continue during the second quarter of fiscal 2012. Therefore, we expect gas prices to remain relatively low with little volatility and spot to forward spread values and basis differentials to remain compressed. Further, sales of natural gas could be adversely impacted. Accordingly, although we anticipate continuing to profit from our nonregulated activities, we anticipate per-unit margins from our delivered gas activities and margins earned from our asset optimization activities will be more consistent with the reduced margins we realized in fiscal 2011 than in previous years.

Realized margins for gas delivery, storage and transportation services and other services were $15.3 million during the three months ended December 31, 2011 compared with $20.7 million for the prior-year quarter. The decrease reflects the following:

• A four percent decrease in consolidated sales volumes. The decrease was largely attributable to warmer weather particularly in the latter half of the quarter, which reduced sales to our utility, municipal and other

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weather-sensitive customers. These decreases were partially offset by a 6 percent period-over-period increase in sales to new and existing industrial and power generation customers.

• A decrease in gas delivery per-unit margins from $0.15/Mcf in the prior-year quarter to $0.10/Mcf in the current-year quarter primarily due to lower basis differentials resulting from increased natural gas supply coupled with increased transportation costs.

Asset optimization margins decreased $25.6 million from the prior-year quarter. In the prior year quarter, due to compressed spot to forward spread values, AEH traded more frequently in the daily cash market and earned intramonth trading gains that exceeded the demand fees paid for its contracted storage capacity.

In the current year quarter, AEH elected to take advantage of falling natural prices by purchasing and injecting a net 15.7 Bcf into storage and capturing incremental physical to forward spread values that should be realized in future periods. As a result of this decision, we realized no storage withdrawal gains to offset the realized losses on the settlement of financial instruments used to hedge our natural gas purchases.

We anticipate this trend will continue during the fiscal second quarter; however, a substantial portion of the incremental margins captured during the quarter are currently anticipated to be realized during the third and fourth quarter of fiscal 2012.

Realized asset optimization margins for the current-year quarter also included a $1.7 million charge to write-down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.

The $21.2 million increase in unrealized margins primarily reflects unrealized gains on the financial instruments executed during the quarter to capture incremental physical to forward spreads as a result of falling natural gas prices.

Operating expenses decreased $5.6 million due to the following:

• $3.1 million decrease in insurance and legal costs as a result of the resolution of the FERC matter and the timing of activity pertaining to other litigation.

• $1.4 million decrease in employee related expenses.

Interest charges decreased $0.9 million primarily due to a decrease in commitment fees.

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.

We intend to refinance our $250 million unsecured 5.125% Senior Notes that mature in January 2013 through the issuance of $350 million 30-year unsecured notes. In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuances of these senior notes. We designated all of these Treasury locks as cash flow hedges.

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 2012.

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Cash Flows

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

Cash flows from operating, investing and financing activities for the three months ended December 31, 2011 and 2010 are presented below.

	Three Months Ended December 31
	2011			2010			2011 vs. 2010
	(In thousands)
Total cash provided by (used in)
Operating activities	$	(15,291	)	$	45,824		$	(61,115	)
Investing activities		(155,474	)		(123,532	)		(31,942	)
Financing activities		124,506			75,648			48,858
Change in cash and cash equivalents		(46,259	)		(2,060	)		(44,199	)
Cash and cash equivalents at beginning of period		131,419			131,952			(533	)
Cash and cash equivalents at end of period	$	85,160		$	129,892		$	(44,732	)

Cash flows from operating activities

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

The $61.1 million decrease in operating cash flows primarily reflects the effect of purchasing natural gas and injecting it into storage in our nonregulated operations in order to capture incremental value anticipated to be realized in the third and fourth quarter of fiscal 2012, as well as the timing of customer collections and vendor payments.

Cash flows from investing activities

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

Capital expenditures for fiscal 2012 are expected to range from $680 million to $700 million. For the three months ended December 31, 2011, capital expenditures were $154.4 million compared with $123.2 million for the three months ended December 31, 2010. The $31.2 million increase in capital expenditures primarily reflects spending for the steel service line replacement program in the Mid-Tex Division and the development of new customer billing and information systems for our natural gas distribution segment.

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Cash flows from financing activities

The $48.9 million increase in financing cash flows was primarily due to the following:

• $61.3 million additional cash provided from short-term debt borrowings.

• $7.7 million increase in cash flows due to lower repayments of long-term debt. In the current-year quarter, we repaid $2.3 million of long-term debt compared to $10.0 million in the prior-year quarter.

These increases in financing cash flows were partially offset by the following:

• $12.5 million additional cash used to repurchase common stock as part of our share buyback program.

• $7.2 million less cash received from proceeds related to the issuance of common stock.

The following table summarizes our share issuances for the three months ended December 31, 2011 and 2010.

	Three Months Ended December 31
	2011		2010
Shares issued:
1998 Long-Term Incentive Plan		197,503		595,103
Outside Directors Stock-for-Fee Plan		618		638
Total shares issued		198,121		595,741

The quarter-over-quarter decrease in the number of shares issued primarily reflects the significant number of stock options exercised in the prior year. During the current quarter, we cancelled and retired 99,555 shares attributable to federal withholdings on equity awards and repurchased and retired 387,991 shares through our 2011 share repurchase program described in Note 7.

As of September 30, 2011, we were authorized to grant awards for up to a maximum of 6.5 million shares of common stock under our 1998 Long-Term Incentive Plan (LTIP). In February 2011, shareholders voted to increase the number of authorized LTIP shares by 2.2 million shares. On October 19, 2011, we received all required state regulatory approvals to increase the maximum number of authorized LTIP shares to 8.7 million shares, subject to certain adjustment provisions. On October 28, 2011, we filed with the SEC a registration statement on Form S-8 to register an additional 2.2 million shares; we also listed such shares with the New York Stock Exchange.

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 four committed revolving credit facilities with third-party lenders that provide approximately $1.0 billion of working capital funding. As of December 31, 2011, the amount available to us under our credit facilities, net of outstanding letters of credit, was $499.2 million.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we were able to issue a total of $950 million in debt securities and $350 million in equity securities. At December 31, 2011, $900

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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). As of December 31, 2011, all three ratings agencies 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 for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of December 31, 2011. Our debt covenants are described in greater detail in Note 6 to the unaudited condensed consolidated financial statements.

Capitalization

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of December 31, 2011, September 30, 2011 and December 31, 2010:

	December 31, 2011				September 30, 2011				December 31, 2010
	(In thousands, except percentages)
Short-term debt	$	389,985	8.0	%	$	206,396	4.4	%	$	247,993	5.3	%
Long-term debt		2,206,324	45.4	%		2,208,551	47.3	%		2,159,753	46.1	%
Shareholders’ equity		2,267,762	46.6	%		2,255,421	48.3	%		2,274,853	48.6	%
Total	$	4,864,071	100.0	%	$	4,670,368	100.0	%	$	4,682,599	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 53.4 percent at December 31, 2011, 51.7 percent at September 30, 2011 and 51.4 percent at December 31, 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.

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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 three months ended December 31, 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 months ended December 31, 2011 and 2010:

	Three Months Ended December 31
	2011			2010
	(In thousands)
Fair value of contracts at beginning of period	$	(79,277	)	$	(49,600	)
Contracts realized/settled		(17,729	)		(32,981	)
Fair value of new contracts		(555	)		531
Other changes in value		11,732			108,856
Fair value of contracts at end of period	$	(85,829	)	$	26,806

The fair value of our natural gas distribution segment’s financial instruments at December 31, 2011 is presented below by time period and fair value source:

	Fair Value of Contracts at December 31, 2011
	Maturity in Years
Source of Fair Value	Less Than 1			1-3			4-5		Greater Than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(15,904	)	$	(69,925	)	$	—	$	—	$	(85,829	)
Prices based on models and other valuation methods		—			—			—		—		—
Total Fair Value	$	(15,904	)	$	(69,925	)	$	—	$	—	$	(85,829	)

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The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three months ended December 31, 2011 and 2010:

	Three Months Ended December 31
	2011			2010
	(In thousands)
Fair value of contracts at beginning of period	$	(25,050	)	$	(12,374	)
Contracts realized/settled		17,449			934
Fair value of new contracts		—			—
Other changes in value		(7,662	)		759
Fair value of contracts at end of period		(15,263	)		(10,681	)
Netting of cash collateral		22,084			25,296
Cash collateral and fair value of contracts at period end	$	6,821		$	14,615

The fair value of our nonregulated segment’s financial instruments at December 31, 2011 is presented below by time period and fair value source:

	Fair Value of Contracts at December 31, 2011
	Maturity in Years
Source of Fair Value	Less Than 1			1-3		4-5			Greater Than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(15,975	)	$	734	$	(22	)	$	—	$	(15,263	)
Prices based on models and other valuation methods		—			—		—			—		—
Total Fair Value	$	(15,975	)	$	734	$	(22	)	$	—	$	(15,263	)

Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2011 and 2010, our total net periodic pension and other benefits cost was $17.3 million and $14.9 million. Those costs relating to our natural gas distribution operations are generally 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 2012 costs were determined using a September 30, 2011 measurement date. As of September 30, 2011, interest and corporate bond rates utilized to determine our discount rates, were lower than the interest and corporate bond rates as of September 30, 2010, the measurement date for our fiscal 2011 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2012 pension and benefit costs to 5.05 percent. We reduced the expected return on our pension plan assets to 7.75 percent, based on historical experience and the current market projection of the target asset allocation. Accordingly, our fiscal 2012 pension and postretirement medical costs for the quarter ended December 31, 2011 were higher than the prior-year quarter.

The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. Based upon the most recent evaluation, we anticipate contributing between $25 million and $30 million to our defined benefit plans in fiscal 2012. 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 between $20 million and $25 million to these plans during fiscal 2012.

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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-month periods ended December 31, 2011 and 2010.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations

	Three Months Ended December 31
	2011		2010
METERS IN SERVICE, end of period
Residential		2,847,305		2,848,433
Commercial		258,749		261,494
Industrial		2,318		2,328
Public authority and other		10,253		10,158
Total meters		3,118,625		3,122,413
INVENTORY STORAGE BALANCE — Bcf(1)		58.1		55.6
SALES VOLUMES — MMcf (2)
Gas sales volumes
Residential		50,240		50,156
Commercial		26,604		26,029
Industrial		5,412		5,146
Public authority and other		2,634		2,806
Total gas sales volumes		84,890		84,137
Transportation volumes		33,967		33,217
Total throughput		118,857		117,354
OPERATING REVENUES (000’s)(2)
Gas sales revenues
Residential	$	437,509	$	443,639
Commercial		189,688		189,265
Industrial		26,707		28,689
Public authority and other		17,494		18,537
Total gas sales revenues		671,398		680,130
Transportation revenues		14,862		15,691
Other gas revenues		7,032		7,641
Total operating revenues	$	693,292	$	703,462
Average transportation revenue per Mcf(1)	$	0.44	$	0.48
Average cost of gas per Mcf sold(1)	$	4.78	$	4.92

See footnote following these tables.

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Natural Gas Distribution Sales and Statistical Data — Discontinued Operations

	Three Months Ended December 31
	2011		2010
Meters in service, end of period		84,383		83,873
Sales volumes — MMcf
Total gas sales volumes		2,429		2,653
Transportation volumes		1,597		1,536
Total throughput		4,026		4,189
Operating revenues (000’s)	$	23,451	$	23,733

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data

	Three Months Ended December 31
	2011		2010
CUSTOMERS, end of period
Industrial		771		749
Municipal		69		62
Other		516		512
Total		1,356		1,323
NONREGULATED INVENTORY STORAGE BALANCE — Bcf		27.9		22.1
REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf(2)		160,829		153,178
NONREGULATED DELIVERED GAS SALES VOLUMES — MMcf(2)		106,462		107,712
OPERATING REVENUES (000’s)(2)
Regulated transmission and storage	$	56,759	$	49,007
Nonregulated		444,176		475,640
Total operating revenues	$	500,935	$	524,647

Note to preceding tables:

⁽¹⁾  Statistics are shown on a consolidated basis.

⁽²⁾  Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

RECENT ACCOUNTING DEVELOPMENTS

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three months ended December 31, 2011, there were no material changes in our quantitative and qualitative disclosures about market risk.

Item 4. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure

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controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 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 in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of the fiscal year ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

During the three months ended December 31, 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 13 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. 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 2. Unregistered Sales of Equity Securities and Use of Proceeds

On September 28, 2011, the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. Although the program is authorized for a five-year period, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the company deems appropriate. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the company. As of December 31, 2011, 387,991 shares had been repurchased.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1, 2011 to October 31, 2011		—	$	—		—		5,000,000
November 1, 2011 to November 30, 2011		77,818		32.51		77,818		4,922,182
December 1, 2011 to December 31, 2011		310,173		32.26		310,173		4,612,009
Total		387,991	$	32.31		387,991		4,612,009

Item 6. Exhibits

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

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SIGNATURE

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

ATMOS ENERGY CORPORATION                (Registrant)
By:	/s/    FRED E. MEISENHEIMER
	Fred E. Meisenheimer Senior Vice President and Chief Financial Officer (Duly authorized signatory)

Date: February 8, 2012

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EXHIBITS INDEX

Item 6

Exhibit Number	Description	Page Number or Incorporation by Reference to
10.1	Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2012
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 on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

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

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EX-10.1

Exhibit 10.1

ATMOS ENERGY CORPORATION EQUITY INCENTIVE

AND DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS

AMENDED AND RESTATED AS OF JANUARY 1, 2012

The Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors (the “Plan”) was an amendment and restatement of the Atmos Energy Corporation Deferred Compensation Plan for Outside Directors adopted by the Company on May 10, 1990, as subsequently amended and restated on August 12, 1998, and was adopted by the Board of Directors of Atmos Energy Corporation, a Texas and Virginia corporation (hereinafter called the “Company”) on August 7, 2007. The Plan was subsequently amended and restated as of January 1, 2010. This Plan document is designed to supersede the amended and restated Plan and includes all terms and provisions of the Plan. The amendments to this amended and restated Plan were adopted by the Board of Directors of the Company on November 8, 2011.

ARTICLE 1

PURPOSE

The Plan, as amended, allows each non-employee Director to defer receipt of his or her annual retainer fee, to invest his or her deferred fee in either a cash account or a stock account, and to receive an annual grant of share units to be credited to his or her stock account for each year the non-employee Director serves on the Company’s Board of Directors. The Plan, as amended, is intended to encourage qualified individuals to accept nominations as Directors of the Company and to strengthen the mutuality of interests between the non-employee Directors and the Company’s other shareholders.

ARTICLE 2

DEFINITIONS

The following are defined terms wherever they appear in the Plan:

2.1 “Board of Directors” or “Board” shall mean the Board of Directors of Atmos Energy Corporation.

2.2(a) “Change in Control” of the Company occurs upon a change in the Company’s ownership, its effective control or the ownership of a substantial portion of its assets, as follows:

(i) Change in Ownership. A change in ownership of the Company occurs on the date that any “Person” (as defined in Section 2.2(b) below), other than (1) the Company or any of its subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of the Company’s stock, acquires ownership of the Company’s stock that, together with stock held by such Person, constitutes more than 50% of the total fair market value or total voting power of the Company’s stock. However, if any Person is considered to own already more than 50% of the total fair market value or total voting power of the Company’s stock, the acquisition of additional stock by the

same Person is not considered to be a Change of Control. In addition, if any Person has effective control of the Company through ownership of 30% or more of the total voting power of the Company’s stock, as discussed in paragraph (ii) below, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this paragraph (i); or

(ii) Change in Effective Control. Even though the Company may not have undergone a change in ownership under paragraph (i) above, a change in the effective control of the Company occurs on either of the following dates:

(A) the date that any Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Company’s stock possessing 30 percent or more of the total voting power of the Company’s stock. However, if any Person owns 30% or more of the total voting power of the Company’s stock, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (ii)(A); or

(B) the date during any 12-month period when a majority of members of the Board is replaced by directors whose appointment or election is not endorsed by a majority of the Board before the date of the appointment or election; provided, however, that any such director shall not be considered to be endorsed by the Board if his or her initial assumption of office occurs as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(iii) Change in Ownership of Substantial Portion of Assets. A change in the ownership of a substantial portion of the Company’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Company, that have a total gross fair market value equal to at least 40% of the total gross fair market value of all of the Company’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the shareholders of the Company immediately after the transfer, through a transfer to (A) a shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to the Company’s stock; (B) an entity, at least 50% of the total value or voting power of the stock of which is owned, directly or indirectly, by the Company; (C) a Person that owns directly or indirectly, at least 50% of the total value or voting power of the Company’s outstanding stock; or (D) an entity, at least 50% of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least 50% of the total value or voting power of the Company’s outstanding stock.

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(b) For purposes of Section 2.2(a) above,

(i) “Person” shall have the meaning given in Code Section 7701(a)(1). Person shall include more than one Person acting as a group as defined by the Final Treasury Regulations issued under Section 409A of the Code.

(ii) “Affiliate” shall have the meaning set forth in Rule 12b-2 promulgated under Section 12 of the Securities Exchange Act of 1934, as amended.

(c) The provisions of this Section 2.2 shall be interpreted in accordance with the requirements of the Final Treasury Regulations under Code Section 409A, it being the intent of the parties that this Section 2.2 shall be in compliance with the requirements of said Code Section and said Regulations.

2.3 “Cash Account” means the Sub-Account under the Plan to which the Director may voluntarily elect to defer his or her Fee (as defined below) for payment at a specified future date, under the terms and provisions of the Plan.

2.4 “Code” means the Internal Revenue Code of 1986, as amended, together with the published rulings, regulations, and interpretations duly promulgated thereunder.

2.5 “Company” means Atmos Energy Corporation, a Texas and Virginia Corporation, and any successor entity.

2.6 “Common Stock” means the Common Stock of the Company, with no par value (stated value of $.005 per share), or such other security or right or instrument into which such Common Stock may be changed or converted in the future.

2.7 “Director” means a member of the Board of Directors who is not employed by the Company or any of its Subsidiaries.

2.8 “Fair Market Value” of a share of Common Stock, as of any specified date, is the mean of the highest and lowest prices per share on the New York Stock Exchange Consolidated Tape on that date. However, if no trading in the Common Stock occurs on the New York Stock Exchange on that date, the “Fair Market Value” shall mean the mean of the highest and lowest prices as reported on the most recent previous day for which sales were reported. In the event the Common Stock is traded on an exchange other than the New York Stock Exchange, the Board of Directors shall select a suitable substitute published stock quotation system, which system shall be in compliance with all relevant regulatory provisions.

2.9 “Fee” means the annual retainer fee (paid in quarterly installments) earned by a Director for his or her service as a member of the Board of Directors during a Plan Year or portion thereof.

2.10 “Plan” means the Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2012, as described herein and as amended from time to time.

2.11 “Plan Benefits” means the benefits described in Articles 5 and 6 hereof.

2.12 “Plan Year” means the calendar year.

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2.13 “Quarter” means the 3-month period beginning January 1, April 1, July 1 or October 1 of each Plan Year.

2.14 “Share Unit” means a notional share that is a fictitious share whose value at any point in time is always equal to the Fair Market Value of a share of the Common Stock of the Company at such point in time.

2.15 “Stock Account” means the Sub-Account under the Plan to which the Director may voluntarily elect to defer his or her Fee, and to which the periodic grants of Share Units are credited, for payment at a specified future date, under the terms and provisions of the Plan.

2.16 “Sub-Account” means the Cash Account, the Stock Account, or both.

2.17 “Termination of Service” means with respect to each Director a “separation from service” as a Director, as defined in Section 1.409A-1(h) of the Final Treasury Regulations under Code Section 409A, or any successor provision thereto.

ARTICLE 3

ADMINISTRATION

The Plan shall be administered by the Board of Directors. The Board of Directors shall have the full authority to construe and interpret the Plan, and any action of the Board of Directors with respect to the Plan shall be final, conclusive, and binding on all persons. Subject to adjustment as provided in Section 7.8 hereof, the total number of shares of Common Stock reserved for issuance under the Plan shall be 150,000.

ARTICLE 4

GRANTS OF SHARE UNITS

From and after the Effective Date (as defined in Section 7.11), each Plan Year, the Board may grant to each Director such number of Share Units, if any, as the Board may determine. The grants will occur on the 30^th day following the Company’s Annual Meeting of Shareholders each Plan Year.

ARTICLE 5

SUB-ACCOUNT CREDITS AND INVESTMENTS

5.1 Sub-Accounts. On or before the December 31 immediately preceding the start of the next Plan Year, each Director participating in the Plan shall designate the Sub-Account into which any Fee earned for such next succeeding Plan Year shall be credited for the Plan Year. The Director may elect to have the Fee credited to either Sub-Account in increments of ten percent (10%). Except as otherwise provided herein, the Fee allocated to a Sub-Account may not thereafter be allocated to the other Sub-Account.

5.2 Cash Account. The amount of the Fee allocated as a credit to the Cash Account shall be converted to a cash balance as of the first business day of each Quarter to be credited with interest in the means set forth below.

4

(a) The balance in the Cash Account prior to any additional allocations or credits of the Fee for such month, if any, shall be credited with interest equal to one-twelfth of the Annual Interest Rate.

(b) The Annual Interest Rate for each applicable Plan Year will be equal to the sum of (i) 2.5 percent, plus (ii) the annual yield reported on a 10-year Treasury Bond for the first business day of January for each Plan Year, as reported in the Wall Street Journal.

5.3 Stock Account. The amount of the Fee allocated as a credit to the Stock Account shall be converted to Share Units as described below. Any Fee payable for a Quarter shall be converted to a number of whole and, if applicable, fractional Share Units on the first business day of that Quarter. Share Units shall be credited with dividend equivalents as and when dividends are declared on shares of Common Stock, and such dividend equivalents shall be converted to whole and, if applicable, fractional Share Units on the business day on which the dividends are declared on the shares of Common Stock.

ARTICLE 6

PLAN BENEFITS

6.1 Form. Plan Benefits of a Director shall be comprised of two forms. Plan Benefits paid from the Cash Account shall be paid in the form of cash. Plan Benefits paid from the Stock Account shall be paid in the form of shares of Common Stock equal in number to whole Share Units in the Director’s Stock Account. Any fractional Share Unit shall be rounded up to a whole Share Unit prior to distribution.

6.2 Distribution.

(a) A Director’s Plan Benefits payable from either the Cash Account or the Stock Account, shall be distributed at the time of the Director’s Termination of Service in a single lump sum, unless the Director elected to receive distribution of either the Cash Account or the Stock Account or both in installments under the terms of the prior Plan.

(b) In the case of the death of a Director, the Director’s Plan Benefits shall be distributed, within a reasonable time as determined by the Company, after the Director’s death to the Director’s beneficiary or beneficiaries, as specified by the Director on a form furnished by and filed with the Corporate Secretary of the Company. If no beneficiary has been designated by the Director or if no designated beneficiary survives the Director, the undistributed balance of his or her Plan Benefit shall be distributed to the Director’s surviving spouse as beneficiary if such spouse is still living or, his or her children, if any, per stripes as beneficiary, or, if none, to the Director’s estate as beneficiary. Any such Plan Benefits shall be payable in a lump sum, unless the Director elected payment in installments as described in Section 6.2(a).

ARTICLE 7

GENERAL PROVISIONS AND TERMS

7.1 Change in Control. In the event of an occurrence of a Change in Control as defined herein, the Company or its successor organization shall be required to fully fund the Cash Account and Stock Account Plan Benefits through a grantor trust arrangement established by the Company for the express purpose of the Plan. Such financing of the grantor trust shall occur within 20 business days following the date of the Change in Control and within 10 business days following any subsequent increase in the value of the Cash Account or Stock Account.

5

7.2 Nontransferability. Except as provided in Article 6.2(b) above, no payment of any Plan Benefit of a Director shall be anticipated, assigned, attached, garnished, optioned, transferred or made subject to any creditor’s process, whether voluntarily or involuntarily or by operation of law. Any act in violation of this subsection shall be void.

7.3 Compliance with Legal and Trading Requirements. The Plan shall be subject to all applicable laws, rules and regulations, including but not limited to, federal and state laws, rules and regulations, and to such approvals by any regulatory or governmental agency as may be required. No provision of the Plan shall be interpreted or construed to obligate the Company to register any shares of Common Stock under federal or state securities laws. The transfer by a Director of shares of Common Stock distributed pursuant to the Plan will be subject to such restrictions as the Company deems necessary or desirable in connection with federal or state securities laws, and Common Stock certificates will bear a legend setting forth any such restriction.

7.4 Taxes. The Company is authorized to withhold from any payment made under this Plan any amount of withholding and other taxes due in connection therewith, and to take such other action as the Company may deem advisable to enable the Company and a Director to satisfy obligations for the payment of any withholding taxes and other tax obligations relating thereto.

7.5 Amendment or Termination. The Board may amend, alter, suspend, discontinue, or terminate the Plan without the consent of shareholders of the Company or individual Directors; provided, however, that, (i) without the consent of an affected Director, no amendment, alteration, suspension, discontinuation, or termination of the Plan may materially impair the rights or, in any other manner, materially and adversely affect the rights of such Director hereunder to the Plan Benefits then credited to his or her Sub-Accounts, and (ii) no amendment, alteration, suspension, discontinuation, or termination of the Plan shall change the time or form of payment hereunder, unless such change is otherwise in compliance with the requirements of Code Section 409A and the Treasury Regulations issued thereunder.

7.6 Unfunded Status of Awards. This Plan is intended to constitute an “unfunded” plan of deferred compensation. With respect to any payments not yet made to a Director, nothing contained in the Plan shall give any such Director any rights that are greater than those of a general unsecured creditor of the Company; provided, however, subject to Article 7.1 hereof, that the Company may authorize the creation of trusts or make other arrangements to meet the Company’s obligations under the Plan to deliver cash or other property, which trusts or other arrangements shall be consistent with the “unfunded” status of the Plan unless the Company otherwise determines with the consent of each affected Director.

7.7 Nonexclusivity of the Plan. The adoption of the Plan by the Board shall not be construed as creating any limitations on the power of the Board to adopt such other compensation arrangements and other awards otherwise than under the Plan as it may deem desirable, and such arrangements and other awards may be either applicable generally or only in specific cases.

7.8 Adjustments. In the event that subsequent to the effective date of the Plan any dividend in shares of Common Stock, recapitalization, Common Stock split, reverse split, reorganization, merger, consolidation, spin-off, combination, repurchase, or exchange, or other such change, affects the shares of Common Stock such that they are increased or decreased or changed into or exchanged for a different number or kind of shares of Common Stock, other securities of the Company or of another corporation or other consideration, then in order to maintain the proportionate interest of the Directors and preserve the value of the Directors’ Share Units and to maintain the value of the Plan there shall automatically be substituted (i) for each Share Unit a new Share Unit and (ii) for the number of shares of Common Stock set forth in Section 3 above a number of shares of Common Stock or other consideration, in the case of (i) and (ii) above, representing the number and kind of shares of Common Stock, other securities or other consideration into which each outstanding share of Common Stock shall be changed or for which each share of Common Stock shall be exchanged. The substituted units shall be subject to the same terms and conditions as the original Share Units.

6

7.9 No Right to Remain on the Board. Neither the Plan nor the crediting of Share Units under the Plan shall be deemed to give any individual a right to remain a Director of the Company or create any obligation on the part of the Board to nominate any Director for reelection by the shareholders of the Company.

7.10 Governing Law. The validity, construction, and effect of the Plan shall be determined in accordance with the laws of Texas without giving effect to principles of conflict of laws.

7.11 Effective Date. The Effective Date for purposes of the most recent amendments to the Plan is January 1, 2012.

7.12 Titles and Headings. The titles and heading of those Articles in the Plan are for convenience of reference only. In the event of any conflict, the text of the Plan, rather than such titles or headings, shall control.

7.13 Indemnification. No member of the Board, nor any officer or Employee of the Company acting on behalf of the Board, shall be personally liable for any action, determination, or interpretation taken or made in good faith with respect to the Plan, and all members of the Board and each and any officer or Employee of the Company acting on their behalf shall, to the extent permitted by law, be fully indemnified and protected by the Company in respect of any such action, determination, or interpretation. Notwithstanding the foregoing, to the extent it is determined that the indemnification provided herein constitutes a deferral of compensation for purposes of Code Section 409A, then (i) the amount provided as indemnification during a calendar year shall not affect the amount eligible for indemnification in any other calendar year, and (ii) payment of indemnification amounts shall be made on or before the last day of the calendar year following the calendar year in which such amounts subject to indemnification were incurred.

IN WITNESS WHEREOF, the Company has caused this instrument to be executed this 29^th day of December, 2011 by its President and Chief Executive Officer pursuant to prior action taken by the Board.

ATMOS ENERGY CORPORATION
By:	/s/ KIM R. COCKLIN
	Kim R. Cocklin
	President and Chief Executive Officer

Attest:

/s/ DWALA KUHN

Dwala Kuhn

Corporate Secretary

7

EX-12

Exhibit 12

Atmos Energy Corporation

Computation of Earnings to Fixed Charges

December 31, 2011

	Three Months Ended December 31
	2011		2010
	(Dollars in thousands)
Income from continuing operations before provision for income taxes per statement of income	$	107,090	$	115,668
Add:
Portion of rents representative of the interest factor		1,796		1,833
Interest on debt & amortization of debt expense		35,442		38,895
Income as adjusted	$	144,328	$	156,396
Fixed charges:
Interest on debt & amortization of debt expense(1)	$	35,442	$	38,895
Capitalized interest(2)		831		523
Rents		5,388		5,498
Portion of rents representative of the interest factor(3)		1,796		1,833
Fixed charges(1)+(2)+(3)	$	38,069	$	41,251
Ratio of earnings to fixed charges		3.79		3.79

EX-15

Exhibit 15

Board of Directors

Atmos Energy Corporation

We are aware of the incorporation by reference in the Registration Statements (Form S-3, No. 33-37869; Form S-3, No. 33-58220; Form S-3D/A, No. 33-70212; Form S-3, No. 33-56915; Form S-3/A, No. 333-03339; Form S-3/A, No. 333-32475; Form S-3/A, No. 333-50477; Form S-3, No. 333-95525; Form S-3/A, No. 333-93705; Form S-3, No. 333-75576; Form S-3D, No. 333-113603; Form S-3, No. 333-118706; Form S-3D, No. 333-155666; Form S-3ASR, No. 333-165818; Form S-4, No. 333-13429; Form S-8, No. 33-57695; Form S-8, No. 33-57687; Form S-8, No. 333-32343; Form S-8, No. 333-46337; Form S-8, No. 333-73145; Form S-8, No. 333-73143; Form S-8, No. 333-63738; Form S-8, No. 333-88832; Form S-8, No. 333-116367; Form S-8, No. 333-138209; Form S-8, No. 333-145817; Form S-8, No. 333-155570; Form S-8, No. 333-166639; and Form S-8, No. 333-177593) of Atmos Energy Corporation and in the related Prospectuses of our report dated February 8, 2012, relating to the unaudited condensed consolidated interim financial statements of Atmos Energy Corporation, which are included in its Form 10-Q for the quarter ended December 31, 2011.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 8, 2012

EX-31

EXHIBIT 31

RULE 13a-14(a)/15d-14(a) CERTIFICATIONS

I, Kim R. Cocklin, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Atmos Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 8, 2012

/s/ KIM R. COCKLIN

Kim R. Cocklin

President and

Chief Executive Officer

I, Fred E. Meisenheimer, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Atmos Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing equivalent functions):

(a) All significant deficiencies or material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 8, 2012

/s/ FRED E. MEISENHEIMER

Fred E. Meisenheimer

Senior Vice President and

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Quarterly Report of Atmos Energy Corporation (the “Company”) on Form 10-Q for the first quarter of the fiscal year ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kim R. Cocklin, President and Chief Executive Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 8, 2012

/s/ KIM R. COCKLIN

Kim R. Cocklin

President and Chief

Executive Officer

A signed original of this written statement has been provided to Atmos Energy Corporation and will be retained by Atmos Energy Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Quarterly Report of Atmos Energy Corporation (the “Company”) on Form 10-Q for the first quarter of the fiscal year ended September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Fred E. Meisenheimer, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 8, 2012

/s/ FRED E. MEISENHEIMER

Fred E. Meisenheimer

Senior Vice President and

Chief Financial Officer

A signed original of this written statement has been provided to Atmos Energy Corporation and will be retained by Atmos Energy Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Commitments and Contingencies (Details) (USD $)	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Long Term Commitment Purchases Abstract
Significant Purchase Commitment Amount Description	$ 312,100,000	$ 334,200,000
Long Term Purchase Commitment Abstract
Significant Purchase Commitment Remaining Minimum Amount Committed Current Fiscal Year	149,788,000
Significant Purchase Commitment Remaining Minimum Amount Committed Next Fiscal Year	82,778,000
Significant Purchase Commitment Remaining Minimum Amount Committed Second Fiscal Year	68,124,000
Significant Purchase Commitment Remaining Minimum Amount Committed Thereafter	0
Total Estimated Purchase Commitments	300,690,000
Other Matters [Abstract]
Steel Service Line Replacement Cost	64,000,000
Description of Regulatory Matters	As previously described in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, 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. Since that time, we have fully cooperated with the Commission during this investigation. The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission’s findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company has paid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company’s financial position, results of operations or cash flows and none of the payments were charged to any of the Company’s customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.
Inventories Under Indexed Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year	103,100,000,000
Long Term Purchase Commitment Minimum Quantity Required One To Three Years	35,300,000,000
Long Term Purchase Commitment Minimum Quantity Required After Three Years	300,000,000
Inventories Under Fixed Price Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year	3,400,000,000
Long Term Purchase Commitment Minimum Quantity Required One To Three Years	200,000,000
Purchase Commitment Amount Minimum	2.82
Purchase Commitment Amount Maximum	$ 6.36

XML

Fair Value Measurements (Details) (USD $)	Dec. 31, 2011	Sep. 30, 2011
Fair Value Abstract
Cash Collateral Right To Reclaim Cash	$ 22,100,000	$ 28,800,000
Debt Instrument Fair Value	2,572,094,000
Cash Held In Margin Accounts Offset Current Risk Management Liabilities	11,400,000	12,400,000
Cash Held In Margin Accounts Classified Current Risk Management Asset	10,700,000	16,400,000
Fair Value Inputs Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Assets	33,768,000	15,262,000
Total financial instruments	33,768,000	15,262,000
Hedged portion of gas stored underground	77,551,000	47,940,000
Available For Sale Securities Equity Securities	38,008,000	36,444,000
Available For Sale Securities Debt Securities	0	0
Available-for-sale securities money market funds	0	0
Fair value	38,008,000	36,444,000
Total assets	149,327,000	99,646,000
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Liabilities	51,117,000	22,091,000
Total liabilities	51,117,000	22,091,000
Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas distribution segment	472,000	1,841,000
Nonregulated Segement Derivative Assets	256,098,000	97,396,000
Total financial instruments	256,570,000	99,237,000
Hedged portion of gas stored underground	0	0
Available For Sale Securities Equity Securities	0	0
Available For Sale Securities Debt Securities	18,346,000	14,366,000
Available-for-sale securities money market funds	1,151,000	1,823,000
Fair value	19,497,000	16,189,000
Total assets	276,067,000	115,426,000
Natural gas distribution segment	86,301,000	81,118,000
Nonregulated Segement Derivative Liabilities	254,012,000	115,617,000
Total liabilities	340,313,000	196,735,000
Fair Value Inputs Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Assets	0	0
Total financial instruments	0	0
Hedged portion of gas stored underground	0	0
Available For Sale Securities Equity Securities	0	0
Available For Sale Securities Debt Securities	0	0
Available-for-sale securities money market funds	0	0
Fair value	0	0
Total assets	0	0
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Liabilities	0	0
Total liabilities	0	0
Netting And Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Assets	(272,938,000)	(95,156,000)
Total financial instruments	(272,938,000)	(95,156,000)
Hedged portion of gas stored underground	0	0
Available For Sale Securities Equity Securities	0	0
Available For Sale Securities Debt Securities	0	0
Available-for-sale securities money market funds	0	0
Fair value	0	0
Total assets	(272,938,000)	(95,156,000)
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Liabilities	(295,022,000)	(123,943,000)
Total liabilities	$ (295,022,000)	$ (123,943,000)

XML

Discontinued Operations (Table)

3 Months Ended

Dec. 31, 2011

Discontinued Operations Table Abstract

Discontinued operations income statement detail table

			Three Months Ended
			December 31
			2011		2010
			(In thousands)
Operating revenues			$	23,451	$	23,733
Purchased gas cost				14,951		14,897
	Gross profit			8,500		8,836
Operating expenses				4,174		4,016
Operating income				4,326		4,820
Other nonoperating expense				(48)		(33)
Income from discontinued
	operations before income taxes			4,278		4,787
Income tax expense				1,559		1,890
		Net income	$	2,719	$	2,897

Assets held for sale table

		December 31,		September 30,
		2011		2011
		(In thousands)
Net plant, property & equipment		$	127,227	$	127,577
Gas stored underground			14,257		11,931
Other current assets			3,773		786
Deferred charges and other assets			62		277
	Assets held for sale	$	145,319	$	140,571
Accounts payable and accrued liabilities		$	9,945	$	1,917
Other current liabilities			5,459		4,877
Regulatory cost of removal obligation			10,367		10,498
Deferred credits and other liabilities			1,175		1,153
	Liabilities held for sale	$	26,946	$	18,445

XML

Earnings Per Share (Details) (USD $)	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Basic Earnings per Share from Continuing Operations
Income (loss) from continuing operations	$ 65,788,000	$ 71,100,000
Less: Income (loss) from continuing operations allocated to participating securities	685,000	748,000
Income (loss) from continuing operations available to common shareholders	65,103,000	70,352,000
Income Loss From Continuing Operations Per Basic Share	$ 0.72	$ 0.78
Basic Earnings per Share from Discontinued Operations
Income (loss) from discontinued operations	2,719,000	2,897,000
Less: Income (loss) from discontinued operations allocated to participating securities	28,000	31,000
Income (loss) from discontinued operations available to common shareholders	2,691,000	2,866,000
Income (loss) from discontinued operations per share - Basic	$ 0.03	$ 0.03
Basic net income (loss) per share	$ 0.75	$ 0.81
Basic	90,254,000	90,082,000
Diluted Earnings per Share from Continuing Operations
Effect of dilutive stock options and other shares	1,000	2,000
Income (loss) from continuing operations available to common shareholders	65,104,000	70,354,000
Additional dilutive stock options and other shares	292,000	326,000
Diluted	90,546,000	90,408,000
Income Loss From Continuing Operations Per Diluted Share	$ 0.72	$ 0.78
Diluted Earnings per Share from Discontinued Operations
Effect of dilutive stock options and other shares	0	0
Income (loss) from discontinued operations available to common shareholders	2,691,000	2,866,000
Additional dilutive stock options and other shares	292,000	326,000
Diluted weighted average shares outstanding	90,546,000	90,408,000
Income (loss) from discontinued operations per share - Diluted	$ 0.03	$ 0.03
Diluted net income (loss) per share	$ 0.75	$ 0.81
Earnings Per Share Diluted Other Disclosures Abstract
Share Repurchase Program - Shares Purchased	387,991
Share Repurchase Program - Number of Shares Authorized	5,000,000
Share Repurchase Program - Years Authorized	5
Share Repurchase Program - Amount Purchased	$ 12,500,000

XML

3. Financial Instruments

3 Months Ended

Dec. 31, 2011

Derivative Instruments And Hedging Activities Disclosure Abstract

3. Financial Instruments

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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the first quarter there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions.

Regulated Commodity Risk Management Activities

Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

Our natural gas distribution gas supply department is responsible for executing this segment's commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2011-2012 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 25 percent, or 25.7 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges.

The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas costs adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas costs 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

The primary business in our nonregulated operations is to aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. We utilize proprietary and customer-owned transportation and storage assets to serve these customers, and will seek to maximize the value of this storage capacity through the arbitrage of pricing differences that occur over time by selling financial instruments at advantageous prices to lock in a gross profit margin to enhance our gross profit by maximizing the economic value associated with the storage and transportation capacity we own or control.

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. Future contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.

We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 59 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.

Also, in our nonregulated operations, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges.

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.

As of December 31, 2011, we had three Treasury lock agreements outstanding to fix the Treasury yield component of $350 million 30-year unsecured notes,which we plan to issue to refinance our $250 million unsecured 5.125% Senior Notes that mature in January 2013.

In prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled 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 December 31, 2011, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2011, we had net long/(short) commodity contracts outstanding in the following quantities:

		Natural
	Hedge	Gas
Contract Type	Designation	Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	-	(26,690)
	Cash Flow	-	44,428
	Not designated	13,964	46,944
		13,964	64,682

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2011 and September 30, 2011. 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 $22.1 million and $28.8 million of cash held on deposit as of December 31, 2011 and September 30, 2011 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.

						Natural
						Gas
				Balance Sheet Location		Distribution		Nonregulated		Total
December 31, 2011:						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	60,222	$	60,222
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		58		58
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			-		(57,988)		(57,988)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(69,755)		(12,012)		(81,767)
	Total						(69,755)		(9,720)		(79,475)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			292		148,669		148,961
		Noncurrent commodity		Deferred charges and
			contracts		other assets		180		80,916		81,096
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(16,196)		(166,878)		(183,074)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(350)		(68,250)		(68,600)
	Total						(16,074)		(5,543)		(21,617)
Total Financial Instruments						$	(85,829)	$	(15,263)	$	(101,092)

(1) Other current liabilities not designated as hedges in our natural gas distribution segment include $1.7 million related to risk management liabilities that were classified as assets held for sale at December 31, 2011.

						Natural
						Gas
				Balance Sheet Location		Distribution		Nonregulated		Total
September 30, 2011:						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	22,396	$	22,396
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		174		174
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			-		(31,064)		(31,064)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(67,527)		(7,709)		(75,236)
	Total						(67,527)		(16,203)		(83,730)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			843		67,710		68,553
		Noncurrent commodity		Deferred charges and
			contracts		other assets		998		22,379		23,377
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(13,256)		(73,865)		(87,121)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(335)		(25,071)		(25,406)
	Total						(11,750)		(8,847)		(20,597)
Total Financial Instruments						$	(79,277)	$	(25,050)	$	(104,327)

(1) Other current liabilities not designated as hedges in our natural gas distribution segment include $1.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2011.

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 December 31, 2011 and 2010 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $8.4 million and $13.5million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2011 and 2010 is presented below.

		Three Months Ended
		December 31
		2011		2010
		(In thousands)
Commodity contracts		$	24,064	$	(1,723)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(15,249)		15,625
Total impact on revenue		$	8,815	$	13,902
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	841	$	921
	Timing ineffectiveness		7,974		12,981
		$	8,815	$	13,902

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.

To the extent that the Company's natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. During the three months ended December 31, 2011, we recorded a $1.7 million charge to writedown nonqualifying natural gas inventory to market.We did not record a writedown for nonqualifying natural gas inventory for the three months ended December 31, 2010.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2011 and 2010 is presented below.Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

		Three Months Ended December 31, 2011
		Natural
		Gas
		Distribution		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	(11,642)	$	(11,642)
Loss arising from ineffective portion of
	commodity contracts		-		(430)		(430)
Total impact on revenue			-		(12,072)		(12,072)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(502)		-		(502)
Total Impact from Cash Flow Hedges		$	(502)	$	(12,072)	$	(12,574)
		Three Months Ended December 31, 2010
		Natural
		Gas
		Distribution		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	(14,253)	$	(14,253)
Loss arising from ineffective portion of
	commodity contracts		-		(444)		(444)
Total impact on revenue			-		(14,697)		(14,697)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(670)		-		(670)
Total Impact from Cash Flow Hedges		$	(670)	$	(14,697)	$	(15,367)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three months ended December 31, 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
		December 31
		2011		2010
		(In thousands)
Increase (decrease) in fair value:
	Treasury lock agreements	$	(1,403)	$	31,425
	Forward commodity contracts		(23,678)		1,657
Recognition of losses in earnings due to settlements:
	Treasury lock agreements		316		422
	Forward commodity contracts		7,103		8,693
Total other comprehensive income (loss)
	from hedging, net of tax(1)	$	(17,662)	$	42,197

(1)Utilizing an income tax rate ranging from37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with ourTreasury lock agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred gains (losses) associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2011. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock agreements as those instruments have not yet settled.

	Treasury
	Lock		Commodity
	Agreements		Contracts		Total
	(In thousands)
Next twelve months	$	(1,266)	$	(25,900)	$	(27,166)
Thereafter		9,967		(7,536)		2,431
Total(1)	$	8,701	$	(33,436)	$	(24,735)

(1)Utilizing an income tax rate ranging from 37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statement for the three months ended December 31, 2011and 2010 was an increase(decrease) in revenue of ($2.2) million and $4.2 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.

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.

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Commitments and Contingencies (Table)

3 Months Ended

Dec. 31, 2011

Commitments and Contingencies Tables Abstract

Long-term supply contracts purchase commitments table

2012	$	149,788
2013		82,778
2014		68,124
Thereafter		-
	$	300,690

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Interim Pension and Other Postretirement Benefits (Table)

3 Months Ended

Dec. 31, 2011

Interim Pension And Other Postretirement Benefit Plan Tables Abstract

Components of net periodic pension cost table

			Three Months Ended December 31
			Pension Benefits				Other Benefits
			2011		2010		2011		2010
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	4,298	$	4,380	$	4,088	$	3,601
	Interest cost			6,677		6,924		3,465		3,203
	Expected return on assets			(5,368)		(5,963)		(652)		(682)
	Amortization of transition asset			-		-		378		378
	Amortization of prior service cost			(35)		(112)		(362)		(362)
	Amortization of actuarial loss			4,142		3,494		662		87
		Net periodic pension cost	$	9,714	$	8,723	$	7,579	$	6,225

Schedule of assumptions used table text block

	Pension Benefits				Other Benefits
	2011		2010		2011		2010
Discount rate	5.05	%	5.39	%	5.05	%	5.39	%
Rate of compensation increase	3.50	%	4.00	%	N/A		N/A
Expected return on plan assets	7.75	%	8.25	%	4.70	%	5.00	%

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Segment Information (Table)

3 Months Ended

Dec. 31, 2011

Segment Information Tables Abstract

Schedule of segment reporting income statement, by segment

		Three Months Ended December 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Eliminations		Consolidated
		(In thousands)
Operating revenues from
	external parties	$	693,068	$	19,440	$	388,665	$	-	$	1,101,173
Intersegment revenues			224		37,319		55,511		(93,054)		-
			693,292		56,759		444,176		(93,054)		1,101,173
Purchased gas cost			402,207		-		428,771		(92,687)		738,291
	Gross profit		291,085		56,759		15,405		(367)		362,882
Operating expenses
	Operation and maintenance		93,414		16,965		6,051		(368)		116,062
	Depreciation and amortization		50,831		7,651		733		-		59,215
	Taxes, other than income		38,479		3,784		935		-		43,198
Total operating expenses			182,724		28,400		7,719		(368)		218,475
Operating income			108,361		28,359		7,686		1		144,407
Miscellaneous income (expense)			(1,756)		(280)		36		125		(1,875)
Interest charges			27,855		7,209		252		126		35,442
Income from continuing
	operations before income taxes		78,750		20,870		7,470		-		107,090
Income tax expense			30,845		7,456		3,001		-		41,302
Income from continuing operations			47,905		13,414		4,469		-		65,788
Income from discontinued
	operations, net of tax		2,719		-		-		-		2,719
	Net income	$	50,624	$	13,414	$	4,469	$	-	$	68,507
Capital expenditures		$	128,733	$	24,120	$	1,541	$	-	$	154,394

		Three Months Ended December 31, 2010
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Eliminations		Consolidated
		(In thousands)
Operating revenues from
	external parties	$	703,261	$	21,233	$	408,768	$	-	$	1,133,262
Intersegment revenues			201		27,774		66,872		(94,847)		-
			703,462		49,007		475,640		(94,847)		1,133,262
Purchased gas cost			412,526		-		450,462		(94,450)		768,538
	Gross profit		290,936		49,007		25,178		(397)		364,724
Operating expenses
	Operation and maintenance		89,229		15,574		10,084		(397)		114,490
	Depreciation and amortization		47,894		5,799		1,084		-		54,777
	Taxes, other than income		34,448		3,553		2,167		-		40,168
Total operating expenses			171,571		24,926		13,335		(397)		209,435
Operating income			119,365		24,081		11,843		-		155,289
Miscellaneous income (expense)			(698)		(282)		290		(36)		(726)
Interest charges			29,697		8,064		1,170		(36)		38,895
Income from continuing
	operations before income taxes		88,970		15,735		10,963		-		115,668
Income tax expense			34,549		5,633		4,386		-		44,568
Income from continuing operations			54,421		10,102		6,577		-		71,100
Income from discontinued
	operations, net of tax		2,897		-		-		-		2,897
	Net income	$	57,318	$	10,102	$	6,577	$	-	$	73,997
Capital expenditures		$	109,499	$	12,739	$	924	$	-	$	123,162

Schedule of segment reporting balance sheet information, by segment

			December 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,328,612	$	855,245	$	62,356	$	-	$	5,246,213
Investment in subsidiaries				672,300		-		(2,096)		(670,204)		-
Current assets
	Cash and cash equivalents			63,031		-		22,129		-		85,160
	Assets from risk
		management activities		292		-		10,732		-		11,024
	Other current assets			912,185		13,418		453,571		(214,117)		1,165,057
	Intercompany receivables			567,587		-		-		(567,587)		-
		Total current assets		1,543,095		13,418		486,432		(781,704)		1,261,241
Intangible assets				-		-		196		-		196
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			180		-		6,196		-		6,376
Deferred charges and other
	assets			359,860		11,297		10,449		-		381,606
			$	7,476,955	$	1,012,341	$	598,244	$	(1,451,908)	$	7,635,632
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,267,762	$	278,515	$	393,785	$	(672,300)	$	2,267,762
Long-term debt				2,206,062		-		131		-		2,206,193
		Total capitalization		4,473,824		278,515		393,916		(672,300)		4,473,955
Current liabilities
	Current maturities of
		long-term debt		-		-		131		-		131
	Short-term debt			583,980		-		-		(193,995)		389,985
	Liabilities from risk
		management activities		14,521		-		4,623		-		19,144
	Other current liabilities			606,357		11,929		170,281		(18,026)		770,541
	Intercompany payables			-		531,126		36,461		(567,587)		-
		Total current liabilities		1,204,858		543,055		211,496		(779,608)		1,179,801
Deferred income taxes				813,423		181,641		(13,505)		-		981,559
Noncurrent liabilities from
	risk management activities			70,105		-		5,484		-		75,589
Regulatory cost of removal
	obligation			437,660		-		-		-		437,660
Deferred credits and other
	liabilities			477,085		9,130		853		-		487,068
			$	7,476,955	$	1,012,341	$	598,244	$	(1,451,908)	$	7,635,632

			September 30, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
				(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,248,198	$	838,302	$	61,418	$	-	$	5,147,918
Investment in subsidiaries				670,993		-		(2,096)		(668,897)		-
Current assets
	Cash and cash equivalents			24,646		-		106,773		-		131,419
	Assets from risk
		management activities		843		-		17,501		-		18,344
	Other current assets			655,716		15,413		386,215		(196,154)		861,190
	Intercompany receivables			569,898		-		-		(569,898)		-
		Total current assets		1,251,103		15,413		510,489		(766,052)		1,010,953
Intangible assets				-		-		207		-		207
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			998		-		-		-		998
Deferred charges and other
	assets			353,960		18,028		10,807		-		382,795
			$	7,098,160	$	1,004,124	$	615,536	$	(1,434,949)	$	7,282,871
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,255,421	$	265,102	$	405,891	$	(670,993)	$	2,255,421
Long-term debt				2,205,986		-		131		-		2,206,117
		Total capitalization		4,461,407		265,102		406,022		(670,993)		4,461,538
Current liabilities
	Current maturities of
		long-term debt		2,303		-		131		-		2,434
	Short-term debt			387,691		-		-		(181,295)		206,396
	Liabilities from risk
		management activities		11,916		-		3,537		-		15,453
	Other current liabilities			474,783		10,369		170,926		(12,763)		643,315
	Intercompany payables			-		543,084		26,814		(569,898)		-
		Total current liabilities		876,693		553,453		201,408		(763,956)		867,598
Deferred income taxes				789,649		173,351		(2,907)		-		960,093
Noncurrent liabilities from
	risk management activities			67,862		-		10,227		-		78,089
Regulatory cost of removal
	obligation			428,947		-		-		-		428,947
Deferred credits and other
	liabilities			473,602		12,218		786		-		486,606
			$	7,098,160	$	1,004,124	$	615,536	$	(1,434,949)	$	7,282,871

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Unaudited Interim Financial Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2011
Regulatory Liabilities [Line Items]
Regulatory Asset - Replacement/renewal of distribution facilities	The 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. During the prior fiscal year, the Railroad Commission of Texas’ Division of Public Safety issued a new rule requiring natural gas distribution companies to develop and implement a risk-based program for the renewal or replacement of distribution facilities, including steel service lines. The rule allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing) at which time investment and costs would be recovered through base rates. As of December 31, 2011, we had deferred $0.1 million associated with the requirements of this rule which are recorded as other costs in the regulatory assets table above.
Statement Of Income And Comprehensive Income Abstract
Net income (loss)	$ 68,507	$ 73,997
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax	901	776
Other Comprehensive Income Reclassification Adjustment And Unrealized Gain Loss On Derivatives Included In Net Income And Arising During Period Net Of Tax	(1,087)	31,847
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax	(16,575)	10,350
Comprehensive Income Net Of Tax	51,746	116,970
Other Comprehensive Income Loss Tax Portion Attributable To Parent Abstract
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Tax	514	455
Other Comprehensive Income Reclassification Adjustment And Unrealized Gain Loss On Derivatives Included In Net Income And Arising During Period Tax	(638)	18,704
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Tax	(10,597)	6,617
Accumulated Other Comprehensive Income Loss Net Of Tax Abstract
Accumulated Other Comprehensive Income Loss Available For Sale Securities Adjustment Net Of Tax	3,459		2,558
Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Interest Rate Hedges Effect Net Of Tax	(35,244)		(34,157)
Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(33,436)		(16,861)
Accumulated other comprehensive income (loss)	(65,221)		(48,460)
Deferred Gas Costs Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,871		8,130
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	469,685		464,025
Miscellaneous Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	14,558		14,025
Pension And Postretirement Benefit Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	249,882		254,666
Merger And Integration Costs Net [Member]
Regulatory Asset [Line Items]
Regulatory Assets	6,120		6,242
Deferred Gas Costs Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets	88,799		33,976
Regulatory Cost of Removal Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets	9,875		8,852
Environmental Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	288		385
Rate Case Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	4,493		4,862
Deferred Franchise Fees [Member]
Regulatory Asset [Line Items]
Regulatory Assets	365		379
Deferred Miscellaneous Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	$ 3,345		$ 3,534

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2. Unaudited Financial Information

3 Months Ended

Dec. 31, 2011

Significant Accounting Policies Abstract

2. Unaudited Financial Information

2. Unaudited Interim Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company's audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2011 are not indicative of our results of operations for the full 2012 fiscal year, which ends September 30, 2012.

We have evaluated subsequent events from the December 31, 2011balance 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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three months ended December 31, 2011, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard requires enhanced disclosure of offsetting arrangements for financial instruments and will become effective for annual periods beginning after January 1, 2013and for interim periods within those annual periods. The second standard defers the effective date for amendments to the presentation of reclassifications of items out of accumulated other comprehensive income as prescribed by a previously issued standard, which were initially to be effective for interim and annual periods beginning after December 15, 2011. The adoption of these standards should not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the quarter ended December 31, 2011.

Regulatory assets and liabilities

Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities, and the regulatory cost of removal obligation is reported separately.

Significant regulatory assets and liabilities as ofDecember 31, 2011 and September 30, 2011 included the following:

		December 31,		September 30,
		2011		2011
			(In thousands)
Regulatory assets:
	Pension and postretirement benefit costs	$	249,882	$	254,666
	Merger and integration costs, net		6,120		6,242
	Deferred gas costs		88,799		33,976
	Regulatory cost of removal asset		9,875		8,852
	Environmental costs		288		385
	Rate case costs		4,493		4,862
	Deferred franchise fees		365		379
	Other		3,345		3,534
		$	363,167	$	312,896
Regulatory liabilities:
	Deferred gas costs	$	1,871	$	8,130
	Regulatory cost of removal obligation		469,685		464,025
	Other		14,558		14,025
		$	486,114	$	486,180

The 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.

During the prior fiscal year, the Railroad Commission of Texas' Division of Public Safety issued a new rule requiring natural gas distribution companies to develop and implement a risk-based program for the renewal or replacement of distribution facilities, including steel service lines. The rule allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing) at which time investment and costs would be recovered through base rates. As of December 31, 2011, we had deferred $0.1 million associated with the requirements of this rule which are recorded asother costs in the regulatory assets table above.

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Environmental costs have been deferred to be included in future rate filings in accordance with rulings received from applicable state regulatory commissions.

Comprehensive income

The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2011 and 2010:

		Three Months Ended
		December 31
		2011		2010
		(In thousands)
Net income		$	68,507	$	73,997
Unrealized holding gains on investments, net of tax expense
	of $514 and $455 for the three months ended December
	31, 2011 and 2010		901		776
Amortization and unrealized gain (loss) on treasury
	lock agreements, net of tax expense (benefit) of $(638)
	and $18,704 for the three months ended December 31,
	2011 and 2010		(1,087)		31,847
Net unrealized gains (losses) on cash flow hedging
	transactions, net of tax expense (benefit) of $(10,597) and
	$6,617 for the three months ended December 31, 2011 and 2010		(16,575)		10,350
Comprehensive income		$	51,746	$	116,970

Accumulated other comprehensiveloss, net of tax, as of December 31, 2011 and September 30, 2011 consisted of the following unrealized gains (losses):

			December 31,		September 30,
			2011		2011
			(In thousands)
Accumulated other comprehensive loss:
	Unrealized holding gains on investments	$	3,459	$	2,558
	Treasury lock agreements		(35,244)		(34,157)
	Cash flow hedges		(33,436)		(16,861)
		$	(65,221)	$	(48,460)

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Financial Instruments (Details) (USD $)	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2011
Effect of Fair Value Hedges on Results of Operations [Abstract]
Commodity contracts	$ (24,064,000)	$ 1,723,000
Fair value adjustment for natural gas inventory designated as the hedged item	15,249,000	(15,625,000)
Total impact on revenue	8,815,000	13,902,000
Basis ineffectiveness	841,000	921,000
Timing ineffectiveness	7,974,000	12,981,000
Other Comprehensive Income Abstract
Treasury lock agreements fair value	(1,403,000)	31,425,000
Forward commodity contracts fair value	(23,678,000)	1,657,000
Treasury lock agreements	316,000	422,000
Forward commodity contracts	7,103,000	8,693,000
Total other comprehensive income (loss) from hedging, net of tax	(17,662,000)	42,197,000
Expected Earnings [Line Items]
Treasury Lock Gain Loss Reclassified To Earnings	8,701,000
Commodity Contract Gain Loss Reclassified To Earnings	(33,436,000)
Natural Gas Inventory Abstract
Inventory write-down to lower of cost or market	1,700,000
Summary Of Derivative Instruments Abstract
Minimum Length Of Time Hedged In Cash Flow Hedge	one
Maximum Length Of Time Hedged In Cash Flow Hedge	59
Gain Loss On Hedge Ineffectiveness	8,400,000	13,500,000
Gain Loss On Derivative Instruments Not Designated Hedges Net Pretax	(2,200,000)	4,200,000
Disposal Group, Including Discontinued Operation, Derivative Liabilities, Current	1,700,000		1,300,000
Next Twelve Months [Member]
Expected Earnings [Line Items]
Treasury Lock Gain Loss Reclassified To Earnings	(1,266,000)
Commodity Contract Gain Loss Reclassified To Earnings	(25,900,000)
Thereafter [Member]
Expected Earnings [Line Items]
Treasury Lock Gain Loss Reclassified To Earnings	9,967,000
Commodity Contract Gain Loss Reclassified To Earnings	(7,536,000)
Natural Gas Distribution Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Fair Value	0
Cash Flow	0
Not designated	13,964,000,000
Total Commodity Contracts Outstanding	13,964,000,000
Derivatives Fair Value [Line Items]
Derivative Assets Current	292,000		843,000
Derivative Assets Noncurrent	180,000		998,000
Derivative Liabilities Current	14,521,000		11,916,000
Derivative Liabilities Noncurrent	70,105,000		67,862,000
Total Financial Instruments	(85,829,000)	(79,277,000)
Cash Flow Hedge [Line Items]
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	0	0
Loss arising from ineffective portion of commodity contracts	0	0
Total impact on revenue	0	0
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	502,000	670,000
Total Impact from Cash Flow Hedges	(502,000)	(670,000)
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Liabilities At Fair Value Net	(69,755,000)	(67,527,000)
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	0	0
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	0	0
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	0	0
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(69,755,000)	(67,527,000)
Natural Gas Distribution Segment [Member] | Nondesignated [Member]
Derivatives Fair Value [Line Items]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net	(16,074,000)	(11,750,000)
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	292,000	843,000
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	180,000	998,000
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(16,196,000)	(13,256,000)
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(350,000)	(335,000)
Nonregulated Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Fair Value	(26,690,000,000)
Cash Flow	44,428,000,000
Not designated	46,944,000,000
Total Commodity Contracts Outstanding	64,682,000,000
Derivatives Fair Value [Line Items]
Derivative Assets Current	10,732,000		17,501,000
Derivative Assets Noncurrent	6,196,000		0
Derivative Liabilities Current	4,623,000		3,537,000
Derivative Liabilities Noncurrent	5,484,000		10,227,000
Total Financial Instruments	(15,263,000)	(25,050,000)
Cash Flow Hedge [Line Items]
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	11,642,000	14,253,000
Loss arising from ineffective portion of commodity contracts	430,000	444,000
Total impact on revenue	(12,072,000)	(14,697,000)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	0	0
Total Impact from Cash Flow Hedges	(12,072,000)	(14,697,000)
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Liabilities At Fair Value Net	(9,720,000)	(16,203,000)
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	60,222,000	22,396,000
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	58,000	174,000
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(57,988,000)	(31,064,000)
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(12,012,000)	(7,709,000)
Nonregulated Segment [Member] | Nondesignated [Member]
Derivatives Fair Value [Line Items]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net	(5,543,000)	(8,847,000)
Nonregulated Segment [Member] | Nondesignated [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	148,669,000	67,710,000
Nonregulated Segment [Member] | Nondesignated [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	80,916,000	22,379,000
Nonregulated Segment [Member] | Nondesignated [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(166,878,000)	(73,865,000)
Nonregulated Segment [Member] | Nondesignated [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(68,250,000)	(25,071,000)
Regulated Transmission and Storage Segment [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	0		0
Derivative Assets Noncurrent	0		0
Derivative Liabilities Current	0		0
Derivative Liabilities Noncurrent	$ 0		$ 0

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2011	Sep. 30, 2010
Segment Reporting Information Profit Loss [Abstract]
Operating revenues	$ 1,101,173	$ 1,133,262
Purchased gas cost	738,291	768,538
Gross profit	362,882	364,724
Operating expenses
Operation and maintenance	116,062	114,490
Depreciation and amortization	59,215	54,777
Taxes, other than income	43,198	40,168
Total operating expenses	218,475	209,435
Operating income	144,407	155,289
Miscellaneous income (expense)	(1,875)	(726)
Interest charges	35,442	38,895
Income (loss) before income taxes	107,090	115,668
Income tax expense (benefit)	41,302	44,568
Income (loss) from continuing operations	65,788	71,100
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	2,719	2,897
Net income (loss)	68,507	73,997
Capital expenditures	154,394	123,162
ASSETS
Net property, plant and equipment	5,246,213		5,147,918
Current assets
Cash and cash equivalents	85,160	129,892	131,419	131,952
Total current assets	1,261,241		1,010,953
Total Assets	7,635,632		7,282,871
CAPITALIZATION AND LIABILITIES
Shareholders' equity	2,267,762		2,255,421
Long-term debt	2,206,193		2,206,117
Total capitalization	4,473,955		4,461,538
Current liabilities
Current maturities of long-term debt	131		2,434
Short-term debt	389,985		206,396
Total current liabilities	1,179,801		867,598
Deferred income taxes	981,559		960,093
Total Equity and Liabilities	7,635,632		7,282,871
Natural Gas Distribution Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	693,068	703,261
Intersegment revenues	224	201
Operating revenues	693,292	703,462
Purchased gas cost	402,207	412,526
Gross profit	291,085	290,936
Operating expenses
Operation and maintenance	93,414	89,229
Depreciation and amortization	50,831	47,894
Taxes, other than income	38,479	34,448
Total operating expenses	182,724	171,571
Operating income	108,361	119,365
Miscellaneous income (expense)	(1,756)	(698)
Interest charges	27,855	29,697
Income (loss) before income taxes	78,750	88,970
Income tax expense (benefit)	30,845	34,549
Income (loss) from continuing operations	47,905	54,421
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	2,719	2,897
Net income (loss)	50,624	57,318
Capital expenditures	128,733	109,499
ASSETS
Net property, plant and equipment	4,328,612		4,248,198
Investment in subsidaries	672,300		670,993
Current assets
Cash and cash equivalents	63,031		24,646
Assets from risk management activities	292		843
Other current assets	912,185		655,716
Intercompany receivables	567,587		569,898
Total current assets	1,543,095		1,251,103
Intangible assets	0		0
Goodwill	572,908		572,908
Noncurrent assets from risk management activities	180		998
Deferred charges and other assets	359,860		353,960
Total Assets	7,476,955		7,098,160
CAPITALIZATION AND LIABILITIES
Shareholders' equity	2,267,762		2,255,421
Long-term debt	2,206,062		2,205,986
Total capitalization	4,473,824		4,461,407
Current liabilities
Current maturities of long-term debt	0		2,303
Short-term debt	583,980		387,691
Liabilities from risk management activities	14,521		11,916
Other current liabilities	606,357		474,783
Intercompany payables	0		0
Total current liabilities	1,204,858		876,693
Deferred income taxes	813,423		789,649
Noncurrent liabilities from risk management activities	70,105		67,862
Regulatory cost of removal obligation	437,660		428,947
Deferred credits and other liabilities	477,085		473,602
Total Equity and Liabilities	7,476,955		7,098,160
Regulated Transmission and Storage Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	19,440	21,233
Intersegment revenues	37,319	27,774
Operating revenues	56,759	49,007
Purchased gas cost	0	0
Gross profit	56,759	49,007
Operating expenses
Operation and maintenance	16,965	15,574
Depreciation and amortization	7,651	5,799
Taxes, other than income	3,784	3,553
Total operating expenses	28,400	24,926
Operating income	28,359	24,081
Miscellaneous income (expense)	(280)	(282)
Interest charges	7,209	8,064
Income (loss) before income taxes	20,870	15,735
Income tax expense (benefit)	7,456	5,633
Income (loss) from continuing operations	13,414	10,102
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	13,414	10,102
Capital expenditures	24,120	12,739
ASSETS
Net property, plant and equipment	855,245		838,302
Investment in subsidaries	0		0
Current assets
Cash and cash equivalents	0		0
Assets from risk management activities	0		0
Other current assets	13,418		15,413
Intercompany receivables	0		0
Total current assets	13,418		15,413
Intangible assets	0		0
Goodwill	132,381		132,381
Noncurrent assets from risk management activities	0		0
Deferred charges and other assets	11,297		18,028
Total Assets	1,012,341		1,004,124
CAPITALIZATION AND LIABILITIES
Shareholders' equity	278,515		265,102
Long-term debt	0		0
Total capitalization	278,515		265,102
Current liabilities
Current maturities of long-term debt	0		0
Short-term debt	0		0
Liabilities from risk management activities	0		0
Other current liabilities	11,929		10,369
Intercompany payables	531,126		543,084
Total current liabilities	543,055		553,453
Deferred income taxes	181,641		173,351
Noncurrent liabilities from risk management activities	0		0
Regulatory cost of removal obligation	0		0
Deferred credits and other liabilities	9,130		12,218
Total Equity and Liabilities	1,012,341		1,004,124
Nonregulated Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	388,665	408,768
Intersegment revenues	55,511	66,872
Operating revenues	444,176	475,640
Purchased gas cost	428,771	450,462
Gross profit	15,405	25,178
Operating expenses
Operation and maintenance	6,051	10,084
Depreciation and amortization	733	1,084
Taxes, other than income	935	2,167
Total operating expenses	7,719	13,335
Operating income	7,686	11,843
Miscellaneous income (expense)	36	290
Interest charges	252	1,170
Income (loss) before income taxes	7,470	10,963
Income tax expense (benefit)	3,001	4,386
Income (loss) from continuing operations	4,469	6,577
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	4,469	6,577
Capital expenditures	1,541	924
ASSETS
Net property, plant and equipment	62,356		61,418
Investment in subsidaries	(2,096)		(2,096)
Current assets
Cash and cash equivalents	22,129		106,773
Assets from risk management activities	10,732		17,501
Other current assets	453,571		386,215
Intercompany receivables	0		0
Total current assets	486,432		510,489
Intangible assets	196		207
Goodwill	34,711		34,711
Noncurrent assets from risk management activities	6,196		0
Deferred charges and other assets	10,449		10,807
Total Assets	598,244		615,536
CAPITALIZATION AND LIABILITIES
Shareholders' equity	393,785		405,891
Long-term debt	131		131
Total capitalization	393,916		406,022
Current liabilities
Current maturities of long-term debt	131		131
Short-term debt	0		0
Liabilities from risk management activities	4,623		3,537
Other current liabilities	170,281		170,926
Intercompany payables	36,461		26,814
Total current liabilities	211,496		201,408
Deferred income taxes	(13,505)		(2,907)
Noncurrent liabilities from risk management activities	5,484		10,227
Regulatory cost of removal obligation	0		0
Deferred credits and other liabilities	853		786
Total Equity and Liabilities	598,244		615,536
Intersegment Elimination [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	0	0
Intersegment revenues	(93,054)	(94,847)
Operating revenues	(93,054)	(94,847)
Purchased gas cost	(92,687)	(94,450)
Gross profit	(367)	(397)
Operating expenses
Operation and maintenance	(368)	(397)
Depreciation and amortization	0	0
Taxes, other than income	0	0
Total operating expenses	(368)	(397)
Operating income	1	0
Miscellaneous income (expense)	125	(36)
Interest charges	126	(36)
Income (loss) before income taxes	0	0
Income tax expense (benefit)	0	0
Income (loss) from continuing operations	0	0
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	0	0
Capital expenditures	0	0
ASSETS
Net property, plant and equipment	0		0
Investment in subsidaries	(670,204)		(668,897)
Current assets
Cash and cash equivalents	0		0
Assets from risk management activities	0		0
Other current assets	(214,117)		(196,154)
Intercompany receivables	(567,587)		(569,898)
Total current assets	(781,704)		(766,052)
Intangible assets	0		0
Goodwill	0		0
Noncurrent assets from risk management activities	0		0
Deferred charges and other assets	0		0
Total Assets	(1,451,908)		(1,434,949)
CAPITALIZATION AND LIABILITIES
Shareholders' equity	(672,300)		(670,993)
Long-term debt	0		0
Total capitalization	(672,300)		(670,993)
Current liabilities
Current maturities of long-term debt	0		0
Short-term debt	(193,995)		(181,295)
Liabilities from risk management activities	0		0
Other current liabilities	(18,026)		(12,763)
Intercompany payables	(567,587)		(569,898)
Total current liabilities	(779,608)		(763,956)
Deferred income taxes	0		0
Noncurrent liabilities from risk management activities	0		0
Regulatory cost of removal obligation	0		0
Deferred credits and other liabilities	0		0
Total Equity and Liabilities	$ (1,451,908)		$ (1,434,949)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Sep. 30, 2011
ASSETS
Property, plant and equipment	$ 6,896,521	$ 6,816,794
Less accumulated depreciation and amortization	1,650,308	1,668,876
Net property, plant and equipment	5,246,213	5,147,918
Current assets
Cash and cash equivalents	85,160	131,419
Accounts receivable, net	489,797	273,303
Gas stored underground	325,669	289,760
Other current assets	360,615	316,471
Total current assets	1,261,241	1,010,953
Goodwill and intangible assets	740,196	740,207
Deferred charges and other assets	387,982	383,793
Total assets	7,635,632	7,282,871
Shareholders' equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2011 - 90,007,057 shares; September 30, 2011 - 90,296,482 shares	448	451
Additional paid-in capital	1,725,050	1,732,935
Retained earnings	607,485	570,495
Accumulated other comprehensive income (loss)	(65,221)	(48,460)
Shareholders' equity	2,267,762	2,255,421
Long-term debt	2,206,193	2,206,117
Total capitalization	4,473,955	4,461,538
Current liabilities
Accounts payable and accrued liabilities	432,332	291,205
Other current liabilities	357,353	367,563
Short-term debt	389,985	206,396
Current maturities of long-term debt	131	2,434
Total current liabilities	1,179,801	867,598
Deferred income taxes	981,559	960,093
Regulatory cost of removal obligation	437,660	428,947
Deferred credits and other liabilities	562,657	564,695
Total shareholders' equity and liabilities	$ 7,635,632	$ 7,282,871

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Cash Flows From Operating Activities
Net income (loss)	$ 68,507	$ 73,997
Depreciation and amortization:
Charged to depreciation and amortization	60,733	56,161
Charged to other accounts	78	46
Other
Deferred income taxes	40,042	43,423
Other	4,692	4,712
Net assets / liabilities from risk management activities	(8,426)	5,304
Net change in operating assets and liabilities	(180,917)	(137,819)
Net cash provided (used) by operating activities	(15,291)	45,824
Cash Flows From Investing Activities
Capital expenditures	(154,394)	(123,162)
Other, net	(1,080)	(370)
Net cash used in investing activities	(155,474)	(123,532)
Cash Flows From Financing Activities
Net increase in short-term debt	173,905	112,628
Repayment of long-term debt	(2,303)	(10,000)
Cash dividends paid	(31,517)	(31,002)
Repurchase of common stock	(12,535)	0
Repurchase of equity awards	(3,120)	(3,231)
Issuance of common stock	76	7,253
Net cash provided by (used in) financing activities	124,506	75,648
Net increase (decrease) in cash and cash equivalents	(46,259)	(2,060)
Cash and cash equivalents at beginning of period	131,419	131,952
Cash and cash equivalents at end of period	$ 85,160	$ 129,892

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Discontinued Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2011
Discontinued Operation Income Loss From Discontinued Operation Disclosures Abstract
Operating revenues	$ 23,451	$ 23,733
Purchased gas cost	14,951	14,897
Gross profit	8,500	8,836
Operating expenses	4,174	4,016
Operating income	4,326	4,820
Miscellaneous (expense)	48	33
Income from discontinued operations before income taxes	4,278	4,787
Income tax expense	1,559	1,890
Income (loss) from discontinued operations	2,719	2,897
Disposal Group Including Discontinued Operation Balance Sheet Disclosures Abstract
Net plant, property & equipment	127,227		127,577
Gas stored underground	14,257		11,931
Other current assets	3,773		786
Deferred charges and other assets	62		277
Assets held for sale	145,319		140,571
Accounts payable	9,945		1,917
Other current liabilities	5,459		4,877
Regulatory cost of removal	10,367		10,498
Deferred credits and other liabilities	1,175		1,153
Liabilities held for sale	$ 26,946		$ 18,445

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Unaudited Interim Financial Information (Table)

3 Months Ended

Dec. 31, 2011

Accumulated Other Comprehensive Income Loss Table Abstract

Accumulated other comprehensive income/loss table

			December 31,		September 30,
			2011		2011
			(In thousands)
Accumulated other comprehensive loss:
	Unrealized holding gains on investments	$	3,459	$	2,558
	Treasury lock agreements		(35,244)		(34,157)
	Cash flow hedges		(33,436)		(16,861)
		$	(65,221)	$	(48,460)

Comprehensive Income Loss Table Abstract

Comprehensive income/loss table

		Three Months Ended
		December 31
		2011		2010
		(In thousands)
Net income		$	68,507	$	73,997
Unrealized holding gains on investments, net of tax expense
	of $514 and $455 for the three months ended December
	31, 2011 and 2010		901		776
Amortization and unrealized gain (loss) on treasury
	lock agreements, net of tax expense (benefit) of $(638)
	and $18,704 for the three months ended December 31,
	2011 and 2010		(1,087)		31,847
Net unrealized gains (losses) on cash flow hedging
	transactions, net of tax expense (benefit) of $(10,597) and
	$6,617 for the three months ended December 31, 2011 and 2010		(16,575)		10,350
Comprehensive income		$	51,746	$	116,970

Regulatory Assets And Liabilities Table Abstract

Regulatory assets and liabilities table

		December 31,		September 30,
		2011		2011
			(In thousands)
Regulatory assets:
	Pension and postretirement benefit costs	$	249,882	$	254,666
	Merger and integration costs, net		6,120		6,242
	Deferred gas costs		88,799		33,976
	Regulatory cost of removal asset		9,875		8,852
	Environmental costs		288		385
	Rate case costs		4,493		4,862
	Deferred franchise fees		365		379
	Other		3,345		3,534
		$	363,167	$	312,896
Regulatory liabilities:
	Deferred gas costs	$	1,871	$	8,130
	Regulatory cost of removal obligation		469,685		464,025
	Other		14,558		14,025
		$	486,114	$	486,180

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Debt (Details) (USD $)	3 Months Ended
	Dec. 31, 2011	Sep. 30, 2011
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	$ 2,210,262,000	$ 2,212,565,000
Debt Instrument Unamortized Discount	(3,938,000)	(4,014,000)
Current maturities of long-term debt	131,000	2,434,000
Total long-term debt	2,206,193,000	2,206,117,000
Long Term Debt Other Disclosures [Abstract]
Authorized Commercial Paper	750,000,000
Commercial Paper	390,000,000	206,400,000
Regulated Operations Line of Credit Facilities, Covenant Terms	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.
Ratio of Total Debt to Total Capital	56.00%
Nonregulated Operations Line of Credit Facilities, Covenant Terms	AEM is required by the financial covenants in its facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million.
AEM Net Working Capital	118,200,000
AEM Tangible Net Worth	147,800,000
Debt and Equity Securities Authorized for Issuance	1,300,000,000
Debt Instrument Covenant Description	In addition to these financial covenants, 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. Finally, AEM’s credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2. We have no other triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.
Debt Instrument Covenant Compliance	We were in compliance with all of our debt covenants as of December 31, 2011.
Debt And Equity Securities Available For Issuance	900,000,000
Debt Securities Available for Issuance	550,000,000
Equity Securities Available for Issuance	350,000,000
First Facility Regulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	750,000,000
Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature	1,000,000,000
Second Facility Regulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	25,000,000
Third Facility Regulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	10,000,000
Intercompany Facility Regulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	350,000,000
Line Of Credit Facility Description	This facility was replaced on January 1, 2012 with a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program.
Committed Facility Nonregulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	200,000,000
Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature	500,000,000
Intercompany Facility Nonregulated Operations [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity	350,000,000
Line Of Credit Facility Description	This facility was replaced on January 1, 2012 with a $500 million intercompany 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.
Unsecured Notes Due December 2011 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	0	2,303,000
Debt Instrument Interest Rate Stated Percentage	10.00%
Debt Instrument Maturity Date	Dec. 31, 2011
Unsecured Senior Notes Due 2013 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	250,000,000	250,000,000
Debt Instrument Interest Rate Stated Percentage	5.125%
Debt Instrument Maturity Date	Jan. 15, 2013
Unsecured Senior Notes Due 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	500,000,000	500,000,000
Debt Instrument Interest Rate Stated Percentage	4.95%
Debt Instrument Maturity Date	Oct. 15, 2014
Unsecured Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	250,000,000	250,000,000
Debt Instrument Interest Rate Stated Percentage	6.35%
Debt Instrument Maturity Date	Jun. 15, 2017
Unsecured Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	450,000,000	450,000,000
Debt Instrument Interest Rate Stated Percentage	8.50%
Debt Instrument Maturity Date	Mar. 15, 2019
Unsecured Senior Notes Due 2034 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	200,000,000	200,000,000
Debt Instrument Interest Rate Stated Percentage	5.95%
Debt Instrument Maturity Date	Oct. 15, 2034
Unsecured Senior Notes Due 2041 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	400,000,000	400,000,000
Debt Instrument Interest Rate Stated Percentage	5.50%
Debt Instrument Maturity Date	Jun. 15, 2041
Medium Term Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	10,000,000	10,000,000
Debt Instrument Interest Rate Stated Percentage	6.67%
Debt Instrument Maturity Date	Dec. 15, 2025
Unsecured Debentures Due 2028 [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	150,000,000	150,000,000
Debt Instrument Interest Rate Stated Percentage	6.75%
Debt Instrument Maturity Date	Jul. 15, 2028
Rental Property Term Note [Member]
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	$ 262,000	$ 262,000
Debt Instrument Maturity Date	Jul. 01, 2013

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Fair Value Measurements (Table)

3 Months Ended

Dec. 31, 2011

Fair Value Measurements Tables Abstract

Fair value measurements table

		Quoted		Significant		Significant
		Prices in		Other		Other
		Active		Observable		Unobservable		Netting and
		Markets		Inputs		Inputs		Cash		December 31,
		(Level 1)		(Level 2)(1)		(Level 3)		Collateral(2)		2011
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	472	$	-	$	-	$	472
	Nonregulated segment		33,768		256,098		-		(272,938)		16,928
Total financial instruments			33,768		256,570		-		(272,938)		17,400
Hedged portion of gas stored
	underground		77,551		-		-		-		77,551
Available-for-sale securities
	Money market funds		-		1,151		-		-		1,151
	Registered investment companies		38,008		-		-		-		38,008
	Bonds		-		18,346		-		-		18,346
Total available-for-sale securities			38,008		19,497		-		-		57,505
Total assets		$	149,327	$	276,067	$	-	$	(272,938)	$	152,456
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	86,301	$	-	$	-	$	86,301
	Nonregulated segment		51,117		254,012		-		(295,022)		10,107
Total liabilities		$	51,117	$	340,313	$	-	$	(295,022)	$	96,408

		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)		2011
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	1,841		$	-	$	-	$	1,841
	Nonregulated segment		15,262		97,396			-		(95,156)		17,502
Total financial instruments			15,262		99,237			-		(95,156)		19,343
Hedged portion of gas stored
	underground		47,940		-			-		-		47,940
Available-for-sale securities
	Money market funds		-		1,823			-		-		1,823
	Registered investment companies		36,444		-			-		-		36,444
	Bonds		-		14,366			-		-		14,366
Total available-for-sale securities			36,444		16,189			-		-		52,633
Total assets		$	99,646	$	115,426		$	-	$	(95,156)	$	119,916
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	81,118		$	-	$	-	$	81,118
	Nonregulated segment		22,091		115,617			-		(123,943)		13,765
Total liabilities		$	22,091	$	196,735		$	-	$	(123,943)	$	94,883

Other fair value measurements table

	December 31, 2011
	(In thousands)
Carrying Amount	$	2,210,262
Fair Value	$	2,572,094

Available for sale securities table

				Gross		Gross
		Amortized		Unrealized		Unrealized		Fair
		Cost		Gain		Loss		Value
		(In thousands)
As of December 31, 2011
	Domestic equity mutual funds	$	27,881	$	5,447	$	-	$	33,328
	Foreign equity mutual funds		4,659		305		(284)		4,680
	Bonds		18,323		45		(22)		18,346
	Money market funds		1,151		-		-		1,151
		$	52,014	$	5,797	$	(306)	$	57,505
As of September 30, 2011
	Domestic equity mutual funds	$	27,748	$	4,074	$	-	$	31,822
	Foreign equity mutual funds		4,597		267		(242)		4,622
	Bonds		14,390		10		(34)		14,366
	Money market funds		1,823		-		-		1,823
		$	48,558	$	4,351	$	(276)	$	52,633

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1. Nature of Business

3 Months Ended

Dec. 31, 2011

Nature Of Operations Abstract

1. Nature Of Business

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Our corporate headquarters and shared-services function are located in Dallas, Texas and our customer support centers are located in Amarillo and Waco, Texas.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. 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, which we currently anticipate will occur during fiscal 2012, 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 businessesare subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate.

Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties. AEH also seeks to maximize, through asset optimization activities, the economic value associated with storage and transportation capacity it owns or controls. Certain of these arrangements are with regulated affiliates of the Company, which have been approved by applicable state regulatory commissions.

We operate the Company through the following three segments:

• the natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
• the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline—Texas Division and
• the nonregulated segment, whichincludes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (PARENTHETICALS) (USD $)	Dec. 31, 2011	Sep. 30, 2011
Top Element - 00250 - Statement - CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (PARENTHETICALS)
Common Stock, Par Value Per Share	$ 0.000	$ 0.000
Common Stock, Stated Value Per Share	$ 0.005	$ 0.005
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	90,007,057	90,296,482

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11. Segment Information

3 Months Ended

Dec. 31, 2011

Segment Reporting Disclosure Abstract

11. Segment Information

11. Segment Information

As discussed in Note 1 above, we operate the Company through the following three segments:

• The natural gas distributionsegment, which includes our regulated natural gas distribution and related sales operations,
• The regulated transmission and storage segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline—Texas Division and
• The nonregulated segment, whichis comprised ofour nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. We evaluate performance based on net income or loss of the respective operating units.

Income statements for the three month periods ended December 31, 2011 and 2010 by segment are presented in the following tables:

		Three Months Ended December 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Eliminations		Consolidated
		(In thousands)
Operating revenues from
	external parties	$	693,068	$	19,440	$	388,665	$	-	$	1,101,173
Intersegment revenues			224		37,319		55,511		(93,054)		-
			693,292		56,759		444,176		(93,054)		1,101,173
Purchased gas cost			402,207		-		428,771		(92,687)		738,291
	Gross profit		291,085		56,759		15,405		(367)		362,882
Operating expenses
	Operation and maintenance		93,414		16,965		6,051		(368)		116,062
	Depreciation and amortization		50,831		7,651		733		-		59,215
	Taxes, other than income		38,479		3,784		935		-		43,198
Total operating expenses			182,724		28,400		7,719		(368)		218,475
Operating income			108,361		28,359		7,686		1		144,407
Miscellaneous income (expense)			(1,756)		(280)		36		125		(1,875)
Interest charges			27,855		7,209		252		126		35,442
Income from continuing
	operations before income taxes		78,750		20,870		7,470		-		107,090
Income tax expense			30,845		7,456		3,001		-		41,302
Income from continuing operations			47,905		13,414		4,469		-		65,788
Income from discontinued
	operations, net of tax		2,719		-		-		-		2,719
	Net income	$	50,624	$	13,414	$	4,469	$	-	$	68,507
Capital expenditures		$	128,733	$	24,120	$	1,541	$	-	$	154,394

		Three Months Ended December 31, 2010
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Eliminations		Consolidated
		(In thousands)
Operating revenues from
	external parties	$	703,261	$	21,233	$	408,768	$	-	$	1,133,262
Intersegment revenues			201		27,774		66,872		(94,847)		-
			703,462		49,007		475,640		(94,847)		1,133,262
Purchased gas cost			412,526		-		450,462		(94,450)		768,538
	Gross profit		290,936		49,007		25,178		(397)		364,724
Operating expenses
	Operation and maintenance		89,229		15,574		10,084		(397)		114,490
	Depreciation and amortization		47,894		5,799		1,084		-		54,777
	Taxes, other than income		34,448		3,553		2,167		-		40,168
Total operating expenses			171,571		24,926		13,335		(397)		209,435
Operating income			119,365		24,081		11,843		-		155,289
Miscellaneous income (expense)			(698)		(282)		290		(36)		(726)
Interest charges			29,697		8,064		1,170		(36)		38,895
Income from continuing
	operations before income taxes		88,970		15,735		10,963		-		115,668
Income tax expense			34,549		5,633		4,386		-		44,568
Income from continuing operations			54,421		10,102		6,577		-		71,100
Income from discontinued
	operations, net of tax		2,897		-		-		-		2,897
	Net income	$	57,318	$	10,102	$	6,577	$	-	$	73,997
Capital expenditures		$	109,499	$	12,739	$	924	$	-	$	123,162

Balance sheet information at December 31, 2011 and September 30, 2011 by segment is presented in the following tables.

			December 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,328,612	$	855,245	$	62,356	$	-	$	5,246,213
Investment in subsidiaries				672,300		-		(2,096)		(670,204)		-
Current assets
	Cash and cash equivalents			63,031		-		22,129		-		85,160
	Assets from risk
		management activities		292		-		10,732		-		11,024
	Other current assets			912,185		13,418		453,571		(214,117)		1,165,057
	Intercompany receivables			567,587		-		-		(567,587)		-
		Total current assets		1,543,095		13,418		486,432		(781,704)		1,261,241
Intangible assets				-		-		196		-		196
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			180		-		6,196		-		6,376
Deferred charges and other
	assets			359,860		11,297		10,449		-		381,606
			$	7,476,955	$	1,012,341	$	598,244	$	(1,451,908)	$	7,635,632
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,267,762	$	278,515	$	393,785	$	(672,300)	$	2,267,762
Long-term debt				2,206,062		-		131		-		2,206,193
		Total capitalization		4,473,824		278,515		393,916		(672,300)		4,473,955
Current liabilities
	Current maturities of
		long-term debt		-		-		131		-		131
	Short-term debt			583,980		-		-		(193,995)		389,985
	Liabilities from risk
		management activities		14,521		-		4,623		-		19,144
	Other current liabilities			606,357		11,929		170,281		(18,026)		770,541
	Intercompany payables			-		531,126		36,461		(567,587)		-
		Total current liabilities		1,204,858		543,055		211,496		(779,608)		1,179,801
Deferred income taxes				813,423		181,641		(13,505)		-		981,559
Noncurrent liabilities from
	risk management activities			70,105		-		5,484		-		75,589
Regulatory cost of removal
	obligation			437,660		-		-		-		437,660
Deferred credits and other
	liabilities			477,085		9,130		853		-		487,068
			$	7,476,955	$	1,012,341	$	598,244	$	(1,451,908)	$	7,635,632

			September 30, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
				(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,248,198	$	838,302	$	61,418	$	-	$	5,147,918
Investment in subsidiaries				670,993		-		(2,096)		(668,897)		-
Current assets
	Cash and cash equivalents			24,646		-		106,773		-		131,419
	Assets from risk
		management activities		843		-		17,501		-		18,344
	Other current assets			655,716		15,413		386,215		(196,154)		861,190
	Intercompany receivables			569,898		-		-		(569,898)		-
		Total current assets		1,251,103		15,413		510,489		(766,052)		1,010,953
Intangible assets				-		-		207		-		207
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			998		-		-		-		998
Deferred charges and other
	assets			353,960		18,028		10,807		-		382,795
			$	7,098,160	$	1,004,124	$	615,536	$	(1,434,949)	$	7,282,871
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,255,421	$	265,102	$	405,891	$	(670,993)	$	2,255,421
Long-term debt				2,205,986		-		131		-		2,206,117
		Total capitalization		4,461,407		265,102		406,022		(670,993)		4,461,538
Current liabilities
	Current maturities of
		long-term debt		2,303		-		131		-		2,434
	Short-term debt			387,691		-		-		(181,295)		206,396
	Liabilities from risk
		management activities		11,916		-		3,537		-		15,453
	Other current liabilities			474,783		10,369		170,926		(12,763)		643,315
	Intercompany payables			-		543,084		26,814		(569,898)		-
		Total current liabilities		876,693		553,453		201,408		(763,956)		867,598
Deferred income taxes				789,649		173,351		(2,907)		-		960,093
Noncurrent liabilities from
	risk management activities			67,862		-		10,227		-		78,089
Regulatory cost of removal
	obligation			428,947		-		-		-		428,947
Deferred credits and other
	liabilities			473,602		12,218		786		-		486,606
			$	7,098,160	$	1,004,124	$	615,536	$	(1,434,949)	$	7,282,871

XML

Document and Entity Information (USD $)	3 Months Ended
	Dec. 31, 2011	Feb. 03, 2012	Mar. 31, 2011
Top Element - 00100 - Document - Document and Entity Information
Document Type	10-Q
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Entity Registrant Name	Atmos Energy Corporation
Entity Central Index Key	0000731802
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Entity Common Stock Shares Outstanding		90,016,074
Entity Public Float			$ 3,008,806,271

XML

Regulatory Assets and Liabilities (Policy)

Dec. 31, 2011

Regulatory Assets And Liabilities Policy Abstract

Regulatory assets and liabilities Policy Text Block

We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities, and the regulatory cost of removal obligation is reported separately.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Operating revenues
Operating revenues	$ 1,101,173	$ 1,133,262
Purchased gas cost
Purchased gas cost	738,291	768,538
Gross profit	362,882	364,724
Operating expenses
Operation and maintenance	116,062	114,490
Depreciation and amortization	59,215	54,777
Taxes, other than income	43,198	40,168
Total operating expenses	218,475	209,435
Operating income	144,407	155,289
Miscellaneous income (expense)	(1,875)	(726)
Interest charges	35,442	38,895
Income (loss) before income taxes	107,090	115,668
Income tax expense (benefit)	41,302	44,568
Income (loss) from continuing operations	65,788	71,100
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	2,719	2,897
Net income (loss)	68,507	73,997
Income Loss From Continuing Operations Per Basic Share	$ 0.72	$ 0.78
Income Loss From Discontinued Operations Net Of Tax Per Basic Share	$ 0.03	$ 0.03
Basic net income (loss) per share	$ 0.75	$ 0.81
Income Loss From Continuing Operations Per Diluted Share	$ 0.72	$ 0.78
Income Loss From Discontinued Operations Net Of Tax Per Diluted Share	$ 0.03	$ 0.03
Diluted net income (loss) per share	$ 0.75	$ 0.81
Cash dividends per share	$ 0.345	$ 0.340
Weighted average shares outstanding:
Basic	90,254	90,082
Diluted	90,546	90,408
Natural Gas Distribution Segment [Member]
Operating revenues
Operating revenues	693,292	703,462
Purchased gas cost
Purchased gas cost	402,207	412,526
Gross profit	291,085	290,936
Operating expenses
Operation and maintenance	93,414	89,229
Depreciation and amortization	50,831	47,894
Taxes, other than income	38,479	34,448
Total operating expenses	182,724	171,571
Operating income	108,361	119,365
Miscellaneous income (expense)	(1,756)	(698)
Interest charges	27,855	29,697
Income (loss) before income taxes	78,750	88,970
Income tax expense (benefit)	30,845	34,549
Income (loss) from continuing operations	47,905	54,421
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	2,719	2,897
Net income (loss)	50,624	57,318
Regulated Transmission and Storage Segment [Member]
Operating revenues
Operating revenues	56,759	49,007
Purchased gas cost
Purchased gas cost	0	0
Gross profit	56,759	49,007
Operating expenses
Operation and maintenance	16,965	15,574
Depreciation and amortization	7,651	5,799
Taxes, other than income	3,784	3,553
Total operating expenses	28,400	24,926
Operating income	28,359	24,081
Miscellaneous income (expense)	(280)	(282)
Interest charges	7,209	8,064
Income (loss) before income taxes	20,870	15,735
Income tax expense (benefit)	7,456	5,633
Income (loss) from continuing operations	13,414	10,102
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	13,414	10,102
Nonregulated Segment [Member]
Operating revenues
Operating revenues	444,176	475,640
Purchased gas cost
Purchased gas cost	428,771	450,462
Gross profit	15,405	25,178
Operating expenses
Operation and maintenance	6,051	10,084
Depreciation and amortization	733	1,084
Taxes, other than income	935	2,167
Total operating expenses	7,719	13,335
Operating income	7,686	11,843
Miscellaneous income (expense)	36	290
Interest charges	252	1,170
Income (loss) before income taxes	7,470	10,963
Income tax expense (benefit)	3,001	4,386
Income (loss) from continuing operations	4,469	6,577
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	4,469	6,577
Intersegment Elimination [Member]
Operating revenues
Operating revenues	(93,054)	(94,847)
Purchased gas cost
Purchased gas cost	(92,687)	(94,450)
Gross profit	(367)	(397)
Operating expenses
Operation and maintenance	(368)	(397)
Depreciation and amortization	0	0
Taxes, other than income	0	0
Total operating expenses	(368)	(397)
Operating income	1	0
Miscellaneous income (expense)	125	(36)
Interest charges	126	(36)
Income (loss) before income taxes	0	0
Income tax expense (benefit)	0	0
Income (loss) from continuing operations	0	0
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0
Net income (loss)	$ 0	$ 0

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6. Debt

3 Months Ended

Dec. 31, 2011

Debt Disclosure Abstract

6. Debt

6. Debt

The nature and terms of our debt instruments are described in detail in Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes in the terms of our debt instruments during the three months ended December 31, 2011.

Long-term debt

Long-term debt at December 31, 2011 and September 30, 2011 consisted of the following:

			December 31,		September 30,
			2011		2011
			(In thousands)
Unsecured 10% Notes, redeemed December 2011			$	-	$	2,303
Unsecured 5.125% Senior Notes, due January 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		400,000
Medium term notes
	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			262		262
		Total long-term debt		2,210,262		2,212,565
Less:
	Original issue discount on unsecured senior
		notes and debentures		(3,938)		(4,014)
	Current maturities			(131)		(2,434)
			$	2,206,193	$	2,206,117

Our unsecured 10% notes were paid on their maturity date on December 31, 2011, and were not replaced.

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.

We finance our short-term borrowing requirements through a combination of a $750 million commercial paper program and four committed revolving credit facilities with third-party lenders. As a result, we have approximately $985 million of working capital funding. Additionally, our $750 million unsecured credit facility has an accordion feature which, if utilized, would increase borrowing capacity to $1.0 billion. At December 31, 2011 and September 30, 2011, there was $390.0 million and $206.4 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.

Regulated Operations

We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $785 million of working capital funding, including a five-year $750 million unsecured facility, a $25 million unsecured facility and a $10 million revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.2 million at December 31, 2011.

In addition to these third-party facilities, our regulated operations had a $350 million intercompany revolving credit facility with AEH. This facility was replaced on January 1, 2012 with a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) 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, 2012.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, has a three-year $200 million committed revolving credit facility, expiring in December 2013, 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. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH. Due to outstanding letters of credit and various covenants, including covenants based on working capital, the amount available to AEM under this credit facility was $110.0 million at December 31, 2011.

To supplement borrowings under this facility, AEH had a $350 million intercompany demand credit facility with AEC. This facility was replaced on January 1, 2012 with a $500 million intercompany 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, 2012.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. At December 31, 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

The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2011, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 56 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

AEM is required by the financial covenants in its facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At December 31, 2011, AEM's ratio of total liabilities to tangible net worth, as defined, was 1.39 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at December 31, 2011, AEM's net working capital was $118.2million and its tangible net worth was $147.8million.

In addition to these financial covenants, 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.

Finally, AEM's credit agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody's rating of Baa2. We have no other triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity, based on our credit rating or other triggering events.

We were in compliance with all of our debt covenants as of December 31, 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.

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5. Discontinued Operations

3 Months Ended

Dec. 31, 2011

Discontinued Operations Abstract

5. Discontinued Operations

5.       Discontinued Operations

On May 12, 2011, we entered into a definitive agreement to sell substantially 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 a 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, which we currently anticipate will occur during fiscal 2012.

As required under generally accepted accounting principles, the operating results of our Missouri, Illinois and Iowa operations have been aggregated and reported on the 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.

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 consolidated balance sheets at December 31, 2011 and September 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
			December 31
			2011		2010
			(In thousands)
Operating revenues			$	23,451	$	23,733
Purchased gas cost				14,951		14,897
	Gross profit			8,500		8,836
Operating expenses				4,174		4,016
Operating income				4,326		4,820
Other nonoperating expense				(48)		(33)
Income from discontinued
	operations before income taxes			4,278		4,787
Income tax expense				1,559		1,890
		Net income	$	2,719	$	2,897

The following table presents balance sheet data related to assets held for sale.

		December 31,		September 30,
		2011		2011
		(In thousands)
Net plant, property & equipment		$	127,227	$	127,577
Gas stored underground			14,257		11,931
Other current assets			3,773		786
Deferred charges and other assets			62		277
	Assets held for sale	$	145,319	$	140,571
Accounts payable and accrued liabilities		$	9,945	$	1,917
Other current liabilities			5,459		4,877
Regulatory cost of removal obligation			10,367		10,498
Deferred credits and other liabilities			1,175		1,153
	Liabilities held for sale	$	26,946	$	18,445

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Financial Instruments (Table)

3 Months Ended

Dec. 31, 2011

Financial Instruments Note Tables Abstract

Oustanding commodity contracts volumes table

		Natural
	Hedge	Gas
Contract Type	Designation	Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	-	(26,690)
	Cash Flow	-	44,428
	Not designated	13,964	46,944
		13,964	64,682

Financial instruments on the balance sheet

						Natural
						Gas
				Balance Sheet Location		Distribution		Nonregulated		Total
December 31, 2011:						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	60,222	$	60,222
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		58		58
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			-		(57,988)		(57,988)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(69,755)		(12,012)		(81,767)
	Total						(69,755)		(9,720)		(79,475)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			292		148,669		148,961
		Noncurrent commodity		Deferred charges and
			contracts		other assets		180		80,916		81,096
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(16,196)		(166,878)		(183,074)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(350)		(68,250)		(68,600)
	Total						(16,074)		(5,543)		(21,617)
Total Financial Instruments						$	(85,829)	$	(15,263)	$	(101,092)

						Natural
						Gas
				Balance Sheet Location		Distribution		Nonregulated		Total
September 30, 2011:						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	22,396	$	22,396
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		174		174
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			-		(31,064)		(31,064)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(67,527)		(7,709)		(75,236)
	Total						(67,527)		(16,203)		(83,730)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			843		67,710		68,553
		Noncurrent commodity		Deferred charges and
			contracts		other assets		998		22,379		23,377
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(13,256)		(73,865)		(87,121)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(335)		(25,071)		(25,406)
	Total						(11,750)		(8,847)		(20,597)
Total Financial Instruments						$	(79,277)	$	(25,050)	$	(104,327)

Fair value hedges table

		Three Months Ended
		December 31
		2011		2010
		(In thousands)
Commodity contracts		$	24,064	$	(1,723)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(15,249)		15,625
Total impact on revenue		$	8,815	$	13,902
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	841	$	921
	Timing ineffectiveness		7,974		12,981
		$	8,815	$	13,902

Cash flow hedges table

		Three Months Ended
		December 31
		2011		2010
		(In thousands)
Increase (decrease) in fair value:
	Treasury lock agreements	$	(1,403)	$	31,425
	Forward commodity contracts		(23,678)		1,657
Recognition of losses in earnings due to settlements:
	Treasury lock agreements		316		422
	Forward commodity contracts		7,103		8,693
Total other comprehensive income (loss)
	from hedging, net of tax(1)	$	(17,662)	$	42,197

Other comprehensive income from hedging table

	Treasury
	Lock		Commodity
	Agreements		Contracts		Total
	(In thousands)
Next twelve months	$	(1,266)	$	(25,900)	$	(27,166)
Thereafter		9,967		(7,536)		2,431
Total(1)	$	8,701	$	(33,436)	$	(24,735)

Expected recognition in earnings of deferred losses in AOCI table

		Three Months Ended December 31, 2011
		Natural
		Gas
		Distribution		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	(11,642)	$	(11,642)
Loss arising from ineffective portion of
	commodity contracts		-		(430)		(430)
Total impact on revenue			-		(12,072)		(12,072)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(502)		-		(502)
Total Impact from Cash Flow Hedges		$	(502)	$	(12,072)	$	(12,574)
		Three Months Ended December 31, 2010
		Natural
		Gas
		Distribution		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	(14,253)	$	(14,253)
Loss arising from ineffective portion of
	commodity contracts		-		(444)		(444)
Total impact on revenue			-		(14,697)		(14,697)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(670)		-		(670)
Total Impact from Cash Flow Hedges		$	(670)	$	(14,697)	$	(15,367)

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Fair Value Measurements (Policy)

3 Months Ended

Dec. 31, 2011

Fair Value Measurements Policy Abstract

Fair Value Measurements Policy Text Block

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the first quarter of fiscal 2012, there were no changes in these methods.

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9. Commitments and Contingencies

3 Months Ended

Dec. 31, 2011

Commitments And Contingencies Disclosure Abstract

9. Commitments and Contingencies

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 13 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2011.

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, Billy Joe Honeycutt et al. vs. Atmos Energy Corporation, et al., which is 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 October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals, appealing the verdict of the trial court. The appellees in this case subsequently filed their reply brief with the Court of Appeals on January 16, 2012, with our reply brief due to be filed with the Court by March 16, 2012.

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, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, 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. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. As of this date, the Court has not yet ruled on the motion.

We have accrued what we believe is an adequate amount for the anticipated resolution of this matter; however, the amount accrued is less than 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 continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

We are a party to other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

Purchase Commitments

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2011, AEH was committed to purchase 103.1Bcf within one year, 35.3Bcf within one to three years and 0.3Bcf after three yearsunder indexed contracts. AEH is committed to purchase 3.4Bcf within one year and0.2Bcf within one to three years under fixed price contracts with prices ranging from $2.82to $6.36per Mcf. Purchases under these contracts totaled $312.1million and $334.2million for the three months ended December 31, 2011 and 2010.

Our natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of December 31, 2011 are as follows (in thousands):

2012	$	149,788
2013		82,778
2014		68,124
Thereafter		-
	$	300,690

Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. There were no material changes to the estimated storage and transportation fees for the quarter ended December 31, 2011.

Regulatory Matters

As previously described in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, 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. Since that time, we have fully cooperated with the Commission during this investigation.

The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission's findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company haspaid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company's financial position, results of operations or cash flows and none of the payments were charged to any of the Company's customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.

As discussed in Note 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, in 2010, our Mid-Tex Division agreed to install 100,000 steel service line replacements by September 30, 2012.  As of December 31, 2011, we had replaced 60,184 lines and are on schedule for completion in September 2012.  Under the terms of the agreement, special rate recovery of the associated return, depreciation and taxes is approved for lines replaced between October 1, 2010 and September 30, 2012.  Since October 1, 2010, we have spent $64.0 millionon steel service line replacements.

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 (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the CFTC and SEC have issued a number of rules and regulations, we expect additional rules and regulations to be issued, which should 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 and related rules and regulations. We also anticipate additional reporting and disclosure obligations will be imposed.

As of December 31, 2011, annual rate filing mechanisms were in progress in our Louisiana and Mississippi service areas and there was oneother ratemaking activity in progress in our Kansas service area. These regulatory proceedings are discussed in further detail below in Management's Discussion and Analysis – Recent Ratemaking Developments.

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7. Earnings Per Share

3 Months Ended

Dec. 31, 2011

Disclosure Earnings Per Share

7. Earnings Per Share

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 months ended December 31, 2011 and 2010 are calculated as follows:

			Three Months Ended
			December 31
			2011		2010
			(In thousands, except
			per share amounts)
Basic Earnings Per Share from continuing operations
	Income from continuing operations		$	65,788	$	71,100
	Less: Income from continuing operations allocated to
		participating securities		685		748
	Income from continuing operations available to common
		shareholders	$	65,103	$	70,352
	Basic weighted average shares outstanding			90,254		90,082
	Income from continuing operations per share - Basic		$	0.72	$	0.78
Basic Earnings Per Share from discontinued operations
	Income from discontinued operations		$	2,719	$	2,897
	Less: Income from discontinued operations allocated to
		participating securities		28		31
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Basic weighted average shares outstanding			90,254		90,082
	Income from discontinued operations per share - Basic		$	0.03	$	0.03
	Net income per share - Basic		$	0.75	$	0.81
Diluted Earnings Per Share from continuing operations
	Income from continuing operations available to common
		shareholders	$	65,103	$	70,352
	Effect of dilutive stock options and other shares			1		2
	Income from continuing operations available to common
		shareholders	$	65,104	$	70,354
	Basic weighted average shares outstanding			90,254		90,082
	Additional dilutive stock options and other shares			292		326
	Diluted weighted average shares outstanding			90,546		90,408
	Income from continuing operations per share - Diluted		$	0.72	$	0.78
Diluted Earnings Per Share from discontinued operations
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Effect of dilutive stock options and other shares			-		-
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Basic weighted average shares outstanding			90,254		90,082
	Additional dilutive stock options and other shares			292		326
	Diluted weighted average shares outstanding			90,546		90,408
	Income from discontinued operations per share - Diluted		$	0.03	$	0.03
	Net income per share - Diluted		$	0.75	$	0.81

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2011 and 2010 as their exercise price was less than the average market price of the common stock during that period.

Share Repurchase Program

On September 28, 2011, the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. Although the program is authorized for a five-year period, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the company deems appropriate. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the company. As of December 31, 2011, 387,991 shares had been repurchased for an aggregate value of $12.5 million.

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8. Interim Pension and Other Postretirement Benefit Plan Information

3 Months Ended

Dec. 31, 2011

Disclosure Interim Pension and Other Postretirement Benefit Plans

8. Interim Pension and Postretirement Benefit Plans

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 months ended December 31, 2011 and 2010 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

			Three Months Ended December 31
			Pension Benefits				Other Benefits
			2011		2010		2011		2010
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	4,298	$	4,380	$	4,088	$	3,601
	Interest cost			6,677		6,924		3,465		3,203
	Expected return on assets			(5,368)		(5,963)		(652)		(682)
	Amortization of transition asset			-		-		378		378
	Amortization of prior service cost			(35)		(112)		(362)		(362)
	Amortization of actuarial loss			4,142		3,494		662		87
		Net periodic pension cost	$	9,714	$	8,723	$	7,579	$	6,225

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2011 and 2010 are as follows:

	Pension Benefits				Other Benefits
	2011		2010		2011		2010
Discount rate	5.05	%	5.39	%	5.05	%	5.39	%
Rate of compensation increase	3.50	%	4.00	%	N/A		N/A
Expected return on plan assets	7.75	%	8.25	%	4.70	%	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, 2012. Based upon this valuation, we expect we will be required to contributebetween $25 million and $30 million to our pension plans by September 15, 2012.

We contributed $4.8 million to our other post-retirement benefit plans during the three months ended December 31, 2011. We expect to contribute between $20 million and $25 million to these plans during fiscal 2012.

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10. Concentration of Credit Risk

3 Months Ended

Dec. 31, 2011

Disclosure Concentration of Credit Risk

10. Concentration of Credit Risk

10. Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three months ended December 31, 2011, there were no material changes in our concentration of credit risk.

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Fair Value Measurements Available-For-Sale Securities (Detials) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Sep. 30, 2011
Money Market Funds [Member]
Schedule Of Available For Sale Securities [Line Items]
Available-for-sale Equity Securities Amortized Cost Basis	$ 1,151	$ 1,823
Available-for-sale Securities Gross Unrealized Gain	0	0
Available-for-sale Securities Gross Unrealized Losses 1	0	0
Available For Sale Securities Fair Value Disclosure	1,151	1,823
Equity Funds Domestic [Member]
Schedule Of Available For Sale Securities [Line Items]
Available-for-sale Equity Securities Amortized Cost Basis	27,881	27,748
Available-for-sale Securities Gross Unrealized Gain	5,447	4,074
Available-for-sale Securities Gross Unrealized Losses 1	0	0
Available For Sale Securities Fair Value Disclosure	33,328	31,822
Equity Funds Foreign [Member]
Schedule Of Available For Sale Securities [Line Items]
Available-for-sale Equity Securities Amortized Cost Basis	4,659	4,597
Available-for-sale Securities Gross Unrealized Gain	305	267
Available-for-sale Securities Gross Unrealized Losses 1	284	242
Available For Sale Securities Fair Value Disclosure	4,680	4,622
Debt Securities [Member]
Schedule Of Available For Sale Securities [Line Items]
Available-for-sale Equity Securities Amortized Cost Basis	18,323	14,390
Available-for-sale Securities Gross Unrealized Gain	45	10
Available-for-sale Securities Gross Unrealized Losses 1	22	34
Available For Sale Securities Fair Value Disclosure	$ 18,346	$ 14,366

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Segment Reporting (Policy)

3 Months Ended

Dec. 31, 2011

Segment Reporting Policy Abstract

Segment Reporting Policy

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. We evaluate performance based on net income or loss of the respective operating units.

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Debt (Table)

3 Months Ended

Dec. 31, 2011

Debt Tables Abstract

Debt instrument table

			December 31,		September 30,
			2011		2011
			(In thousands)
Unsecured 10% Notes, redeemed December 2011			$	-	$	2,303
Unsecured 5.125% Senior Notes, due January 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		400,000
Medium term notes
	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			262		262
		Total long-term debt		2,210,262		2,212,565
Less:
	Original issue discount on unsecured senior
		notes and debentures		(3,938)		(4,014)
	Current maturities			(131)		(2,434)
			$	2,206,193	$	2,206,117

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CONDENSED CONSOLIDATED STATEMENT OF INCOME (UNAUDITED) (PARENTHETICALS) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Statement of Income Parentheticals
Discontinued Operation Tax Effect Of Income Loss From Discontinued Operation During Phase Out Period	$ 1,559	$ 1,890

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4. Fair Value Measurements

3 Months Ended

Dec. 31, 2011

Fair Value Measurements Abstract

4. Fair Value Measurements

4. Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the first quarter of fiscal 2012, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 9 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2011.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and September 30, 2011. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

		Quoted		Significant		Significant
		Prices in		Other		Other
		Active		Observable		Unobservable		Netting and
		Markets		Inputs		Inputs		Cash		December 31,
		(Level 1)		(Level 2)(1)		(Level 3)		Collateral(2)		2011
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	472	$	-	$	-	$	472
	Nonregulated segment		33,768		256,098		-		(272,938)		16,928
Total financial instruments			33,768		256,570		-		(272,938)		17,400
Hedged portion of gas stored
	underground		77,551		-		-		-		77,551
Available-for-sale securities
	Money market funds		-		1,151		-		-		1,151
	Registered investment companies		38,008		-		-		-		38,008
	Bonds		-		18,346		-		-		18,346
Total available-for-sale securities			38,008		19,497		-		-		57,505
Total assets		$	149,327	$	276,067	$	-	$	(272,938)	$	152,456
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	86,301	$	-	$	-	$	86,301
	Nonregulated segment		51,117		254,012		-		(295,022)		10,107
Total liabilities		$	51,117	$	340,313	$	-	$	(295,022)	$	96,408

		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)		2011
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	1,841		$	-	$	-	$	1,841
	Nonregulated segment		15,262		97,396			-		(95,156)		17,502
Total financial instruments			15,262		99,237			-		(95,156)		19,343
Hedged portion of gas stored
	underground		47,940		-			-		-		47,940
Available-for-sale securities
	Money market funds		-		1,823			-		-		1,823
	Registered investment companies		36,444		-			-		-		36,444
	Bonds		-		14,366			-		-		14,366
Total available-for-sale securities			36,444		16,189			-		-		52,633
Total assets		$	99,646	$	115,426		$	-	$	(95,156)	$	119,916
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	81,118		$	-	$	-	$	81,118
	Nonregulated segment		22,091		115,617			-		(123,943)		13,765
Total liabilities		$	22,091	$	196,735		$	-	$	(123,943)	$	94,883

(1)       Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences. This level also includes municipal and corporate bonds where market data for pricing is observable.

(2)       This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of December 31, 2011, we had $22.1 millionof cash held in margin accountsto collateralize certain financial instruments. Of this amount, $11.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $10.7 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, 2011 we had $28.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.4 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.4 million is classified as current risk management assets.

Available-for-sale securities are comprised of the following:

				Gross		Gross
		Amortized		Unrealized		Unrealized		Fair
		Cost		Gain		Loss		Value
		(In thousands)
As of December 31, 2011
	Domestic equity mutual funds	$	27,881	$	5,447	$	-	$	33,328
	Foreign equity mutual funds		4,659		305		(284)		4,680
	Bonds		18,323		45		(22)		18,346
	Money market funds		1,151		-		-		1,151
		$	52,014	$	5,797	$	(306)	$	57,505
As of September 30, 2011
	Domestic equity mutual funds	$	27,748	$	4,074	$	-	$	31,822
	Foreign equity mutual funds		4,597		267		(242)		4,622
	Bonds		14,390		10		(34)		14,366
	Money market funds		1,823		-		-		1,823
		$	48,558	$	4,351	$	(276)	$	52,633

At December 31, 2011 and September 30, 2011, our available-for-sale securities included $39.2 million and $38.3 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2011 we maintained investments in bonds that have contractual maturity dates ranging from January 2012 through July 2016.

These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund's purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.

We maintained an investment in one foreign equity mutual fund with a fair value of $2.2 million in an unrealized loss position of $0.3 million as of December 31, 2011. This fund has been in an unrealized loss position for less than twelve months. Because this fund is only used to fund the supplemental plans, we evaluate investment performance over a long-term horizon. Based upon our intent and ability to hold this investment, our ability to direct the source of the payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that this fund continues to receive good ratings from mutual fund rating companies, we do not consider this impairment to be other than temporary as of December 31, 2011. We also maintained several bonds with a cumulative fair value of $6.5 million in an unrealized loss position of less than $0.1 million as of December 31, 2011. These bonds have been in an unrealized loss position for less than twelve months. Based upon our intent and ability to hold these investments, our ability to direct the source of payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that these bonds are investment grade, we do not consider this impairment to be other than temporary as of December 31, 2011.

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of December 31, 2011:

	December 31, 2011
	(In thousands)
Carrying Amount	$	2,210,262
Fair Value	$	2,572,094

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Earnings Per Share (Table)

3 Months Ended

Dec. 31, 2011

Earnings Per Share Table Abstract

Earnings per share table

			Three Months Ended
			December 31
			2011		2010
			(In thousands, except
			per share amounts)
Basic Earnings Per Share from continuing operations
	Income from continuing operations		$	65,788	$	71,100
	Less: Income from continuing operations allocated to
		participating securities		685		748
	Income from continuing operations available to common
		shareholders	$	65,103	$	70,352
	Basic weighted average shares outstanding			90,254		90,082
	Income from continuing operations per share - Basic		$	0.72	$	0.78
Basic Earnings Per Share from discontinued operations
	Income from discontinued operations		$	2,719	$	2,897
	Less: Income from discontinued operations allocated to
		participating securities		28		31
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Basic weighted average shares outstanding			90,254		90,082
	Income from discontinued operations per share - Basic		$	0.03	$	0.03
	Net income per share - Basic		$	0.75	$	0.81
Diluted Earnings Per Share from continuing operations
	Income from continuing operations available to common
		shareholders	$	65,103	$	70,352
	Effect of dilutive stock options and other shares			1		2
	Income from continuing operations available to common
		shareholders	$	65,104	$	70,354
	Basic weighted average shares outstanding			90,254		90,082
	Additional dilutive stock options and other shares			292		326
	Diluted weighted average shares outstanding			90,546		90,408
	Income from continuing operations per share - Diluted		$	0.72	$	0.78
Diluted Earnings Per Share from discontinued operations
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Effect of dilutive stock options and other shares			-		-
	Income from discontinued operations available to
		common shareholders	$	2,691	$	2,866
	Basic weighted average shares outstanding			90,254		90,082
	Additional dilutive stock options and other shares			292		326
	Diluted weighted average shares outstanding			90,546		90,408
	Income from discontinued operations per share - Diluted		$	0.03	$	0.03
	Net income per share - Diluted		$	0.75	$	0.81

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Interim Pension and Other Postretirement Benefits (Details) (USD $)	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount Rate	5.05%	5.39%
Rate of compensation increase	3.50%	4.00%
Expected return on plan assets	7.75%	8.25%
Components of net periodic pension cost [Abstract]
Service Cost	$ 4,298,000	$ 4,380,000
Interest Cost	6,677,000	6,924,000
Expected return on assets	5,368,000	5,963,000
Amortization of transition asset	0	0
Amortization of prior service cost	(35,000)	(112,000)
Recognized actuarial loss	(4,142,000)	(3,494,000)
Defined Benefit Plan Net Periodic Benefit Cost	9,714,000	8,723,000
Current Year Benefit Plan Contributions [Abstract]
Contributions Estimate Minimum	25,000,000
Contributions Estimate Maximum	30,000,000
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount Rate	5.05%	5.39%
Expected return on plan assets	4.70%	5.00%
Components of net periodic pension cost [Abstract]
Service Cost	4,088,000	3,601,000
Interest Cost	3,465,000	3,203,000
Expected return on assets	652,000	682,000
Amortization of transition asset	378,000	378,000
Amortization of prior service cost	(362,000)	(362,000)
Recognized actuarial loss	(662,000)	(87,000)
Defined Benefit Plan Net Periodic Benefit Cost	7,579,000	6,225,000
Current Year Benefit Plan Contributions [Abstract]
Contributions Actual	4,800,000
Contributions Estimate Minimum	20,000,000
Contributions Estimate Maximum	$ 25,000,000

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Earnings Per Share (Policy)

3 Months Ended

Dec. 31, 2011

Earnings Per Share Policy Abstract

Earnings Per Share Policy Text Block

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.