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 March 31, 2012

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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 April 27, 2012.

Class	Shares Outstanding
No Par Value	90,030,471

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.
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
ISRS	Infrastructure System Replacement Surcharge
Mcf	Thousand cubic feet
MMcf	Million cubic feet
Moody’s	Moody’s Investors Services, Inc.
NYMEX	New York Mercantile Exchange, Inc.
PPA	Pension Protection Act of 2006
PRP	Pipeline Replacement Program
RRC	Railroad Commission of Texas
RRM	Rate Review Mechanism
S&P	Standard & Poor’s Corporation
SEC	United States Securities and Exchange Commission
WNA	Weather Normalization Adjustment

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2012			September 30, 2011
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	6,992,899		$	6,816,794
Less accumulated depreciation and amortization		1,658,887			1,668,876
Net property, plant and equipment		5,334,012			5,147,918
Current assets
Cash and cash equivalents		47,040			131,419
Accounts receivable, net		350,261			273,303
Gas stored underground		221,112			289,760
Other current assets		275,428			316,471
Total current assets		893,841			1,010,953
Goodwill and intangible assets		740,185			740,207
Deferred charges and other assets		400,689			383,793
	$	7,368,727		$	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: March 31, 2012 — 90,029,852 shares;
September 30, 2011 — 90,296,482 shares	$	450		$	451
Additional paid-in capital		1,728,150			1,732,935
Retained earnings		685,206			570,495
Accumulated other comprehensive loss		(53,094	)		(48,460	)
Shareholders’ equity		2,360,712			2,255,421
Long-term debt		1,956,213			2,206,117
Total capitalization		4,316,925			4,461,538
Current liabilities
Accounts payable and accrued liabilities		309,864			291,205
Other current liabilities		374,123			367,563
Short-term debt		173,996			206,396
Current maturities of long-term debt		250,131			2,434
Total current liabilities		1,108,114			867,598
Deferred income taxes		1,062,488			960,093
Regulatory cost of removal obligation		414,001			428,947
Deferred credits and other liabilities		467,199			564,695
	$	7,368,727		$	7,282,871

See accompanying notes to condensed consolidated financial statements.

2

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended March 31
	2012			2011
	(Unaudited)
	(In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	889,008		$	1,077,414
Regulated transmission and storage segment		58,037			54,976
Nonregulated segment		370,763			583,531
Intersegment eliminations		(74,358	)		(134,424	)
		1,243,450			1,581,497
Purchased gas cost
Natural gas distribution segment		508,206			698,410
Regulated transmission and storage segment		—			—
Nonregulated segment		374,992			563,473
Intersegment eliminations		(74,009	)		(134,054	)
		809,189			1,127,829
Gross profit		434,261			453,668
Operating expenses
Operation and maintenance		110,708			114,162
Depreciation and amortization		60,272			55,467
Taxes, other than income		54,919			53,558
Asset impairment		—			19,282
Total operating expenses		225,899			242,469
Operating income		208,362			211,199
Miscellaneous income		616			26,202
Interest charges		36,660			37,875
Income from continuing operations before income taxes		172,318			199,526
Income tax expense		66,408			71,366
Income from continuing operations		105,910			128,160
Income from discontinued operations, net of tax ($1,834 and $2,642)		3,201			4,049
Net income	$	109,111		$	132,209
Basic earnings per share
Income per share from continuing operations	$	1.16		$	1.41
Income per share from discontinued operations		0.04			0.04
Net income per share — basic	$	1.20		$	1.45
Diluted earnings per share
Income per share from continuing operations	$	1.16		$	1.41
Income per share from discontinued operations		0.04			0.04
Net income per share — diluted	$	1.20		$	1.45
Cash dividends per share	$	0.345		$	0.340
Weighted average shares outstanding:
Basic		90,020			90,246
Diluted		90,322			90,533

See accompanying notes to condensed consolidated financial statements.

3

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Six Months Ended March 31
	2012			2011
	(Unaudited)
	(In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	1,582,300		$	1,780,876
Regulated transmission and storage segment		114,796			103,983
Nonregulated segment		814,939			1,059,171
Intersegment eliminations		(167,412	)		(229,271	)
		2,344,623			2,714,759
Purchased gas cost
Natural gas distribution segment		910,413			1,110,936
Regulated transmission and storage segment		—			—
Nonregulated segment		803,763			1,013,935
Intersegment eliminations		(166,696	)		(228,504	)
		1,547,480			1,896,367
Gross profit		797,143			818,392
Operating expenses
Operation and maintenance		226,770			228,652
Depreciation and amortization		119,487			110,244
Taxes, other than income		98,117			93,726
Asset impairment		—			19,282
Total operating expenses		444,374			451,904
Operating income		352,769			366,488
Miscellaneous income (expense)		(1,259	)		25,476
Interest charges		72,102			76,770
Income from continuing operations before income taxes		279,408			315,194
Income tax expense		107,710			115,934
Income from continuing operations		171,698			199,260
Income from discontinued operations, net of tax ($3,393 and $4,532)		5,920			6,946
Net income	$	177,618		$	206,206
Basic earnings per share
Income per share from continuing operations	$	1.89		$	2.18
Income per share from discontinued operations		0.06			0.08
Net income per share — basic	$	1.95		$	2.26
Diluted earnings per share
Income per share from continuing operations	$	1.88		$	2.18
Income per share from discontinued operations		0.06			0.08
Net income per share — diluted	$	1.94		$	2.26
Cash dividends per share	$	0.690		$	0.680
Weighted average shares outstanding:
Basic		90,137			90,157
Diluted		90,440			90,455

See accompanying notes to condensed consolidated financial statements.

4

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended March 31
	2012			2011
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	177,618		$	206,206
Adjustments to reconcile net income to net cash provided by operating activities:
Asset impairment		—			19,282
Depreciation and amortization:
Charged to depreciation and amortization		122,532			113,297
Charged to other accounts		203			98
Deferred income taxes		102,052			115,302
Other		9,874			10,255
Net assets / liabilities from risk management activities		15,690			(17,478	)
Net change in operating assets and liabilities		(67,246	)		(8,491	)
Net cash provided by operating activities		360,723			438,471
Cash Flows From Investing Activities
Capital expenditures		(311,123	)		(246,663	)
Other, net		(3,878	)		(1,535	)
Net cash used in investing activities		(315,001	)		(248,198	)
Cash Flows From Financing Activities
Net decrease in short-term debt		(48,945	)		(128,884	)
Unwinding of Treasury lock agreements		—			27,803
Repayment of long-term debt		(2,369	)		(10,066	)
Cash dividends paid		(62,907	)		(62,067	)
Repurchase of common stock		(12,535	)		—
Repurchase of equity awards		(3,509	)		(3,333	)
Issuance of common stock		164			7,568
Net cash used in financing activities		(130,101	)		(168,979	)
Net increase (decrease) in cash and cash equivalents		(84,379	)		21,294
Cash and cash equivalents at beginning of period		131,419			131,952
Cash and cash equivalents at end of period	$	47,040		$	153,246

See accompanying notes to condensed consolidated financial statements.

5

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2012

1.    Nature of Business

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

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions which currently cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. In May 2011, we 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 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 six-month period ended March 31, 2012 are not indicative of our results of operations for the full 2012 fiscal year, which ends September 30, 2012.

6

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We have evaluated subsequent events from the March 31, 2012 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as discussed in Note 6, 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.

Due to the pending sale of our distribution operations in our Missouri, Illinois and Iowa service areas, the financial results for these service areas are shown in discontinued operations. Accordingly, certain prior-year amounts have been reclassified to conform with the current year presentation.

During the second quarter of fiscal 2012, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

During the six months ended March 31, 2012, 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 indefinitely 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 six months ended March 31, 2012.

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.

7

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant regulatory assets and liabilities as of March 31, 2012 and September 30, 2011 included the following:

	March 31, 2012		September 30, 2011
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs	$	245,096	$	254,666
Merger and integration costs, net		5,998		6,242
Deferred gas costs		19,547		33,976
Regulatory cost of removal asset		10,233		8,852
Environmental costs		117		385
Rate case costs		4,503		4,862
Deferred franchise fees		333		379
Other		8,861		3,534
	$	294,688	$	312,896
Regulatory liabilities:
Deferred gas costs	$	15,232	$	8,130
Regulatory cost of removal obligation		463,740		464,025
Other		13,090		14,025
	$	492,062	$	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 March 31, 2012, we had deferred $0.7 million associated with the requirements of this rule which are recorded in “Other” in the regulatory assets table above.

Effective January 1, 2012, the Texas Legislature amended its Gas Utility Regulatory Act (GURA) to permit natural gas utilities to defer into a regulatory asset or liability the difference between a gas utility’s actual pension and postretirement expense and the level of such expense recoverable in its existing rates. The deferred amount will become eligible for inclusion in the utility’s rates in its next rate proceeding. During the quarter, we elected to utilize this provision of GURA, effective January 1, 2012, and established a regulatory asset totaling $2.5 million, which is recorded in “Other” in the regulatory assets table above. Of this amount, $1.4 million represented a reduction to operation and maintenance expense during the second quarter of fiscal 2012.

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

8

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive income

The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and six-month periods ended March 31, 2012 and 2011:

	Three Months Ended March 31						Six Months Ended March 31
	2012			2011			2012			2011
	(In thousands)
Net income	$	109,111		$	132,209		$	177,618		$	206,206
Unrealized holding gains on investments, net of tax expense of $1,203 and $477 for the three months ended March 31, 2012 and 2011 and of $1,717 and $932 for the six months ended March 31, 2012 and 2011		2,046			810			2,947			1,586
Amortization, unrealized gain and unwinding of treasury lock agreements, net of tax expense (benefit) of $9,042 and $(6,125) for the three months ended March 31, 2012 and 2011 and $8,404 and $12,579 for the six month ended March 31, 2012 and 2011		15,396			(10,427	)		14,309			21,420
Net unrealized gains (losses) on cash flow hedging transactions, net of tax expense (benefit) of $(3,399) and $2,573 for the three months ended March 31, 2012 and 2011 and $(13,996) and $9,190 for the six months ended March 31, 2012 and 2011		(5,315	)		4,025			(21,890	)		14,375
Comprehensive income	$	121,238		$	126,617		$	172,984		$	243,587

Accumulated other comprehensive income (loss), net of tax, as of March 31, 2012 and September 30, 2011 consisted of the following unrealized gains (losses):

	March 31, 2012			September 30, 2011
	(In thousands)
Accumulated other comprehensive income (loss):
Unrealized holding gains on investments	$	5,505		$	2,558
Treasury lock agreements		(19,848	)		(34,157	)
Cash flow hedges		(38,751	)		(16,861	)
	$	(53,094	)	$	(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 six months ended March 31, 2012 there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize finan-

9

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cial 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 hedged 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 cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.

Nonregulated Commodity Risk Management Activities

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 56 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.

10

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 March 31, 2012, we had three Treasury lock agreements outstanding to fix the Treasury yield component of 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 March 31, 2012, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2012, 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		—		(38,340	)
	Cash Flow		—		49,098
	Not designated		6,033		28,190
			6,033		38,948

11

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 March 31, 2012 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 $5.7 million and $28.8 million of cash held on deposit in margin accounts as of March 31, 2012 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)
March 31, 2012
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	77,441		$	77,441
Noncurrent commodity contracts	Deferred charges and other assets		—			—			—
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(45,818	)		(59,301	)		(105,119	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(10,914	)		(10,914	)
Total			(45,818	)		7,226			(38,592	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		502			137,934			138,436
Noncurrent commodity contracts	Deferred charges and other assets		—			85,951			85,951
Liability Financial Instruments
Current commodity contracts	Other current liabilities(1)		(2,215	)		(164,189	)		(166,404	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(1	)		(69,496	)		(69,497	)
Total			(1,714	)		(9,800	)		(11,514	)
Total Financial Instruments		$	(47,532)		$	(2,574	)	$	(50,106	)

⁽¹⁾  Other current liabilities not designated as hedges in our natural gas distribution segment include $0.8 million related to risk management liabilities that were classified as assets held for sale at March 31, 2012.

12

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 March 31, 2012 and 2011 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(6.2) million and $4.1 million. For the six months ended March 31, 2012 and 2011 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $2.2 million and $17.5 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

13

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 and six months ended March 31, 2012 and 2011 is presented below.

	Three Months Ended March 31
	2012			2011
	(In thousands)
Commodity contracts	$	29,090		$	(1,279	)
Fair value adjustment for natural gas inventory designated as the hedged item		(35,087	)		5,586
Total impact on revenue	$	(5,997	)	$	4,307
The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(739	)	$	(509	)
Timing ineffectiveness		(5,258	)		4,816
	$	(5,997	)	$	4,307

	Six Months Ended March  31
	2012			2011
	(In thousands)
Commodity contracts	$	53,153		$	(3,003	)
Fair value adjustment for natural gas inventory designated as the hedged item		(50,335	)		21,211
Total impact on revenue	$	2,818		$	18,208
The impact on revenue is comprised of the following:
Basis ineffectiveness	$	102		$	412
Timing ineffectiveness		2,716			17,796
	$	2,818		$	18,208

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 six months ended March 31, 2012, 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 six months ended March 31, 2011.

14

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	Three Months Ended March 31, 2012
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	—	$	(21,181	)	$	(21,181	)
Loss arising from ineffective portion of commodity contracts		—			—		(238	)		(238	)
Total impact on revenue		—			—		(21,419	)		(21,419	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(502	)		—		—			(502	)
Total Impact from Cash Flow Hedges	$	(502	)	$	—	$	(21,419	)	$	(21,921	)

	Three Months Ended March 31, 2011
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	—	$	(7,328	)	$	(7,328	)
Loss arising from ineffective portion of commodity contracts		—			—		(233	)		(233	)
Total impact on revenue		—			—		(7,561	)		(7,561	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(669	)		—		—			(669	)
Gain on unwinding of Treasury lock reclassified from AOCI into miscellaneous income		21,803			6,000		—			27,803
Total Impact from Cash Flow Hedges	$	21,134		$	6,000	$	(7,561	)	$	19,573

15

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Six Months Ended March 31, 2012
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	—	$	(32,823	)	$	(32,823	)
Loss arising from ineffective portion of commodity contracts		—			—		(668	)		(668	)
Total impact on revenue		—			—		(33,491	)		(33,491	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(1,004	)		—		—			(1,004	)
Total Impact from Cash Flow Hedges	$	(1,004	)	$	—	$	(33,491	)	$	(34,495	)

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

16

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended March 31, 2012 and 2011. 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 March 31						Six Months Ended March 31
	2012			2011			2012			2011
	(In thousands)
Increase (decrease) in fair value:
Treasury lock agreements	$	15,079		$	6,667		$	13,676		$	38,092
Forward commodity contracts		(18,234	)		(446	)		(41,912	)		1,211
Recognition of (gains) losses in earnings due to settlements:
Treasury lock agreements		317			(17,094	)		633			(16,672	)
Forward commodity contracts		12,919			4,471			20,022			13,164
Total other comprehensive income (loss) from hedging, net of tax(1)	$	10,081		$	(6,402	)	$	(7,581	)	$	35,795

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

Deferred gains (losses) recorded in 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 March 31, 2012. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock agreements as these instruments have not yet settled.

	Treasury Lock Agreements			Commodity Contracts			Total
	(In thousands)
Next twelve months	$	(1,266	)	$	(32,130	)	$	(33,396	)
Thereafter		10,284			(6,621	)		3,663
Total(1)	$	9,018		$	(38,751	)	$	(29,733	)

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

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended March 31, 2012 and 2011 was an increase (decrease) in revenue of $(12.8) million and $4.0 million. For the six months ended March 31, 2012 and 2011 revenue increased (decreased) $(15.0) million and $8.2 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.

17

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.

4.    Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011. During the three and six months ended March 31, 2012, there were no changes in these methods.

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

18

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 tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and September 30, 2011. 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)			March 31, 2012
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	502	$	—	$	—		$	502
Nonregulated segment		52,013		249,313		—		(287,608	)		13,718
Total financial instruments		52,013		249,815		—		(287,608	)		14,220
Hedged portion of gas stored underground		73,043		—		—		—			73,043
Available-for-sale securities Money market funds		—		3,358		—		—			3,358
Registered investment companies		38,424		—		—		—			38,424
Bonds		—		23,637		—		—			23,637
Total available-for-sale securities		38,424		26,995		—		—			65,419
Total assets	$	163,480	$	276,810	$	—	$	(287,608	)	$	152,682
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	48,034	$	—	$	—		$	48,034
Nonregulated segment		76,476		227,424		—		(293,304	)		10,596
Total liabilities	$	76,476	$	275,458	$	—	$	(293,304	)	$	58,630

19

ATMOS ENERGY CORPORATION

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 March 31, 2012, we had $5.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $2.8 million was used to offset current risk management liabilities under master netting arrangements and the remaining $2.9 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.

20

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 March 31, 2012:
Domestic equity mutual funds	$	24,471	$	7,821	$	—		$	32,292
Foreign equity mutual funds		5,327		805		—			6,132
Bonds		23,525		127		(15	)		23,637
Money market funds		3,358		—		—			3,358
	$	56,681	$	8,753	$	(15	)	$	65,419
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 March 31, 2012 and September 30, 2011, our available-for-sale securities included $41.8 million and $38.3 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At March 31, 2012 we maintained investments in bonds that have contractual maturity dates ranging from April 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 several bonds with a cumulative fair value of $4.4 million in an unrealized loss position of less than $0.1 million as of March 31, 2012. 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 March 31, 2012.

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of March 31, 2012:

	March 31, 2012
	(In thousands)
Carrying Amount	$	2,210,196
Fair Value	$	2,583,071

21

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 condensed consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.

The tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations. Additionally, assets and liabilities related to our Missouri, Illinois and Iowa operations are classified as “held for sale” in other current assets and liabilities in our condensed consolidated balance sheets at March 31, 2012 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 March 31						Six Months Ended March 31
	2012			2011			2012			2011
	(In thousands)
Operating revenues	$	26,374		$	35,790		$	49,825		$	59,523
Purchased gas cost		17,026			24,636			31,977			39,533
Gross profit		9,348			11,154			17,848			19,990
Operating expenses		4,275			4,431			8,449			8,447
Operating income		5,073			6,723			9,399			11,543
Other nonoperating expense		(38	)		(32	)		(86	)		(65	)
Income from discontinued operations before income taxes		5,035			6,691			9,313			11,478
Income tax expense		1,834			2,642			3,393			4,532
Net income	$	3,201		$	4,049		$	5,920		$	6,946

22

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	March 31, 2012		September 30, 2011
	(In thousands)
Net plant, property & equipment	$	126,587	$	127,577
Gas stored underground		6,517		11,931
Other current assets		515		786
Deferred charges and other assets		49		277
Assets held for sale	$	133,668	$	140,571
Accounts payable and accrued liabilities	$	5,404	$	1,917
Other current liabilities		6,857		4,877
Regulatory cost of removal		7,687		10,498
Deferred credits and other liabilities		872		1,153
Liabilities held for sale	$	20,820	$	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 six months ended March 31, 2012.

Long-term debt

Long-term debt at March 31, 2012 and September 30, 2011 consisted of the following:

	March 31, 2012			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		196			262
Total long-term debt		2,210,196			2,212,565
Less:
Original issue discount on unsecured senior notes and debentures		(3,852	)		(4,014	)
Current maturities		(250,131	)		(2,434	)
	$	1,956,213		$	2,206,117

23

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. As noted above, our Unsecured 5.125% Senior Notes will mature in January 2013; accordingly, these have been classified within the current maturities of long-term debt.

Short-term debt

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

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 March 31, 2012 and September 30, 2011, there was $174.0 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 March 31, 2012. Our $25 million unsecured facility was renewed effective April 1, 2012. This facility bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin.

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 $82.0 million at March 31, 2012.

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.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 March 31, 2012, $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 March 31, 2012, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 52 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 March 31, 2012, AEM’s ratio of total liabilities to tangible net worth, as defined, was 0.97 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at March 31, 2012, AEM’s net working capital was $105.9 million and its tangible net worth was $142.5 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 March 31, 2012. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

7.    Earnings Per Share

Since we have non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents (referred to as participating securities) we are required to use the two-class method of computing earnings per share. The Company’s non-vested restricted stock and restricted stock units, for which vesting is predicated solely on the passage of time granted under our 1998 Long-Term Incentive Plan, are considered to be participat-

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ing securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three and six months ended March 31, 2012 and 2011 are calculated as follows:

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
	(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	105,910	$	128,160	$	171,698	$	199,260
Less: Income from continuing operations allocated to participating securities		1,109		1,342		1,794		2,089
Income from continuing operations available to common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
Basic weighted average shares outstanding		90,020		90,246		90,137		90,157
Income from continuing operations per share — Basic	$	1.16	$	1.41	$	1.89	$	2.18
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	3,201	$	4,049	$	5,920	$	6,946
Less: Income from discontinued operations allocated to participating securities		34		42		62		73
Income from discontinued operations available to common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
Basic weighted average shares outstanding		90,020		90,246		90,137		90,157
Income from discontinued operations per share — Basic	$	0.04	$	0.04	$	0.06	$	0.08
Net income per share — Basic	$	1.20	$	1.45	$	1.95	$	2.26

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
	(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
Effect of dilutive stock options and other shares		3		3		4		5
Income from continuing operations available to common shareholders	$	104,804	$	126,821	$	169,908	$	197,176
Basic weighted average shares outstanding		90,020		90,246		90,137		90,157
Additional dilutive stock options and other shares		302		287		303		298
Diluted weighted average shares outstanding		90,322		90,533		90,440		90,455
Income from continuing operations per share — Diluted	$	1.16	$	1.41	$	1.88	$	2.18
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
Effect of dilutive stock options and other shares		—		—		—		—
Income from discontinued operations available to common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
Basic weighted average shares outstanding		90,020		90,246		90,137		90,157
Additional dilutive stock options and other shares		302		287		303		298
Diluted weighted average shares outstanding		90,322		90,533		90,440		90,455
Income from discontinued operations per share — Diluted	$	0.04	$	0.04	$	0.06	$	0.08
Net income per share — Diluted	$	1.20	$	1.45	$	1.94	$	2.26

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2012 and 2011 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. However, 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 March 31, 2012, 387,991 shares had been repurchased for an aggregate value of $12.5 million.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8.    Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and six months ended March 31, 2012 and 2011 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 March 31
	Pension Benefits						Other Benefits
	2012			2011			2012			2011
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,298		$	4,257		$	4,088		$	3,601
Interest cost		6,678			7,055			3,466			3,203
Expected return on assets		(5,369	)		(6,285	)		(652	)		(682	)
Amortization of transition asset		—			—			378			378
Amortization of prior service cost		(36	)		(105	)		(363	)		(363	)
Amortization of actuarial loss		4,143			2,748			662			86
Curtailment gain		—			(40	)		—			—
Net periodic pension cost	$	9,714		$	7,630		$	7,579		$	6,223

	Six Months Ended March 31
	Pension Benefits						Other Benefits
	2012			2011			2012			2011
	(In thousands)
Components of net periodic pension cost:
Service cost	$	8,596		$	8,637		$	8,176		$	7,202
Interest cost		13,355			13,979			6,931			6,406
Expected return on assets		(10,737	)		(12,248	)		(1,304	)		(1,364	)
Amortization of transition asset		—			—			756			756
Amortization of prior service cost		(71	)		(217	)		(725	)		(725	)
Amortization of actuarial loss		8,285			6,242			1,324			173
Curtailment gain		—			(40	)		—			—
Net periodic pension cost	$	19,428		$	16,353		$	15,158		$	12,448

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2012 and 2011 are as follows:

	Pension Account Plan						Other Pension  Benefits						Other Benefits
	2012			2011			2012			2011			2012			2011
Discount rate		5.05	%		5.68	%		5.05	%		5.39	%		5.05	%		5.39	%
Rate of compensation increase		3.50	%		4.00	%		3.50	%		4.00	%		N/A			N/A
Expected return on plan assets		7.75	%		8.25	%		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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 contributed $23.0 million to our defined benefit pension plans during the second fiscal quarter to achieve a desirable PPA funding threshold. The need for this funding reflects the increased pension benefit obligation due to a decrease in the discount rate compared to the prior year as well as a decline in the fair value of plan assets. During the first six months of fiscal 2012, we contributed $34.2 million to our defined benefit plans and we anticipate contributing an additional $12.4 million during the remainder of the fiscal year.

We contributed $9.1 million to our other post-retirement benefit plans during the six months ended March 31, 2012. We expect to contribute a total of approximately $10 million to $15 million to these plans during the remainder of the fiscal year.

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 six months ended March 31, 2012.

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 appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court on March 19, 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

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. On March 27, 2012 the court denied the motion to dismiss.

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 March 31, 2012, AEH was committed to purchase 96.2 Bcf within one year, 23.5 Bcf within one to three years and 0.6 Bcf after three years under indexed contracts. AEH is committed to purchase 3.5 Bcf within one year and 0.6 Bcf within one to three years under fixed price contracts with prices ranging from $1.75 to $6.36 per Mcf. Purchases under these contracts totaled $264.3 million and $438.9 million for the three months ended March 31, 2012 and 2011 and $576.4 million and $773.1 million for the six months ended March 31, 2012 and 2011.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of March 31, 2012 are as follows (in thousands):

2012	$	33,347
2013		71,496
2014		61,594
2015		—
2016		—
Thereafter		—
	$	166,437

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

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 six months ended March 31, 2012.

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 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 March 31, 2012, we had replaced 73,822 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 $81.4 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 Commodity Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the SEC and CFTC 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 the Company. 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. Additional reporting and disclosure obligations have been imposed upon the Company, the full extent of which will not be known until the SEC and the CFTC have completed their ongoing rulemaking process.

As of March 31, 2012, rate cases were in progress in our Mid-Tex, West Texas and Kansas service areas and annual rate filing mechanisms were in progress in our Mid-Tex and Louisiana service areas along with one infrastructure program filing in progress in our Atmos Pipeline — Texas 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 six months ended March 31, 2012, there were no material changes in our concentration of credit risk.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Income statements for the three and six month periods ended March 31, 2012 and 2011 by segment are presented in the following tables:

	Three Months Ended March 31, 2012
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	888,685	$	20,430		$	334,335		$	—		$	1,243,450
Intersegment revenues		323		37,607			36,428			(74,358	)		—
		889,008		58,037			370,763			(74,358	)		1,243,450
Purchased gas cost		508,206		—			374,992			(74,009	)		809,189
Gross profit		380,802		58,037			(4,229	)		(349	)		434,261
Operating expenses
Operation and maintenance		89,443		15,847			5,769			(351	)		110,708
Depreciation and amortization		51,755		7,792			725			—			60,272
Taxes, other than income		50,313		3,915			691			—			54,919
Total operating expenses		191,511		27,554			7,185			(351	)		225,899
Operating income (loss)		189,291		30,483			(11,414	)		2			208,362
Miscellaneous income (expense)		733		(56	)		567			(628	)		616
Interest charges		28,833		7,614			839			(626	)		36,660
Income (loss) from continuing operations before income taxes		161,191		22,813			(11,686	)		—			172,318
Income tax expense (benefit)		62,890		8,193			(4,675	)		—			66,408
Income (loss) from continuing operations		98,301		14,620			(7,011	)		—			105,910
Income from discontinued operations, net of tax		3,201		—			—			—			3,201
Net income (loss)	$	101,502	$	14,620		$	(7,011	)	$	—		$	109,111
Capital expenditures	$	114,402	$	38,871		$	3,456		$	—		$	156,729

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Three Months Ended March 31, 2011
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,077,178	$	21,597	$	482,722		$	—		$	1,581,497
Intersegment revenues		236		33,379		100,809			(134,424	)		—
		1,077,414		54,976		583,531			(134,424	)		1,581,497
Purchased gas cost		698,410		—		563,473			(134,054	)		1,127,829
Gross profit		379,004		54,976		20,058			(370	)		453,668
Operating expenses
Operation and maintenance		92,266		15,231		7,035			(370	)		114,162
Depreciation and amortization		48,555		5,798		1,114			—			55,467
Taxes, other than income		50,088		4,113		(643	)		—			53,558
Asset impairment		—		—		19,282			—			19,282
Total operating expenses		190,909		25,142		26,788			(370	)		242,469
Operating income (loss)		188,095		29,834		(6,730	)		—			211,199
Miscellaneous income		20,156		5,861		306			(121	)		26,202
Interest charges		29,605		8,085		306			(121	)		37,875
Income (loss) from continuing operations before income taxes		178,646		27,610		(6,730	)		—			199,526
Income tax expense (benefit)		64,085		9,871		(2,590	)		—			71,366
Income (loss) from continuing operations		114,561		17,739		(4,140	)		—			128,160
Income from discontinued operations, net of tax		4,049		—		—			—			4,049
Net income (loss)	$	118,610	$	17,739	$	(4,140	)	$	—		$	132,209
Capital expenditures	$	109,762	$	11,818	$	1,921		$	—		$	123,501

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Six Months Ended March 31, 2012
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,581,753		$	39,870		$	723,000		$	—		$	2,344,623
Intersegment revenues		547			74,926			91,939			(167,412	)		—
		1,582,300			114,796			814,939			(167,412	)		2,344,623
Purchased gas cost		910,413			—			803,763			(166,696	)		1,547,480
Gross profit		671,887			114,796			11,176			(716	)		797,143
Operating expenses
Operation and maintenance		182,857			32,812			11,820			(719	)		226,770
Depreciation and amortization		102,586			15,443			1,458			—			119,487
Taxes, other than income		88,792			7,699			1,626			—			98,117
Total operating expenses		374,235			55,954			14,904			(719	)		444,374
Operating income (loss)		297,652			58,842			(3,728	)		3			352,769
Miscellaneous income (expense)		(1,023	)		(336	)		603			(503	)		(1,259	)
Interest charges		56,688			14,823			1,091			(500	)		72,102
Income (loss) from continuing operations before income taxes		239,941			43,683			(4,216	)		—			279,408
Income tax expense (benefit)		93,735			15,649			(1,674	)		—			107,710
Income (loss) from continuing operations		146,206			28,034			(2,542	)		—			171,698
Income from discontinued operations, net of tax		5,920			—			—			—			5,920
Net income (loss)	$	152,126		$	28,034		$	(2,542	)	$	—		$	177,618
Capital expenditures	$	243,135		$	62,991		$	4,997		$	—		$	311,123

34

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Six Months Ended March 31, 2011
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,780,439	$	42,830	$	891,490	$	—		$	2,714,759
Intersegment revenues		437		61,153		167,681		(229,271	)		—
		1,780,876		103,983		1,059,171		(229,271	)		2,714,759
Purchased gas cost		1,110,936		—		1,013,935		(228,504	)		1,896,367
Gross profit		669,940		103,983		45,236		(767	)		818,392
Operating expenses
Operation and maintenance		181,495		30,805		17,119		(767	)		228,652
Depreciation and amortization		96,449		11,597		2,198		—			110,244
Taxes, other than income		84,536		7,666		1,524		—			93,726
Asset impairment		—		—		19,282		—			19,282
Total operating expenses		362,480		50,068		40,123		(767	)		451,904
Operating income		307,460		53,915		5,113		—			366,488
Miscellaneous income		19,458		5,579		596		(157	)		25,476
Interest charges		59,302		16,149		1,476		(157	)		76,770
Income from continuing operations before income taxes		267,616		43,345		4,233		—			315,194
Income tax expense		98,634		15,504		1,796		—			115,934
Income from continuing operations		168,982		27,841		2,437		—			199,260
Income from discontinued operations, net of tax		6,946		—		—		—			6,946
Net income	$	175,928	$	27,841	$	2,437	$	—		$	206,206
Capital expenditures	$	219,261	$	24,557	$	2,845	$	—		$	246,663

35

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at March 31, 2012 and September 30, 2011 by segment is presented to reflect our business structure as of March 31, 2012 in the following tables.

	March 31, 2012
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,382,291	$	886,507	$	65,214		$	—		$	5,334,012
Investment in subsidiaries		674,594		—		(2,096	)		(672,498	)		—
Current assets
Cash and cash equivalents		40,140		—		6,900			—			47,040
Assets from risk management activities		502		—		2,877			—			3,379
Other current assets		632,486		13,278		399,389			(201,731	)		843,422
Intercompany receivables		584,018		—		—			(584,018	)		—
Total current assets		1,257,146		13,278		409,166			(785,749	)		893,841
Intangible assets		—		—		185			—			185
Goodwill		572,908		132,381		34,711			—			740,000
Noncurrent assets from risk management activities		—		—		10,841			—			10,841
Deferred charges and other assets		366,329		13,203		10,316			—			389,848
	$	7,253,268	$	1,045,369	$	528,337		$	(1,458,247	)	$	7,368,727
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,360,712	$	293,135	$	381,459		$	(674,594	)	$	2,360,712
Long-term debt		1,956,147		—		66			—			1,956,213
Total capitalization		4,316,859		293,135		381,525			(674,594	)		4,316,925
Current liabilities
Current maturities of long-term debt		250,000		—		131			—			250,131
Short-term debt		371,996		—		—			(198,000	)		173,996
Liabilities from risk management activities		47,281		—		5,296			—			52,577
Other current liabilities		507,354		6,309		119,382			(1,635	)		631,410
Intercompany payables		—		551,330		32,688			(584,018	)		—
Total current liabilities		1,176,631		557,639		157,497			(783,653	)		1,108,114
Deferred income taxes		890,455		188,936		(16,903	)		—			1,062,488
Noncurrent liabilities from risk management activities		1		—		5,300			—			5,301
Regulatory cost of removal obligation		414,001		—		—			—			414,001
Deferred credits and other liabilities		455,321		5,659		918			—			461,898
	$	7,253,268	$	1,045,369	$	528,337		$	(1,458,247	)	$	7,368,727

36

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

37

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 March 31, 2012, the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2012 and 2011, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2012 and 2011. 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

May 3, 2012

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

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 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 our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas currently located in 12 states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. In May 2011, we 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 primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions

39

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 six months ended March 31, 2012.

RESULTS OF OPERATIONS

Atmos Energy Corporation is involved in the distribution, marketing and transportation of natural gas. Accordingly, our results of operations are impacted by the demand for natural gas, particularly during the winter heating season, and the volatility of the natural gas markets. This generally results in higher operating revenues and net income during the period from October through March of each fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal year. As a result of the seasonality of the natural gas industry, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 62 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years.

Additionally, the seasonality of our business impacts our working capital differently at various times during the year. Typically, our accounts receivable, accounts payable and short-term debt balances peak by the end of January and then start to decline, as customers begin to pay their winter heating bills. Gas stored underground, particularly in our natural gas distribution segment, typically peaks in November and declines as we utilize storage gas to serve our customers.

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We reported net income of $109.1 million, or $1.20 per diluted share for the three months ended March 31, 2012, compared with net income of $132.2 million or $1.45 per diluted share in the prior year. Excluding the impact of unrealized margins, diluted earnings per share decreased $0.19 compared with the prior-year quarter. Results for the prior-year period were influenced by the net positive impact of several one-time items totaling $11.1 million, or $0.12 per diluted share related to the following pre-tax amounts:

• $27.8 million favorable impact related to a cash gain recorded in association with the unwinding of two Treasury locks in conjunction with the cancellation of a previously planned debt offering.

• $19.3 million unfavorable impact related to the non-cash impairment of certain assets in our nonregulated business.

• $5.0 million favorable impact related to the administrative settlement of various income tax positions.

After excluding the impact of unrealized margins and the one-time items, net income and diluted earnings per share for the three months ended March 31, 2012 decreased $6.4 million, or $0.07 per diluted share when compared to the prior-year period, primarily due to lower earnings in our nonregulated segment due to historically warm winter weather and unfavorable natural gas market conditions. Included in the current quarter amount is net income from discontinued operations of $3.2 million, or $0.04 per diluted share associated with the pending sale of our Missouri, Illinois and Iowa service areas, a decrease of $0.8 million or $0.00 per diluted share compared with the prior-year quarter.

During the six months ended March 31, 2012, we earned $177.6 million or $1.94 per diluted share, which represents a 14 percent decrease in net income and diluted net income per share compared with the prior-year period. Results for the prior-year period were influenced by the net positive impact of several one-time items totaling $11.1 million, or $0.12 per diluted share. Excluding the impact of these one-time items and unrealized margins in our nonregulated operations, we earned $172.3 million, or $1.88 per diluted share for the six months ended March 31, 2012, compared to $196.8 million, or $2.16 in the prior-year period. Included in the current period amount is net income from discontinued operations of $5.9 million, or $0.06 per diluted share associated with the pending sale of our Missouri, Illinois and Iowa service areas, a decrease of $1.0 million or $0.02 per diluted share compared with the prior-year period.

Our quarter-to-date and year-to-date results were unfavorably impacted by substantially warmer winter weather and an abundance of natural gas supply. The impact of these conditions was most significantly realized in our nonregulated operations, which experienced a $23.0 million six-month period-over-period decrease in net income, excluding the impact of one-time items and unrealized margins. These market conditions also contributed to a 10 percent decrease in throughput in our natural gas distribution segment and lower through-system transportation rates earned on our regulated intrastate pipeline for the six months ended March 31, 2012 compared to the six months ended March 31, 2011. However, the impact on our regulated operations was not as significant due to favorable rate designs, which substantially mitigated the effects of relatively warm weather in most of our natural gas distribution service areas and the favorable impact of rate case increases experienced in both our natural gas distribution and regulated transmission and storage segments.

During the fiscal second quarter, we undertook several steps to grow earnings in our regulated operations. In our natural gas distribution segment, we initiated seven rate proceedings requesting a total of $68.7 million in additional annual operating income and, in April 2012, we completed an annual rate filing for Atmos Pipeline-Texas (APT) that should increase annual operating income by $14.7 million. Further, we announced two significant pipeline expansion projects whereby APT will spend $150 million over the next two fiscal years to increase its ability to secure new long-term gas supply on a firm and reliable basis and to enhance the reliability of APT’s service to our Mid-Tex Division in certain critical locations.

During the second fiscal quarter, we completed the annual evaluation of the funded status of our qualified defined benefit plans as of January 1, 2012 as required by the Pension Protection Act of 2006 (PPA). As a result of lower asset returns and a year-over-year 92 basis point decline in the discount rate used to value our pension liabilities, we were required to contribute $23.0 million into the plans. For the six months ended March 31, 2012, we contributed $34.2 million into these plans and expect to contribute an additional $12.4 million for the

41

remainder of the fiscal year. Additionally, we contributed $9.1 million into our postretirement medical plans during the six months ended March 31, 2012 and expect to contribute between $10 million and $15 million for the remainder of the fiscal year. We believe our cash flows from operations are sufficient to fund these contributions.

Consolidated Results

The following table presents our consolidated financial highlights for the three and six months ended March 31, 2012 and 2011:

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012			2011
	(In thousands, except per share data)
Operating revenues	$	1,243,450	$	1,581,497	$	2,344,623		$	2,714,759
Gross profit		434,261		453,668		797,143			818,392
Operating expenses		225,899		242,469		444,374			451,904
Operating income		208,362		211,199		352,769			366,488
Miscellaneous income (expense)		616		26,202		(1,259	)		25,476
Interest charges		36,660		37,875		72,102			76,770
Income from continuing operations before income taxes		172,318		199,526		279,408			315,194
Income tax expense		66,408		71,366		107,710			115,934
Income from continuing operations		105,910		128,160		171,698			199,260
Income from discontinued operations, net of tax		3,201		4,049		5,920			6,946
Net income	$	109,111	$	132,209	$	177,618		$	206,206
Diluted net income per share from continuing operations	$	1.16	$	1.41	$	1.88		$	2.18
Diluted net income per share from discontinued operations		0.04		0.04		0.06			0.08
Diluted net income per share	$	1.20	$	1.45	$	1.94		$	2.26

Our consolidated net income during the three and six month periods ended March 31, 2012 and 2011 was earned in each of our business segments as follows:

	Three Months Ended March 31
	2012			2011			Change
	(In thousands)
Natural gas distribution segment from continuing operations	$	98,301		$	114,561		$	(16,260	)
Regulated transmission and storage segment		14,620			17,739			(3,119	)
Nonregulated segment		(7,011	)		(4,140	)		(2,871	)
Net income from continuing operations		105,910			128,160			(22,250	)
Net income from discontinued operations		3,201			4,049			(848	)
Net income	$	109,111		$	132,209		$	(23,098	)

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	Six Months Ended March 31
	2012			2011		Change
	(In thousands)
Natural gas distribution segment from continuing operations	$	146,206		$	168,982	$	(22,776	)
Regulated transmission and storage segment		28,034			27,841		193
Nonregulated segment		(2,542	)		2,437		(4,979	)
Net income from continuing operations		171,698			199,260		(27,562	)
Net income from discontinued operations		5,920			6,946		(1,026	)
Net income	$	177,618		$	206,206	$	(28,588	)

Regulated operations contributed 106 percent and 101 percent to our consolidated net income for the three and six month periods ended March 31, 2012. The following tables segregate our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:

	Three Months Ended March 31
	2012			2011			Change
	(In thousands, except per share data)
Regulated operations	$	112,921		$	132,300		$	(19,379	)
Nonregulated operations		(7,011	)		(4,140	)		(2,871	)
Net income from continuing operations		105,910			128,160			(22,250	)
Net income from discontinued operations		3,201			4,049			(848	)
Net income	$	109,111		$	132,209		$	(23,098	)
Diluted EPS from continuing regulated operations	$	1.23		$	1.45		$	(0.22	)
Diluted EPS from nonregulated operations		(0.07	)		(0.04	)		(0.03	)
Diluted EPS from continuing operations		1.16			1.41			(0.25	)
Diluted EPS from discontinued operations		0.04			0.04			—
Consolidated diluted EPS	$	1.20		$	1.45		$	(0.25	)

	Six Months Ended March 31
	2012			2011		Change
	(In thousands, except per share data)
Regulated operations	$	174,240		$	196,823	$	(22,583	)
Nonregulated operations		(2,542	)		2,437		(4,979	)
Net income from continuing operations		171,698			199,260		(27,562	)
Net income from discontinued operations		5,920			6,946		(1,026	)
Net income	$	177,618		$	206,206	$	(28,588	)
Diluted EPS from continuing regulated operations	$	1.91		$	2.15	$	(0.24	)
Diluted EPS from nonregulated operations		(0.03	)		0.03		(0.06	)
Diluted EPS from continuing operations		1.88			2.18		(0.30	)
Diluted EPS from discontinued operations		0.06			0.08		(0.02	)
Consolidated diluted EPS	$	1.94		$	2.26	$	(0.32	)

43

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. Conversely, lower gas costs reduce our collection risk and reduce the need to utilize short-term borrowings to fund our working capital needs.

As discussed above, in May 2011, we 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.

44

Three Months Ended March 31, 2012 compared with Three Months Ended March 31, 2011

Financial and operational highlights for our natural gas distribution segment for the three months ended March 31, 2012 and 2011 are presented below.

	Three Months Ended March 31
	2012		2011		Change
	(In thousands, unless otherwise noted)
Gross profit	$	380,802	$	379,004	$	1,798
Operating expenses		191,511		190,909		602
Operating income		189,291		188,095		1,196
Miscellaneous income		733		20,156		(19,423	)
Interest charges		28,833		29,605		(772	)
Income from continuing operations before income taxes		161,191		178,646		(17,455	)
Income tax expense		62,890		64,085		(1,195	)
Income from continuing operations		98,301		114,561		(16,260	)
Income from discontinued operations, net of tax		3,201		4,049		(848	)
Net income	$	101,502	$	118,610	$	(17,108	)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf		103,169		132,517		(29,348	)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf		36,877		37,378		(501	)
Consolidated natural gas distribution throughput from continuing operations — MMcf		140,046		169,895		(29,849	)
Consolidated natural gas distribution throughput from discontinued operations — MMcf		4,848		6,406		(1,558	)
Total consolidated natural gas distribution throughput — MMcf		144,894		176,301		(31,407	)
Consolidated natural gas distribution average transportation revenue per Mcf	$	0.43	$	0.47	$	(0.04	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	4.94	$	5.28	$	(0.34	)

The $1.8 million increase in natural gas distribution gross profit was primarily due to a $6.4 million net increase in rate adjustments, primarily in our Mid-Tex, Mississippi and Louisiana service areas, combined with a $1.0 million increase in customers, primarily in our Mid-Tex service area.

These increases were partially offset by a $5.9 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.

Results for the second fiscal quarter were also unfavorably impacted by significantly warmer winter weather, which resulted in an 18 percent decrease in total consolidated throughput compared to the prior year. However, the impact to gross profit was mitigated by favorable rate designs that substantially lessened the impact of warm weather in most of our natural gas distribution service areas.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $0.6 million primarily due to the following:

• $3.2 million increase in depreciation and amortization associated with an increase in our net plant as a result of our capital investments in the prior year.

45

• $1.1 million net increase in legal and other administrative costs.

• $1.2 million increase in software maintenance costs.

These increases were partially offset by the following:

• $2.0 million decrease in revenue-related taxes. When combined with the $5.9 million decrease in associated revenue taxes included in gross margin, we experienced a net $3.9 million quarter-over-quarter decrease in operating income.

• $1.4 million decrease due to the establishment of a regulatory asset in Texas for pension and post-retirement costs.

• $1.0 million decrease in operating expenses due to increased capital spending and warmer weather allowing us time to complete more capital work than in the prior year.

Net income for this segment for the prior-year quarter was favorably impacted by a $21.8 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks and a $5.0 million income tax benefit related to the administrative settlement of various income tax positions.

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 March 31, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	Three Months Ended March 31
	2012		2011		Change
	(In thousands)
Mid-Tex	$	88,301	$	82,476	$	5,825
Kentucky/Mid-States		24,655		28,837		(4,182	)
Louisiana		22,470		23,235		(765	)
West Texas		17,989		19,280		(1,291	)
Mississippi		17,537		18,004		(467	)
Colorado-Kansas		13,982		15,250		(1,268	)
Other		4,357		1,013		3,344
Total	$	189,291	$	188,095	$	1,196

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Six Months Ended March 31, 2012 compared with Six Months Ended March 31, 2011

Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2012 and 2011 are presented below.

	Six Months Ended March 31
	2012			2011		Change
	(In thousands, unless otherwise noted)
Gross profit	$	671,887		$	669,940	$	1,947
Operating expenses		374,235			362,480		11,755
Operating income		297,652			307,460		(9,808	)
Miscellaneous income (expense)		(1,023	)		19,458		(20,481	)
Interest charges		56,688			59,302		(2,614	)
Income from continuing operations before income taxes		239,941			267,616		(27,675	)
Income tax expense		93,735			98,634		(4,899	)
Income from continuing operations		146,206			168,982		(22,776	)
Income from discontinued operations, net of tax		5,920			6,946		(1,026	)
Net income	$	152,126		$	175,928	$	(23,802	)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf		188,059			216,654		(28,595	)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf		69,709			69,596		113
Consolidated natural gas distribution throughput from continuing operations — MMcf		257,768			286,250		(28,482	)
Consolidated natural gas distribution throughput from discontinued operations — MMcf		8,874			10,595		(1,721	)
Total consolidated natural gas distribution throughput — MMcf		266,642			296,845		(30,203	)
Consolidated natural gas distribution average transportation revenue per Mcf	$	0.44		$	0.48	$	(0.04	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	4.87		$	5.14	$	(0.27	)

The $1.9 million increase in natural gas distribution gross profit was primarily due to an $11.0 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Mississippi, Kentucky and West Texas service areas.

These increases were partially offset by the following:

• $2.9 million decrease due to a 10 percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather in the current quarter compared to the same period last year in most of our service areas.

• $5.6 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $11.8 million primarily due to the following:

• $6.1 million increase in depreciation and amortization and a $5.5 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.

47

• $7.6 million net increase in legal and other administrative costs.

• $1.8 million increase in software maintenance costs.

These increases were partially offset by the following:

• $4.0 million decrease in operating expenses due to increased capital spending and warmer weather allowing us time to complete more capital work than in the prior year.

• $1.8 million decrease in revenue-related taxes. When combined with the $5.6 million decrease in associated revenue taxes included in gross margin, we experienced a net $3.8 million year-over-year decrease in operating income.

• $1.4 million decrease associated with the aforementioned regulatory asset.

Net income from the prior-year period also reflects the aforementioned Treasury lock gain and income tax benefit.

The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the six months ended March 31, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	Six Months Ended March 31
	2012		2011		Change
	(In thousands)
Mid-Tex	$	136,750	$	139,915	$	(3,165	)
Kentucky/Mid-States		40,973		45,690		(4,717	)
Louisiana		37,671		38,196		(525	)
West Texas		28,664		28,800		(136	)
Mississippi		27,669		28,219		(550	)
Colorado-Kansas		22,161		22,952		(791	)
Other		3,764		3,688		76
Total	$	297,652	$	307,460	$	(9,808	)

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the six months ended March 31, 2012 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling.

Annual net operating income increases totaling $8.0 million resulting from ratemaking activity became effective in the six months ended March 31, 2012 as summarized below:

Rate Action	Annual Increase to Operating Income
	(In thousands)
Rate case filings	$	545
Infrastructure programs		3,744
Annual rate filing mechanisms		3,505
Other rate activity		167
	$	7,961

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

Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Mid-Tex	Rate Case	RRC	$	45,980
West Texas	Rate Case	RRC		11,137
Colorado-Kansas	Rate Case	Kansas		6,134
Mid-Tex	Dallas Annual Rate Review	RRC		2,545
Louisiana	Rate Stabilization Clause	LGS		1,823
Kentucky/Mid-States	PRP	Georgia		1,079
Louisiana	Rate Stabilization Clause	TransLa		—
			$	68,698

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 to 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 six months ended March 31, 2012.

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 occurring during the six months ended March 31, 2012.

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

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Annual Rate Filing Mechanisms

As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and the Georgia service area in our Kentucky/Mid-States Division. The Company is requesting new annual rate filing mechanisms as part of our ongoing rate cases in our Mid-Tex and West Texas divisions to replace the annual mechanisms that expired for significant portions of these service areas in 2011. These mechanisms are referred to as rate review mechanisms in our Mid-Tex and West Texas divisions, stable rate filings in the Mississippi Division and a rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms for the six months ended March 31, 2012.

Division	Jurisdiction	Test Year Ended		Additional Annual Operating Income			Effective Date
				(In thousands)
2012 Filings:
Kentucky/Mid-States	Georgia		09/30/2011	$	(818	)		02/01/2012
Mississippi	Mississippi		06/30/2011		4,323			01/11/2012
Total 2012 Filings				$	3,505

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the six months ended March 31, 2012:

Division	Jurisdiction		Rate Activity			Additional Annual Operating Income		Effective Date
						(In thousands)
2012 Other Rate Activity:
Colorado-Kansas		Kansas		Ad Valorem	(1)	$	167		01/14/2012
Total 2012 Other Rate Activity						$	167

⁽¹⁾  The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas area’s base rates.

Regulated Transmission and Storage Segment

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

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

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Three Months Ended March 31, 2012 compared with Three Months Ended March 31, 2011

Financial and operational highlights for our regulated transmission and storage segment for the three months ended March 31, 2012 and 2011 are presented below.

	Three Months Ended March 31
	2012			2011		Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	39,114		$	33,096	$	6,018
Third-party transportation		14,309			16,811		(2,502	)
Storage and park and lend services		1,867			2,219		(352	)
Other		2,747			2,850		(103	)
Gross profit		58,037			54,976		3,061
Operating expenses		27,554			25,142		2,412
Operating income		30,483			29,834		649
Miscellaneous income (expense)		(56	)		5,861		(5,917	)
Interest charges		7,614			8,085		(471	)
Income before income taxes		22,813			27,610		(4,797	)
Income tax expense		8,193			9,871		(1,678	)
Net income	$	14,620		$	17,739	$	(3,119	)
Gross pipeline transportation volumes — MMcf		176,361			174,471		1,890
Consolidated pipeline transportation volumes — MMcf		109,626			93,493		16,133

The $3.1 million increase in regulated transmission and storage gross profit compared to the prior-year quarter 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. Therefore, despite an 18 percent decrease in throughput to our Mid-Tex Division, we experienced an 18 percent increase in gross profit from Mid-Tex transportation.

For the quarter, the enhanced rate design resulted in an $8.4 million increase in gross profit compared to the prior-year quarter. This increase was partially offset by the following:

• $3.0 million decrease associated with lower throughput to our Mid-Tex Division.

• $1.5 million decrease in third-party transportation. Throughput associated with third-party transportation increased 17 percent due to the execution of new delivery contracts with local producers in the Barnett Shale region. However, these increases were more than offset by lower transportation rates.

Operating expenses increased $2.4 million primarily due to the following:

• $0.5 million increase due to higher pipeline maintenance costs.

• $2.0 million increase due to higher depreciation expense, resulting from the rate case and a higher investment in net plant.

Net income for this segment for the prior-year quarter was favorably impacted by a $6.0 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks.

On April 10, 2012, the RRC approved the Atmos Pipeline — Texas GRIP filing that was filed in February 2012. The Commission approved an annual operating income increase of $14.7 million that went into effect with bills rendered on and after April 10, 2012.

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Six Months Ended March 31, 2012 compared with Six Months Ended March 31, 2011

Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2012 and 2011 are presented below.

	Six Months Ended March 31
	2012			2011		Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	76,457		$	60,631	$	15,826
Third-party transportation		29,248			33,323		(4,075	)
Storage and park and lend services		3,673			4,389		(716	)
Other		5,418			5,640		(222	)
Gross profit		114,796			103,983		10,813
Operating expenses		55,954			50,068		5,886
Operating income		58,842			53,915		4,927
Miscellaneous income (expense)		(336	)		5,579		(5,915	)
Interest charges		14,823			16,149		(1,326	)
Income before income taxes		43,683			43,345		338
Income tax expense		15,649			15,504		145
Net income	$	28,034		$	27,841	$	193
Gross pipeline transportation volumes — MMcf		337,190			327,649		9,541
Consolidated pipeline transportation volumes — MMcf		214,663			193,334		21,329

The $10.8 million increase in regulated transmission and storage gross profit compared to the prior-year period was primarily a result of the previously discussed rate design changes approved in the rate case in the prior year. Therefore, despite a nine percent decrease in throughput to our Mid-Tex Division, we experienced a 26 percent increase in gross profit from Mid-Tex transportation.

For the year-to-date period, the enhanced rate design resulted in a $16.9 million increase in gross profit compared to the prior-year period. This increase was partially offset by the following:

• $2.5 million decrease associated with lower throughput to our Mid-Tex Division.

• $2.5 million decrease in third-party transportation. Throughput associated with third-party transportation increased 11 percent due to the execution of new delivery contracts with local producers in the Barnett Shale region. However, these increases were more than offset by lower transportation rates.

Operating expenses increased $5.9 million primarily due to the following:

• $1.8 million increase due to higher pipeline maintenance costs.

• $3.8 million increase due to higher depreciation expense, resulting from the rate case and a higher investment in net plant.

Net income from the prior-year period also reflects the aforementioned Treasury lock gain.

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.

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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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Three Months Ended March 31, 2012 compared with Three Months Ended March 31, 2011

Financial and operational highlights for our nonregulated segment for the three months ended March 31, 2012 and 2011 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers, margins earned from storage and transportation services and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.

	Three Months Ended March 31
	2012			2011			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	14,271		$	19,170		$	(4,899	)
Storage and transportation services		3,451			3,522			(71	)
Other		996			1,460			(464	)
		18,718			24,152			(5,434	)
Asset optimization(1)		(10,045	)		(686	)		(9,359	)
Total realized margins		8,673			23,466			(14,793	)
Unrealized margins		(12,902	)		(3,408	)		(9,494	)
Gross profit		(4,229	)		20,058			(24,287	)
Operating expenses, excluding asset impairment		7,185			7,506			(321	)
Asset impairment		—			19,282			(19,282	)
Operating loss		(11,414	)		(6,730	)		(4,684	)
Miscellaneous income		567			306			261
Interest charges		839			306			533
Loss before income taxes		(11,686	)		(6,730	)		(4,956	)
Income tax benefit		(4,675	)		(2,590	)		(2,085	)
Net loss	$	(7,011)		$	(4,140	)	$	(2,871	)
Gross nonregulated delivered gas sales volumes — MMcf		111,656			127,377			(15,721	)
Consolidated nonregulated delivered gas sales volumes — MMcf		99,844			107,566			(7,722	)
Net physical position (Bcf)		38.0			17.7			20.3

⁽¹⁾  Net of storage fees of $4.8 million and $3.6 million.

Results for our nonregulated operations during the second fiscal quarter continue to be adversely influenced by unfavorable natural gas market conditions. Historically high natural gas storage levels caused by strong domestic natural gas production coupled with lower demand driven by an unseasonably warm 2011-2012 winter heating season caused natural gas prices to remain relatively low during our fiscal second quarter. As a result, we continue to experience compressed spot to forward spread values and basis differentials. Additionally, we experienced a quarter-over-quarter decrease in sales volumes due to the relatively warm weather.

We anticipate natural gas storage levels will remain high for an extended period of time. Therefore, we anticipate that basis differentials will remain compressed, which will limit arbitrage and sales opportunities from buying gas in one location and delivering gas into another location. Additionally, we expect gas prices will remain relatively low with lower spot to forward spread volatility relative to recent years. Accordingly, although

54

we anticipate continuing to profit on a fiscal-year basis from our nonregulated activities, we anticipate per-unit margins from our delivered gas activities and margins earned from our asset optimization activities will be lower than in previous years for the foreseeable future.

Realized margins for gas delivery, storage and transportation services and other services were $18.7 million during the three months ended March 31, 2012 compared with $24.2 million for the prior-year quarter. The decrease reflects the following:

• A seven percent decrease in consolidated sales volumes. The decrease was largely attributable to warmer weather, which reduced sales to utility, municipal and other weather-sensitive customers.

• A decrease in gas delivery per-unit margins from $0.15/Mcf in the prior-year quarter to $0.13/Mcf in the current-year quarter primarily due to lower basis differentials resulting from increased natural gas supply. The decrease in basis differentials was partially offset by increased fees earned from certain transportation arrangements and the receipt of a one-time refund of transportation demand fees from one of our transporters.

Asset optimization margins decreased $9.4 million from the prior-year quarter. In the current year quarter, AEH continued to take advantage of falling natural gas prices by purchasing and injecting a net 8.9 Bcf into storage and capturing incremental physical to forward spread values that should be realized primarily in the third and fourth quarter of fiscal 2012. As a result of this decision and falling prices, we realized significantly higher losses on the settlement of financial instruments used to hedge our natural gas purchases. Additionally, AEH experienced increased storage fees associated with increased park and loan activity.

The $9.5 million decrease in unrealized margins primarily reflects the impact of falling prices on our physical inventory as this hedged inventory is marked to market.

Operating expenses, excluding asset impairment, decreased $0.3 million primarily due to lower employee-related expenses. In the prior-year quarter, an asset impairment charge of $19.3 million was recorded related to our investment in Fort Necessity, which resulted in a write-off of substantially all of our investment in the project.

55

Six Months Ended March 31, 2012 compared with Six Months Ended March 31, 2011

Financial and operational highlights for our natural gas marketing segment for the six months ended March 31, 2012 and 2011 are presented below.

	Six Months Ended March 31
	2012			2011			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	25,384		$	35,211		$	(9,827	)
Storage and transportation services		6,640			6,871			(231	)
Other		2,013			2,779			(766	)
		34,037			44,861			(10,824	)
Asset optimization(1)		(31,639	)		3,279			(34,918	)
Total realized margins		2,398			48,140			(45,742	)
Unrealized margins		8,778			(2,904	)		11,682
Gross profit		11,176			45,236			(34,060	)
Operating expenses, excluding asset impairment		14,904			20,841			(5,937	)
Asset impairment		—			19,282			(19,282	)
Operating income (loss)		(3,728	)		5,113			(8,841	)
Miscellaneous income		603			596			7
Interest charges		1,091			1,476			(385	)
Income (loss) before income taxes		(4,216	)		4,233			(8,449	)
Income tax expense (benefit)		(1,674	)		1,796			(3,470	)
Net income (loss)	$	(2,542)		$	2,437		$	(4,979	)
Gross nonregulated delivered gas sales volumes — MMcf		218,118			235,089			(16,971	)
Consolidated nonregulated delivered gas sales volumes — MMcf		190,714			202,104			(11,390	)
Net physical position (Bcf)		38.0			17.7			20.3

⁽¹⁾  Net of storage fees of $9.5 million and $6.9 million.

Realized margins for gas delivery, storage and transportation services and other services were $34.0 million during the six months ended March 31, 2012 compared with $44.9 million for the prior-year period. The decrease reflects the following:

• A six percent decrease in consolidated sales volumes. The decrease was largely attributable to warmer weather, which reduced sales to utility, municipal and other weather-sensitive customers.

• A decrease in gas delivery per-unit margins from $0.15/Mcf in the prior-year quarter to $0.12/Mcf in the current-year quarter primarily due to lower basis differentials resulting from increased natural gas supply. The decrease in basis differentials was partially offset by increased fees earned from certain transportation arrangements and the receipt of a one-time refund of transportation demand fees from one of our transporters.

Asset optimization margins decreased $34.9 million from the prior-year period. The period-over-period decrease primarily reflects AEH’s decision to take advantage of falling natural prices by purchasing and injecting a net 24.6 Bcf into storage and capturing incremental physical to forward spread values that should be realized

56

primarily in the third and fourth quarter of fiscal 2012. As a result of this decision and falling prices, we realized significantly higher losses on the settlement of financial instruments used to hedge our natural gas purchases. Additionally, AEH experienced increased storage fees associated with increased park and loan activity. Finally, AEH incurred a $1.7 million charge in the first fiscal quarter to write-down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.

Unrealized margins increased $11.7 million in the current period compared to the prior-year period primarily due to the timing of year-over-year realized margins.

Operating expenses, excluding asset impairment decreased $5.9 million primarily due to lower employee-related expenses. Asset impairment includes the aforementioned pre-tax impairment charge recorded in the prior-year period related to the write-off of substantially all of the Fort Necessity project.

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 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.

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 six months ended March 31, 2012 and 2011 are presented below.

	Six Months Ended March 31
	2012			2011			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	360,723		$	438,471		$	(77,748	)
Investing activities		(315,001	)		(248,198	)		(66,803	)
Financing activities		(130,101	)		(168,979	)		38,878
Change in cash and cash equivalents		(84,379	)		21,294			(105,673	)
Cash and cash equivalents at beginning of period		131,419			131,952			(533	)
Cash and cash equivalents at end of period	$	47,040		$	153,246		$	(106,206	)

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Cash flows from operating activities

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

For the six months ended March 31, 2012, we generated operating cash flow of $360.7 million from operating activities compared with $438.5 million for the six months ended March 31, 2011. The $77.7 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, combined with $43.3 million in contributions made to our pension and postretirement plans during the first six months of fiscal 2012 and 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 currently expected to range from $690 million to $710 million. For the six months ended March 31, 2012, capital expenditures were $311.1 million compared with $246.7 million for the six months ended March 31, 2011. The $64.4 million increase in capital expenditures primarily reflects spending for the steel service line replacement program in the Mid-Tex Division and other infrastructure replacement projects in our Mid-Tex, West Texas and Kentucky service areas, the development of new customer billing and information systems for our natural gas distribution segment and increased capital spending to increase the capacity on our Atmos Pipeline — Texas system.

Cash flows from financing activities

For the six months ended March 31, 2012, our financing activities used $130.1 million of cash compared with $169.0 million of cash used in the prior-year period, primarily due to lower cash outflows associated with repayment of our short-term and long-term debt instruments, as follows:

• $80.0 million for short-term debt repayments. In the current-year period, $48.9 million of short-term debt was repaid, compared with $128.9 million in the prior-year period.

• $7.7 million for scheduled long-term debt repayments. In the current-year period, $2.4 million of long-term debt was repaid, compared with $10.1 million in the prior-year period.

The lower repayment activity was partially offset by:

• $27.8 million less cash received related to the unwinding of two Treasury locks in the prior year.

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

• $7.4 million less cash received from proceeds related to the issuance of common stock.

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The following table summarizes our share issuances for the six months ended March 31, 2012 and 2011.

	Six Months Ended March 31
	2012		2011
Shares issued:
1998 Long-Term Incentive Plan		219,712		663,555
Outside Directors Stock-for-Fee Plan		1,204		1,232
Total shares issued		220,916		664,787

The year-over-year decrease in the number of shares issued primarily reflects the significant number of stock options exercised in the prior year. During the current-year period, 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 typically 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 provided approximately $1.0 billion of working capital funding. As of March 31, 2012, the amount available to us under our credit facilities, net of outstanding letters of credit, was $687.2 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 March 31, 2012, $900 million was available for issuance. Of this amount, $550 million is available for the issuance of debt securities and $350 million remains available for the issuance of equity securities under the shelf until March 2013.

Credit Ratings

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

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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 March 31, 2012, 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 is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB- for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of March 31, 2012. 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 March 31, 2012, September 30, 2011 and March 31, 2011:

	March 31, 2012				September 30, 2011				March 31, 2011
	(In thousands, except percentages)
Short-term debt	$	173,996	3.7	%	$	206,396	4.4	%	$	—	—
Long-term debt		2,206,344	46.5	%		2,208,551	47.3	%		2,159,757	47.6	%
Shareholders’ equity		2,360,712	49.8	%		2,255,421	48.3	%		2,373,979	52.4	%
Total	$	4,741,052	100.0	%	$	4,670,368	100.0	%	$	4,533,736	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 50.2 percent at March 31, 2012, 51.7 percent at September 30, 2011 and 47.6 percent at March 31, 2011. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 9 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the six months ended March 31, 2012.

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.

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

The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and six months ended March 31, 2012 and 2011:

	Three Months Ended March 31						Six Months Ended March 31
	2012			2011			2012			2011
	(In thousands)
Fair value of contracts at beginning of period	$	(85,829	)	$	26,806		$	(79,277	)	$	(49,600	)
Contracts realized/settled		(13,807	)		(18,064	)		(31,537	)		(51,045	)
Fair value of new contracts		176			540			(377	)		1,071
Other changes in value		51,928			21,251			63,659			130,107
Fair value of contracts at end of period	$	(47,532	)	$	30,533		$	(47,532	)	$	30,533

The fair value of our natural gas distribution segment’s financial instruments at March 31, 2012 is presented below by time period and fair value source:

	Fair Value of Contracts at March 31, 2012
	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	$	(47,531	)	$	(1	)	$	—	$	—	$	(47,532	)
Prices based on models and other valuation methods		—			—			—		—		—
Total Fair Value	$	(47,531	)	$	(1	)	$	—	$	—	$	(47,532	)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and six months ended March 31, 2012 and 2011:

	Three Months Ended March 31						Six Months Ended March 31
	2012			2011			2012			2011
	(In thousands)
Fair value of contracts at beginning of period	$	(15,263	)	$	(10,681	)	$	(25,050	)	$	(12,374	)
Contracts realized/settled		13,779			(1,009	)		31,228			(75	)
Fair value of new contracts		—			—			—			—
Other changes in value		(1,090	)		(1,252	)		(8,752	)		(493	)
Fair value of contracts at end of period		(2,574	)		(12,942	)		(2,574	)		(12,942	)
Netting of cash collateral		5,696			17,053			5,696			17,053
Cash collateral and fair value of contracts at period end	$	3,122		$	4,111		$	3,122		$	4,111

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The fair value of our nonregulated segment’s financial instruments at March 31, 2012 is presented below by time period and fair value source:

	Fair Value of Contracts at March 31, 2012
	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	$	(8,115	)	$	5,563	$	(22	)	$	—	$	(2,574	)
Prices based on models and other valuation methods		—			—		—			—		—
Total Fair Value	$	(8,115	)	$	5,563	$	(22	)	$	—	$	(2,574	)

Pension and Postretirement Benefits Obligations

For the six months ended March 31, 2012 and 2011, our total net periodic pension and other benefits costs were $34.6 million and $28.8 million. A substantial portion of those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 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 six months ended March 31, 2012 were higher than the prior-year period.

The amounts we fund our defined benefit plans with are determined in accordance with the PPA and are influenced by the discount rate and funded position of the plans when the funding requirements are determined on January 1 of each year. We completed our valuation for fiscal 2012 during the second fiscal quarter and as a result of lower asset returns and a year-over-year 92 basis point decline in the discount rate used to value our qualified pension liabilities, we were required to contribute $23.0 million to the plans. During the six months ended March 31, 2012, we contributed $34.2 million to our defined benefit plans and we anticipate contributing an additional $12.4 million during the remainder of the fiscal year. Additionally, we contributed $9.1 million to our postretirement medical plans during the six months ended March 31, 2012 and anticipate contributing between $10 million and $15 million to these plans during the remainder of the fiscal year. We believe our cash flows from operations are sufficient to fund these contributions.

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

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OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage and nonregulated segments for the three and six month periods ended March 31, 2012 and 2011.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
METERS IN SERVICE, end of period
Residential		2,862,546		2,856,181		2,862,546		2,856,181
Commercial		261,449		260,010		261,449		260,010
Industrial		2,281		2,323		2,281		2,323
Public authority and other		10,245		10,194		10,245		10,194
Total meters		3,136,521		3,128,708		3,136,521		3,128,708
INVENTORY STORAGE BALANCE — Bcf		33.2		28.2		33.2		28.2
SALES VOLUMES — MMcf (2)
Gas sales volumes
Residential		63,362		82,920		113,602		133,076
Commercial		31,667		39,456		58,271		65,485
Industrial		4,697		6,046		10,109		11,192
Public authority and other		3,443		4,095		6,077		6,901
Total gas sales volumes		103,169		132,517		188,059		216,654
Transportation volumes		38,069		38,571		72,036		71,788
Total throughput		141,238		171,088		260,095		288,442
OPERATING REVENUES (000’s)(2)
Gas sales revenues
Residential	$	589,108	$	702,858	$	1,026,617	$	1,146,497
Commercial		229,204		285,680		418,892		474,945
Industrial		25,148		34,427		51,855		63,116
Public authority and other		21,749		27,546		39,243		46,083
Total gas sales revenues		865,209		1,050,511		1,536,607		1,730,641
Transportation revenues		15,867		17,727		30,729		33,418
Other gas revenues		7,932		9,176		14,964		16,817
Total operating revenues	$	889,008	$	1,077,414	$	1,582,300	$	1,780,876
Average transportation revenue per Mcf(1)	$	0.42	$	0.46	$	0.43	$	0.47
Average cost of gas per Mcf sold(1)	$	4.94	$	5.28	$	4.87	$	5.14

See footnote following these tables.

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Natural Gas Distribution Sales and Statistical Data — Discontinued Operations

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
Meters in service, end of period		83,524		84,323		83,524		84,323
Inventory storage balance — Bcf		2.2		1.9		2.2		1.9
Sales volumes — MMcf
Total gas sales volumes		3,094		4,321		5,523		6,974
Transportation volumes		1,754		2,085		3,351		3,621
Total throughput		4,848		6,406		8,874		10,595
Operating revenues (000’s)	$	26,374	$	35,790	$	49,825	$	59,523

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
CUSTOMERS, end of period
Industrial		781		753		781		753
Municipal		139		62		139		62
Other		444		513		444		513
Total		1,364		1,328		1,364		1,328
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf		49.0		23.3		49.0		23.3
REGULATED TRANSMISSION AND
STORAGE VOLUMES — MMcf(2)		176,361		174,471		337,190		327,649
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf(2)		111,656		127,377		218,118		235,089
OPERATING REVENUES (000’s)(2)
Regulated transmission and storage	$	58,037	$	54,976	$	114,796	$	103,983
Nonregulated		370,763		583,531		814,939		1,059,171
Total operating revenues	$	428,800	$	638,507	$	929,735	$	1,163,154

Notes 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 six months ended March 31, 2012, there were no material changes in our quantitative and qualitative disclosures about market risk.

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Item 4. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2012 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 second 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 six months ended March 31, 2012, 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. We did not repurchase any shares during the second quarter of fiscal 2012. At March 31, 2012, there were 4,612,009 shares of repurchase authority remaining under the program.

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: May 3, 2012

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EXHIBITS INDEX

Item 6

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

* These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report 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-12

Exhibit 12

Atmos Energy Corporation

Computation of Earnings to Fixed Charges

March 31, 2012

	Three Months Ended March 31				Six Months Ended March 31
	2012		2011		2012		2011
	(Dollars in thousands)
Income from continuing operations before provision for income taxes per statement of income	$	172,318	$	199,526	$	279,408	$	315,194
Add:
Portion of rents representative of the interest factor		1,759		1,833		3,555		3,666
Interest on debt & amortization of debt expense		36,660		37,875		72,102		76,770
Income as adjusted	$	210,737	$	239,234	$	355,065	$	395,630
Fixed charges:
Interest on debt & amortization of debt expense(1)	$	36,660	$	37,875	$	72,102	$	76,770
Capitalized interest(2)		690		231		1,521		754
Rents		5,276		5,500		10,664		10,998
Portion of rents representative of the interest factor(3)		1,759		1,833		3,555		3,666
Fixed charges(1)+(2)+(3)	$	39,109	$	39,939	$	77,178	$	81,190
Ratio of earnings to fixed charges		5.39		5.99		4.60		4.87

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 May 3, 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 March 31, 2012.

/s/ ERNST & YOUNG LLP

Dallas, Texas

May 3, 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: May 3, 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: May 3, 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 second 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.

May 3, 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 second 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.

May 3, 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

Debt (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Sep. 30, 2011
Long Term Debt Other Disclosures [Abstract]
Authorized Commercial Paper	$ 750,000,000
Commercial Paper	174,000,000	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	52.00%
Nonregulated Operations Line of Credit Facilities, Covenant Terms	Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. 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.
AEM Net Working Capital	105,900,000
AEM Tangible Net Worth	142,500,000
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 March 31, 2012.
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
Debt Instrument [Line Items]
Debt Instrument Carrying Amount	2,210,196,000	2,212,565,000
Debt Instrument Unamortized Discount	(3,852,000)	(4,014,000)
Current maturities of long-term debt	250,131,000	2,434,000
Total long-term debt	1,956,213,000	2,206,117,000
Line Of Credit Facility [Line Items]
Line of Credit Facility, Current Available Borrowing Capacity	4,200,000
Line Of Credit Facility Description	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. 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.
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	500,000,000
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, Current Available Borrowing Capacity	82,000,000
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	500,000,000
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	$ 196,000	$ 262,000
Debt Instrument Maturity Date	Jul. 01, 2013

XML

Interim Pension and Other Postretirement Benefits (Table)

6 Months Ended

Mar. 31, 2012

Disclosure Interim Pension and Other Postretirement Benefit Plans

Components of net periodic pension cost table

			Three Months Ended March 31
			Pension Benefits				Other Benefits
			2012		2011		2012		2011
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	4,298	$	4,257	$	4,088	$	3,601
	Interest cost			6,678		7,055		3,466		3,203
	Expected return on assets			(5,369)		(6,285)		(652)		(682)
	Amortization of transition asset			-		-		378		378
	Amortization of prior service cost			(36)		(105)		(363)		(363)
	Amortization of actuarial loss			4,143		2,748		662		86
	Curtailment gain			-		(40)		-		-
		Net periodic pension cost	$	9,714	$	7,630	$	7,579	$	6,223
			Six Months Ended March 31
			Pension Benefits				Other Benefits
			2012		2011		2012		2011
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	8,596	$	8,637	$	8,176	$	7,202
	Interest cost			13,355		13,979		6,931		6,406
	Expected return on assets			(10,737)		(12,248)		(1,304)		(1,364)
	Amortization of transition asset			-		-		756		756
	Amortization of prior service cost			(71)		(217)		(725)		(725)
	Amortization of actuarial loss			8,285		6,242		1,324		173
	Curtailment gain			-		(40)		-		-
		Net periodic pension cost	$	19,428	$	16,353	$	15,158	$	12,448

Schedule of assumptions used table text block

	Pension				Other
	Account Plan				Pension Benefits				Other Benefits
	2012		2011		2012		2011		2012		2011
Discount rate	5.05	%	5.68	%	5.05	%	5.39	%	5.05	%	5.39	%
Rate of compensation increase	3.50	%	4.00	%	3.50	%	4.00	%	N/A		N/A
Expected return on plan assets	7.75	%	8.25	%	7.75	%	8.25	%	4.70	%	5.00	%

XML

Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2011	Sep. 30, 2010
Segment Reporting Information Profit Loss [Abstract]
Operating revenues	$ 1,243,450	$ 1,581,497	$ 2,344,623	$ 2,714,759
Purchased gas cost	809,189	1,127,829	1,547,480	1,896,367
Gross profit	434,261	453,668	797,143	818,392
Operating expenses
Operation and maintenance	110,708	114,162	226,770	228,652
Depreciation and amortization	60,272	55,467	119,487	110,244
Taxes, other than income	54,919	53,558	98,117	93,726
Asset impairments	0	19,282	0	19,282
Total operating expenses	225,899	242,469	444,374	451,904
Operating income	208,362	211,199	352,769	366,488
Miscellaneous income (expense)	616	26,202	(1,259)	25,476
Interest charges	36,660	37,875	72,102	76,770
Income (loss) before income taxes	172,318	199,526	279,408	315,194
Income tax expense (benefit)	66,408	71,366	107,710	115,934
Income (loss) from continuing operations	105,910	128,160	171,698	199,260
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	3,201	4,049	5,920	6,946
Net income (loss)	109,111	132,209	177,618	206,206
Capital expenditures	156,729	123,501	311,123	246,663
ASSETS
Net property, plant and equipment	5,334,012		5,334,012		5,147,918
Current assets
Cash and cash equivalents	47,040	153,246	47,040	153,246	131,419	131,952
Total current assets	893,841		893,841		1,010,953
Total Assets	7,368,727		7,368,727		7,282,871
CAPITALIZATION AND LIABILITIES
Shareholders' equity	2,360,712		2,360,712		2,255,421
Long-term debt	1,956,213		1,956,213		2,206,117
Total capitalization	4,316,925		4,316,925		4,461,538
Current liabilities
Current maturities of long-term debt	250,131		250,131		2,434
Short-term debt	173,996		173,996		206,396
Total current liabilities	1,108,114		1,108,114		867,598
Deferred income taxes	1,062,488		1,062,488		960,093
Total Equity and Liabilities	7,368,727		7,368,727		7,282,871
Natural Gas Distribution Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	888,685	1,077,178	1,581,753	1,780,439
Intersegment revenues	323	236	547	437
Operating revenues	889,008	1,077,414	1,582,300	1,780,876
Purchased gas cost	508,206	698,410	910,413	1,110,936
Gross profit	380,802	379,004	671,887	669,940
Operating expenses
Operation and maintenance	89,443	92,266	182,857	181,495
Depreciation and amortization	51,755	48,555	102,586	96,449
Taxes, other than income	50,313	50,088	88,792	84,536
Asset impairments	0	0	0	0
Total operating expenses	191,511	190,909	374,235	362,480
Operating income	189,291	188,095	297,652	307,460
Miscellaneous income (expense)	733	20,156	(1,023)	19,458
Interest charges	28,833	29,605	56,688	59,302
Income (loss) before income taxes	161,191	178,646	239,941	267,616
Income tax expense (benefit)	62,890	64,085	93,735	98,634
Income (loss) from continuing operations	98,301	114,561	146,206	168,982
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	3,201	4,049	5,920	6,946
Net income (loss)	101,502	118,610	152,126	175,928
Capital expenditures	114,402	109,762	243,135	219,261
ASSETS
Net property, plant and equipment	4,382,291		4,382,291		4,248,198
Investment in subsidaries	674,594		674,594		670,993
Current assets
Cash and cash equivalents	40,140		40,140		24,646
Assets from risk management activities	502		502		843
Other current assets	632,486		632,486		655,716
Intercompany receivables	584,018		584,018		569,898
Total current assets	1,257,146		1,257,146		1,251,103
Intangible assets	0		0		0
Goodwill	572,908		572,908		572,908
Noncurrent assets from risk management activities	0		0		998
Deferred charges and other assets	366,329		366,329		353,960
Total Assets	7,253,268		7,253,268		7,098,160
CAPITALIZATION AND LIABILITIES
Shareholders' equity	2,360,712		2,360,712		2,255,421
Long-term debt	1,956,147		1,956,147		2,205,986
Total capitalization	4,316,859		4,316,859		4,461,407
Current liabilities
Current maturities of long-term debt	250,000		250,000		2,303
Short-term debt	371,996		371,996		387,691
Liabilities from risk management activities	47,281		47,281		11,916
Other current liabilities	507,354		507,354		474,783
Intercompany payables	0		0		0
Total current liabilities	1,176,631		1,176,631		876,693
Deferred income taxes	890,455		890,455		789,649
Noncurrent liabilities from risk management activities	1		1		67,862
Regulatory cost of removal obligation	414,001		414,001		428,947
Deferred credits and other liabilities	455,321		455,321		473,602
Total Equity and Liabilities	7,253,268		7,253,268		7,098,160
Regulated Transmission and Storage Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	20,430	21,597	39,870	42,830
Intersegment revenues	37,607	33,379	74,926	61,153
Operating revenues	58,037	54,976	114,796	103,983
Purchased gas cost	0	0	0	0
Gross profit	58,037	54,976	114,796	103,983
Operating expenses
Operation and maintenance	15,847	15,231	32,812	30,805
Depreciation and amortization	7,792	5,798	15,443	11,597
Taxes, other than income	3,915	4,113	7,699	7,666
Asset impairments	0	0	0	0
Total operating expenses	27,554	25,142	55,954	50,068
Operating income	30,483	29,834	58,842	53,915
Miscellaneous income (expense)	(56)	5,861	(336)	5,579
Interest charges	7,614	8,085	14,823	16,149
Income (loss) before income taxes	22,813	27,610	43,683	43,345
Income tax expense (benefit)	8,193	9,871	15,649	15,504
Income (loss) from continuing operations	14,620	17,739	28,034	27,841
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	14,620	17,739	28,034	27,841
Capital expenditures	38,871	11,818	62,991	24,557
ASSETS
Net property, plant and equipment	886,507		886,507		838,302
Investment in subsidaries	0		0		0
Current assets
Cash and cash equivalents	0		0		0
Assets from risk management activities	0		0		0
Other current assets	13,278		13,278		15,413
Intercompany receivables	0		0		0
Total current assets	13,278		13,278		15,413
Intangible assets	0		0		0
Goodwill	132,381		132,381		132,381
Noncurrent assets from risk management activities	0		0		0
Deferred charges and other assets	13,203		13,203		18,028
Total Assets	1,045,369		1,045,369		1,004,124
CAPITALIZATION AND LIABILITIES
Shareholders' equity	293,135		293,135		265,102
Long-term debt	0		0		0
Total capitalization	293,135		293,135		265,102
Current liabilities
Current maturities of long-term debt	0		0		0
Short-term debt	0		0		0
Liabilities from risk management activities	0		0		0
Other current liabilities	6,309		6,309		10,369
Intercompany payables	551,330		551,330		543,084
Total current liabilities	557,639		557,639		553,453
Deferred income taxes	188,936		188,936		173,351
Noncurrent liabilities from risk management activities	0		0		0
Regulatory cost of removal obligation	0		0		0
Deferred credits and other liabilities	5,659		5,659		12,218
Total Equity and Liabilities	1,045,369		1,045,369		1,004,124
Nonregulated Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	334,335	482,722	723,000	891,490
Intersegment revenues	36,428	100,809	91,939	167,681
Operating revenues	370,763	583,531	814,939	1,059,171
Purchased gas cost	374,992	563,473	803,763	1,013,935
Gross profit	(4,229)	20,058	11,176	45,236
Operating expenses
Operation and maintenance	5,769	7,035	11,820	17,119
Depreciation and amortization	725	1,114	1,458	2,198
Taxes, other than income	691	(643)	1,626	1,524
Asset impairments	0	19,282	0	19,282
Total operating expenses	7,185	26,788	14,904	40,123
Operating income	(11,414)	(6,730)	(3,728)	5,113
Miscellaneous income (expense)	567	306	603	596
Interest charges	839	306	1,091	1,476
Income (loss) before income taxes	(11,686)	(6,730)	(4,216)	4,233
Income tax expense (benefit)	(4,675)	(2,590)	(1,674)	1,796
Income (loss) from continuing operations	(7,011)	(4,140)	(2,542)	2,437
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	(7,011)	(4,140)	(2,542)	2,437
Capital expenditures	3,456	1,921	4,997	2,845
ASSETS
Net property, plant and equipment	65,214		65,214		61,418
Investment in subsidaries	(2,096)		(2,096)		(2,096)
Current assets
Cash and cash equivalents	6,900		6,900		106,773
Assets from risk management activities	2,877		2,877		17,501
Other current assets	399,389		399,389		386,215
Intercompany receivables	0		0		0
Total current assets	409,166		409,166		510,489
Intangible assets	185		185		207
Goodwill	34,711		34,711		34,711
Noncurrent assets from risk management activities	10,841		10,841		0
Deferred charges and other assets	10,316		10,316		10,807
Total Assets	528,337		528,337		615,536
CAPITALIZATION AND LIABILITIES
Shareholders' equity	381,459		381,459		405,891
Long-term debt	66		66		131
Total capitalization	381,525		381,525		406,022
Current liabilities
Current maturities of long-term debt	131		131		131
Short-term debt	0		0		0
Liabilities from risk management activities	5,296		5,296		3,537
Other current liabilities	119,382		119,382		170,926
Intercompany payables	32,688		32,688		26,814
Total current liabilities	157,497		157,497		201,408
Deferred income taxes	(16,903)		(16,903)		(2,907)
Noncurrent liabilities from risk management activities	5,300		5,300		10,227
Regulatory cost of removal obligation	0		0		0
Deferred credits and other liabilities	918		918		786
Total Equity and Liabilities	528,337		528,337		615,536
Intersegment Elimination [Member]
Segment Reporting Information Profit Loss [Abstract]
Revenues from external customers	0	0	0	0
Intersegment revenues	(74,358)	(134,424)	(167,412)	(229,271)
Operating revenues	(74,358)	(134,424)	(167,412)	(229,271)
Purchased gas cost	(74,009)	(134,054)	(166,696)	(228,504)
Gross profit	(349)	(370)	(716)	(767)
Operating expenses
Operation and maintenance	(351)	(370)	(719)	(767)
Depreciation and amortization	0	0	0	0
Taxes, other than income	0	0	0	0
Asset impairments	0	0	0	0
Total operating expenses	(351)	(370)	(719)	(767)
Operating income	2	0	3	0
Miscellaneous income (expense)	(628)	(121)	(503)	(157)
Interest charges	(626)	(121)	(500)	(157)
Income (loss) before income taxes	0	0	0	0
Income tax expense (benefit)	0	0	0	0
Income (loss) from continuing operations	0	0	0	0
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	0	0	0	0
ASSETS
Net property, plant and equipment	0		0		0
Investment in subsidaries	(672,498)		(672,498)		(668,897)
Current assets
Cash and cash equivalents	0		0		0
Assets from risk management activities	0		0		0
Other current assets	(201,731)		(201,731)		(196,154)
Intercompany receivables	(584,018)		(584,018)		(569,898)
Total current assets	(785,749)		(785,749)		(766,052)
Intangible assets	0		0		0
Goodwill	0		0		0
Noncurrent assets from risk management activities	0		0		0
Deferred charges and other assets	0		0		0
Total Assets	(1,458,247)		(1,458,247)		(1,434,949)
CAPITALIZATION AND LIABILITIES
Shareholders' equity	(674,594)		(674,594)		(670,993)
Long-term debt	0		0		0
Total capitalization	(674,594)		(674,594)		(670,993)
Current liabilities
Current maturities of long-term debt	0		0		0
Short-term debt	(198,000)		(198,000)		(181,295)
Liabilities from risk management activities	0		0		0
Other current liabilities	(1,635)		(1,635)		(12,763)
Intercompany payables	(584,018)		(584,018)		(569,898)
Total current liabilities	(783,653)		(783,653)		(763,956)
Deferred income taxes	0		0		0
Noncurrent liabilities from risk management activities	0		0		0
Regulatory cost of removal obligation	0		0		0
Deferred credits and other liabilities	0		0		0
Total Equity and Liabilities	$ (1,458,247)		$ (1,458,247)		$ (1,434,949)

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3. Financial Instruments

6 Months Ended

Mar. 31, 2012

Financial Instruments [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 six months ended March 31, 2012 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 hedged 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 cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.

Nonregulated Commodity Risk Management Activities

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 56 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.

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

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 March 31, 2012, we had three Treasury lock agreements outstanding to fix the Treasury yield component of 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 March 31, 2012, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2012, 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	-	(38,340)
	Cash Flow	-	49,098
	Not designated	6,033	28,190
		6,033	38,948

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of March 31, 2012 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 $5.7 million and $28.8 million of cash held on deposit in margin accounts as of March 31, 2012 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
March 31, 2012						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	77,441	$	77,441
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		-		-
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			(45,818)		(59,301)		(105,119)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		-		(10,914)		(10,914)
	Total						(45,818)		7,226		(38,592)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			502		137,934		138,436
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		85,951		85,951
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(2,215)		(164,189)		(166,404)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(1)		(69,496)		(69,497)
	Total						(1,714)		(9,800)		(11,514)
Total Financial Instruments						$	(47,532)	$	(2,574)	$	(50,106)

(1) Other current liabilities not designated as hedges in our natural gas distribution segment include $0.8 million related to risk management liabilities that were classified as assets held for sale at March 31, 2012.

						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 $1.3million 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 March 31, 2012 and 2011 we recognized a gain (loss)arising from fair value and cash flow hedge ineffectiveness of $ (6.2) million and $ 4.1 million. For the six months ended March 31, 2012 and 2011 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $ 2.2 million and $ 17.5 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and six months ended March 31, 2012 and 2011 is presented below.

		Three Months Ended March 31
		2012		2011
		(In thousands)
Commodity contracts		$	29,090	$	(1,279)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(35,087)		5,586
Total impact on revenue		$	(5,997)	$	4,307
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	(739)	$	(509)
	Timing ineffectiveness		(5,258)		4,816
		$	(5,997)	$	4,307
		Six Months Ended March 31
		2012		2011
			(In thousands)
Commodity contracts		$	53,153	$	(3,003)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(50,335)		21,211
Total impact on revenue		$	2,818	$	18,208
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	102	$	412
	Timing ineffectiveness		2,716		17,796
		$	2,818	$	18,208

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 six months ended March 31, 2012, 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 six months ended March 31, 2011.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

		Three Months Ended March 31, 2012
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(21,181)	$	(21,181)
Loss arising from ineffective portion of
	commodity contracts		-		-		(238)		(238)
Total impact on revenue			-		-		(21,419)		(21,419)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(502)		-		-		(502)
Total Impact from Cash Flow Hedges		$	(502)	$	-	$	(21,419)	$	(21,921)
		Three Months Ended March 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(7,328)	$	(7,328)
Loss arising from ineffective portion of
	commodity contracts		-		-		(233)		(233)
Total impact on revenue			-		-		(7,561)		(7,561)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(669)		-		-		(669)
Gain on unwinding of Treasury lock reclassified
	from AOCI into miscellaneous income		21,803		6,000		-		27,803
Total Impact from Cash Flow Hedges		$	21,134	$	6,000	$	(7,561)	$	19,573
		Six Months Ended March 31, 2012
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(32,823)	$	(32,823)
Loss arising from ineffective portion of
	commodity contracts		-		-		(668)		(668)
Total impact on revenue			-		-		(33,491)		(33,491)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(1,004)		-		-		(1,004)
Total Impact from Cash Flow Hedges		$	(1,004)	$	-	$	(33,491)	$	(34,495)
		Six Months Ended March 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(21,581)	$	(21,581)
Loss arising from ineffective portion of
	commodity contracts		-		-		(677)		(677)
Total impact on revenue			-		-		(22,258)		(22,258)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(1,339)		-		-		(1,339)
Gain on unwinding of Treasury lock reclassified
	from AOCI into miscellaneous income		21,803		6,000		-		27,803
Total Impact from Cash Flow Hedges		$	20,464	$	6,000	$	(22,258)	$	4,206

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended March 31, 2012 and 2011.The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.

		Three Months Ended				Six Months Ended
		March 31				March 31
		2012		2011		2012		2011
		(In thousands)
Increase (decrease) in fair value:
	Treasury lock agreements	$	15,079	$	6,667	$	13,676	$	38,092
	Forward commodity contracts		(18,234)		(446)		(41,912)		1,211
Recognition of (gains) losses in earnings due to
	settlements:
	Treasury lock agreements		317		(17,094)		633		(16,672)
	Forward commodity contracts		12,919		4,471		20,022		13,164
Total other comprehensive income (loss) from
	hedging, net of tax(1)	$	10,081	$	(6,402)	$	(7,581)	$	35,795

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

Deferred gains (losses) recorded in 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 March 31, 2012. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock agreements as these instruments have not yet settled.

	Treasury
	Lock		Commodity
	Agreements		Contracts		Total
	(In thousands)
Next twelve months	$	(1,266)	$	(32,130)	$	(33,396)
Thereafter		10,284		(6,621)		3,663
Total(1)	$	9,018	$	(38,751)	$	(29,733)

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

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended March 31, 2012 and 2011 was an increase (decrease) in revenue of $(12.8) million and $4.0 million. For the six months ended March 31, 2012 and 2011 revenue increased (decreased) $(15.0) million and $8.2 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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Financial Instruments (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2011
Natural Gas Inventory [Abstract]
Inventory write-down to lower of cost or market			$ 1,700,000
Minimum Length Of Time Hedged In Cash Flow Hedge	one
Maximum Length Of Time Hedged In Cash Flow Hedge	56
Gain Loss On Hedge Ineffectiveness	(6,200,000)	4,100,000	2,200,000	17,500,000
Gain Loss On Derivative Instruments Not Designated Hedges Net Pretax	(12,800,000)	4,000,000	(15,000,000)	8,200,000
Disposal Group, Including Discontinued Operation, Derivative Liabilities, Current	800,000		800,000		1,300,000
Effect of Fair Value Hedges on Results of Operations [Abstract]
Commodity contracts	(29,090,000)	1,279,000	(53,153,000)	3,003,000
Fair value adjustment for natural gas inventory designated as the hedged item	35,087,000	(5,586,000)	50,335,000	(21,211,000)
Total impact on revenue	(5,997,000)	4,307,000	2,818,000	18,208,000
Basis ineffectiveness	(739,000)	(509,000)	102,000	412,000
Timing ineffectiveness	(5,258,000)	4,816,000	2,716,000	17,796,000
Other Comprehensive Income [Abstract]
Treasury lock agreements fair value	15,079,000	6,667,000	13,676,000	38,092,000
Forward commodity contracts fair value	(18,234,000)	(446,000)	(41,912,000)	1,211,000
Treasury lock agreements	317,000	(17,094,000)	633,000	(16,672,000)
Forward commodity contracts	12,919,000	4,471,000	20,022,000	13,164,000
Total other comprehensive income (loss) from hedging, net of tax	10,081,000	(6,402,000)	(7,581,000)	35,795,000
Expected Earnings [Line Items]
Treasury Lock Gain Loss Reclassified To Earnings			9,018,000
Commodity Contract Gain Loss Reclassified To Earnings			(38,751,000)
Total Hedge Gain Loss Reclassified To Earnings			(29,733,000)
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			(32,130,000)
Total Hedge Gain Loss Reclassified To Earnings			(33,396,000)
Thereafter [Member]
Expected Earnings [Line Items]
Treasury Lock Gain Loss Reclassified To Earnings			10,284,000
Commodity Contract Gain Loss Reclassified To Earnings			(6,621,000)
Total Hedge Gain Loss Reclassified To Earnings			3,663,000
Natural Gas Distribution Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Fair Value	0		0
Cash Flow	0		0
Not designated	6,033		6,033
Total Commodity Contracts Outstanding	6,033		6,033
Derivatives Fair Value [Line Items]
Derivative Assets Current	502,000		502,000		843,000
Derivative Assets Noncurrent	0		0		998,000
Derivative Liabilities Current	47,281,000		47,281,000		11,916,000
Derivative Liabilities Noncurrent	1,000		1,000		67,862,000
Total Financial Instruments	(47,532,000)		(47,532,000)		(79,277,000)
Cash Flow Hedge [Line Items]
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	0	0	0	0
Loss arising from ineffective portion of commodity contracts	0	0	0	0
Total impact on revenue	0	0	0	0
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	502,000	669,000	1,004,000	1,339,000
Gain On Unwinding Of Treasury Lock Reclassified From Accumulated Oci To Miscellaneous Income		21,803,000		21,803,000
Total Impact from Cash Flow Hedges	(502,000)	21,134,000	(1,004,000)	20,464,000
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Liabilities At Fair Value Net	(45,818,000)		(45,818,000)		(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		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		0
Natural Gas Distribution Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(45,818,000)		(45,818,000)		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	0		0		(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	(1,714,000)		(1,714,000)		(11,750,000)
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	502,000		502,000		843,000
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	0		0		998,000
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(2,215,000)		(2,215,000)		(13,256,000)
Natural Gas Distribution Segment [Member] | Nondesignated [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(1,000)		(1,000)		(335,000)
Nonregulated Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Fair Value	(38,340)		(38,340)
Cash Flow	49,098		49,098
Not designated	28,190		28,190
Total Commodity Contracts Outstanding	38,948		38,948
Derivatives Fair Value [Line Items]
Derivative Assets Current	2,877,000		2,877,000		17,501,000
Derivative Assets Noncurrent	10,841,000		10,841,000		0
Derivative Liabilities Current	5,296,000		5,296,000		3,537,000
Derivative Liabilities Noncurrent	5,300,000		5,300,000		10,227,000
Total Financial Instruments	(2,574,000)		(2,574,000)		(25,050,000)
Cash Flow Hedge [Line Items]
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	21,181,000	7,328,000	32,823,000	21,581,000
Loss arising from ineffective portion of commodity contracts	238,000	233,000	668,000	677,000
Total impact on revenue	(21,419,000)	(7,561,000)	(33,491,000)	(22,258,000)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	0	0	0	0
Gain On Unwinding Of Treasury Lock Reclassified From Accumulated Oci To Miscellaneous Income		0		0
Total Impact from Cash Flow Hedges	(21,419,000)	(7,561,000)	(33,491,000)	(22,258,000)
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Liabilities At Fair Value Net	7,226,000		7,226,000		(16,203,000)
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	77,441,000		77,441,000		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	0		0		174,000
Nonregulated Segment [Member] | Designated As Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(59,301,000)		(59,301,000)		(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	(10,914,000)		(10,914,000)		(7,709,000)
Nonregulated Segment [Member] | Nondesignated [Member]
Derivatives Fair Value [Line Items]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net	(9,800,000)		(9,800,000)		(8,847,000)
Nonregulated Segment [Member] | Nondesignated [Member] | Other Current Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	137,934,000		137,934,000		67,710,000
Nonregulated Segment [Member] | Nondesignated [Member] | Deferred Charges And Other Assets [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Noncurrent	85,951,000		85,951,000		22,379,000
Nonregulated Segment [Member] | Nondesignated [Member] | Other Current Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Current	(164,189,000)		(164,189,000)		(73,865,000)
Nonregulated Segment [Member] | Nondesignated [Member] | Deferred Credits And Other Liabilities [Member]
Derivatives Fair Value [Line Items]
Derivative Liabilities Noncurrent	(69,496,000)		(69,496,000)		(25,071,000)
Regulated Transmission and Storage Segment [Member]
Derivatives Fair Value [Line Items]
Derivative Assets Current	0		0		0
Derivative Assets Noncurrent	0		0		0
Derivative Liabilities Current	0		0		0
Derivative Liabilities Noncurrent	0		0		0
Cash Flow Hedge [Line Items]
Loss reclassified from AOCI into revenue for effective portion of commodity contracts	0	0	0	0
Loss arising from ineffective portion of commodity contracts	0	0	0	0
Total impact on revenue	0	0	0	0
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	0	0	0	0
Gain On Unwinding Of Treasury Lock Reclassified From Accumulated Oci To Miscellaneous Income		6,000,000		6,000,000
Total Impact from Cash Flow Hedges	$ 0	$ 6,000,000	$ 0	$ 6,000,000

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Unaudited Interim Financial Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2011
Regulatory Asset [Line Items]
Regulatory Assets	$ 294,688		$ 294,688		$ 312,896
Regulatory Liabilities [Line Items]
Regulatory Liabilities	492,062		492,062		486,180
Regulatory Asset - Replacement/renewal of distribution facilities			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 March 31, 2012, we had deferred $0.7 million associated with the requirements of this rule which are recorded in “Other” in the regulatory assets table above.
Statement Of Income And Comprehensive Income Abstract
Net income (loss)	109,111	132,209	177,618	206,206
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Net Of Tax	2,046	810	2,947	1,586
Other Comprehensive Income Reclassification Adjustment And Unrealized Gain Loss On Derivatives Included In Net Income And Arising During Period Net Of Tax	15,396	(10,427)	14,309	21,420
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax	(5,315)	4,025	(21,890)	14,375
Comprehensive Income Net Of Tax	121,238	126,617	172,984	243,587
Other Comprehensive Income Loss Tax Portion Attributable To Parent Abstract
Other Comprehensive Income Unrealized Holding Gain Loss On Securities Arising During Period Tax	1,203	477	1,717	932
Other Comprehensive Income Reclassification Adjustment And Unrealized Gain Loss On Derivatives Included In Net Income And Arising During Period Tax	9,042	(6,125)	8,404	12,579
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Tax	(3,399)	2,573	(13,996)	9,190
Accumulated Other Comprehensive Income Loss Net Of Tax Abstract
Accumulated Other Comprehensive Income Loss Available For Sale Securities Adjustment Net Of Tax	5,505		5,505		2,558
Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Interest Rate Hedges Effect Net Of Tax	(19,848)		(19,848)		(34,157)
Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(38,751)		(38,751)		(16,861)
Accumulated other comprehensive income (loss)	(53,094)		(53,094)		(48,460)
Deferred Gas Costs Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	15,232		15,232		8,130
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	463,740		463,740		464,025
Miscellaneous Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	13,090		13,090		14,025
Pension And Postretirement Benefit Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	245,096		245,096		254,666
Merger And Integration Costs Net [Member]
Regulatory Asset [Line Items]
Regulatory Assets	5,998		5,998		6,242
Deferred Gas Costs Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets	19,547		19,547		33,976
Regulatory Cost of Removal Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets	10,233		10,233		8,852
Environmental Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	117		117		385
Rate Case Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	4,503		4,503		4,862
Deferred Franchise Fees [Member]
Regulatory Asset [Line Items]
Regulatory Assets	333		333		379
Deferred Miscellaneous Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets	$ 8,861		$ 8,861		$ 3,534

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Fair Value Measurements (Details) (USD $)	Mar. 31, 2012	Sep. 30, 2011
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value	$ 65,419,000	$ 52,633,000
Fair Value [Abstract]
Cash Collateral Right To Reclaim Cash	5,700,000	28,800,000
Debt Instrument Fair Value	2,583,071,000
Cash Held In Margin Accounts Offset Current Risk Management Liabilities	2,800,000	12,400,000
Cash Held In Margin Accounts Classified Current Risk Management Asset	2,900,000	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	52,013,000	15,262,000
Total financial instruments	52,013,000	15,262,000
Hedged portion of gas stored underground	73,043,000	47,940,000
Available For Sale Securities Equity Securities	38,424,000	36,444,000
Available For Sale Securities Debt Securities	0	0
Available-for-sale securities money market funds	0	0
Fair value	38,424,000	36,444,000
Total assets	163,480,000	99,646,000
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Liabilities	76,476,000	22,091,000
Total liabilities	76,476,000	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	502,000	1,841,000
Nonregulated Segement Derivative Assets	249,313,000	97,396,000
Total financial instruments	249,815,000	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	23,637,000	14,366,000
Available-for-sale securities money market funds	3,358,000	1,823,000
Fair value	26,995,000	16,189,000
Total assets	276,810,000	115,426,000
Natural gas distribution segment	48,034,000	81,118,000
Nonregulated Segement Derivative Liabilities	227,424,000	115,617,000
Total liabilities	275,458,000	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	(287,608,000)	(95,156,000)
Total financial instruments	(287,608,000)	(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	(287,608,000)	(95,156,000)
Natural gas distribution segment	0	0
Nonregulated Segement Derivative Liabilities	(293,304,000)	(123,943,000)
Total liabilities	$ (293,304,000)	$ (123,943,000)

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Fair Value Measurements Available-For-Sale Securities (Detials) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Sep. 30, 2011
Schedule Of Available For Sale Securities [Line Items]
Available For Sale Securities Amortized Cost	$ 56,681	$ 48,558
Available-for-sale Securities Gross Unrealized Gain	8,753	4,351
Available-for-sale Securities Gross Unrealized Losses 1	15	276
Available For Sale Securities Fair Value Disclosure	65,419	52,633
Money Market Funds [Member]
Schedule Of Available For Sale Securities [Line Items]
Available For Sale Securities Amortized Cost	3,358	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	3,358	1,823
Equity Funds Domestic [Member]
Schedule Of Available For Sale Securities [Line Items]
Available For Sale Securities Amortized Cost	24,471	27,748
Available-for-sale Securities Gross Unrealized Gain	7,821	4,074
Available-for-sale Securities Gross Unrealized Losses 1	0	0
Available For Sale Securities Fair Value Disclosure	32,292	31,822
Equity Funds Foreign [Member]
Schedule Of Available For Sale Securities [Line Items]
Available For Sale Securities Amortized Cost	5,327	4,597
Available-for-sale Securities Gross Unrealized Gain	805	267
Available-for-sale Securities Gross Unrealized Losses 1	0	242
Available For Sale Securities Fair Value Disclosure	6,132	4,622
Debt Securities [Member]
Schedule Of Available For Sale Securities [Line Items]
Available For Sale Securities Amortized Cost	23,525	14,390
Available-for-sale Securities Gross Unrealized Gain	127	10
Available-for-sale Securities Gross Unrealized Losses 1	15	34
Available For Sale Securities Fair Value Disclosure	$ 23,637	$ 14,366

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2. Unaudited Financial Information

6 Months Ended

Mar. 31, 2012

Disclosure Unaudited Interim Financial Information

2. Unaudited Financial Information

2. Unaudited Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company's audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 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 six-month period ended March 31, 2012 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 March 31, 2012balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as discussed in Note 6, 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.

Due to the pending sale of our distribution operations in our Missouri, Illinois and Iowa service areas, the financial results for these service areas are shown in discontinued operations. Accordingly, certain prior-year amounts have been reclassified to conform with the current year presentation.

During the second quarter of fiscal 2012, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

During the six months ended March 31, 2012, 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 indefinitely 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 thesixmonths ended March 31, 2012.

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 ofMarch 31, 2012 and September 30, 2011 included the following:

			March 31,		September 30,
			2012		2011
			(In thousands)
Regulatory assets:
	Pension and postretirement benefit costs	$	245,096	$	254,666
	Merger and integration costs, net		5,998		6,242
	Deferred gas costs		19,547		33,976
	Regulatory cost of removal asset		10,233		8,852
	Environmental costs		117		385
	Rate case costs		4,503		4,862
	Deferred franchise fees		333		379
	Other		8,861		3,534
		$	294,688	$	312,896
Regulatory liabilities:
	Deferred gas costs	$	15,232	$	8,130
	Regulatory cost of removal obligation		463,740		464,025
	Other		13,090		14,025
		$	492,062	$	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 March 31, 2012, we had deferred $0.7 million associated with the requirements of this rule which are recorded in“Other” in the regulatory assets table above.

Effective January 1, 2012, the Texas Legislature amended its Gas Utility Regulatory Act (GURA) to permit natural gas utilities to defer into a regulatory asset or liability the difference between a gas utility's actual pension and postretirement expense and the level of such expense recoverable in its existing rates.  The deferred amount will become eligible for inclusion in the utility's rates in its next rate proceeding.  During the quarter, we elected to utilize this provision of GURA, effective January 1, 2012, and established a regulatory asset totaling $2.5 million, which is recorded in “Other” in the regulatory assets table above. Of this amount, $1.4 million represented a reduction to operation and maintenance expense during the second quarter of fiscal 2012.

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

Comprehensive income

The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and six-month periods ended March 31, 2012 and 2011:

		Three Months Ended				Six Months Ended
		March 31				March 31
		2012		2011		2012		2011
		(In thousands)
Net income		$	109,111	$	132,209	$	177,618	$	206,206
Unrealized holding gains on investments,
	net of tax expense of $1,203 and $477
	for the three months ended March 31,
	2012 and 2011 and of $1,717 and $932
	for the six months ended March 31, 2012
	and 2011		2,046		810		2,947		1,586
Amortization, unrealized gain and unwinding
	of treasury lock agreements, net of tax
	expense (benefit) of $9,042 and $(6,125)
	for the three months ended March 31, 2012
	and 2011 and $8,404 and $12,579 for the six
	month ended March 31, 2012 and 2011		15,396		(10,427)		14,309		21,420
Net unrealized gains (losses) on cash flow
	hedging transactions, net of tax expense
	(benefit) of $(3,399) and $2,573 for the three
	months ended March 31, 2012 and 2011 and
	$(13,996) and $9,190 for the six months
	ended March 31, 2012 and 2011		(5,315)		4,025		(21,890)		14,375
Comprehensive income		$	121,238	$	126,617	$	172,984	$	243,587

Accumulated other comprehensive income (loss), net of tax, as of March 31, 2012 and September 30, 2011 consisted of the following unrealized gains (losses):

		March 31,		September 30,
		2012		2011
		(In thousands)
Accumulated other comprehensive income (loss):
	Unrealized holding gains on investments	$	5,505	$	2,558
	Treasury lock agreements		(19,848)		(34,157)
	Cash flow hedges		(38,751)		(16,861)
		$	(53,094)	$	(48,460)

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Discontinued Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2011
Discontinued Operation Income Loss From Discontinued Operation Disclosures Abstract
Operating revenues	$ 26,374	$ 35,790	$ 49,825	$ 59,523
Purchased gas cost	17,026	24,636	31,977	39,533
Gross profit	9,348	11,154	17,848	19,990
Operating expenses	4,275	4,431	8,449	8,447
Operating income	5,073	6,723	9,399	11,543
Miscellaneous (expense)	38	32	86	65
Income from discontinued operations before income taxes	5,035	6,691	9,313	11,478
Income tax expense	1,834	2,642	3,393	4,532
Income (loss) from discontinued operations	3,201	4,049	5,920	6,946
Disposal Group Including Discontinued Operation Balance Sheet Disclosures Abstract
Net plant, property & equipment	126,587		126,587		127,577
Gas stored underground	6,517		6,517		11,931
Other current assets	515		515		786
Deferred charges and other assets	49		49		277
Assets held for sale	133,668		133,668		140,571
Accounts payable	5,404		5,404		1,917
Other current liabilities	6,857		6,857		4,877
Regulatory cost of removal	7,687		7,687		10,498
Deferred credits and other liabilities	872		872		1,153
Liabilities held for sale	$ 20,820		$ 20,820		$ 18,445
Other Discontinued Operations Disclosures [Abstract]
Disposal Group Sales Price			124000000

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Sep. 30, 2011
ASSETS
Property, plant and equipment	$ 6,992,899	$ 6,816,794
Less accumulated depreciation and amortization	1,658,887	1,668,876
Net property, plant and equipment	5,334,012	5,147,918
Current assets
Cash and cash equivalents	47,040	131,419
Accounts receivable, net	350,261	273,303
Gas stored underground	221,112	289,760
Other current assets	275,428	316,471
Total current assets	893,841	1,010,953
Goodwill and intangible assets	740,185	740,207
Deferred charges and other assets	400,689	383,793
Total assets	7,368,727	7,282,871
Shareholders' equity
Common stock, no par value (stated at $.005 per share)	450	451
Additional paid-in capital	1,728,150	1,732,935
Retained earnings	685,206	570,495
Accumulated other comprehensive income (loss)	(53,094)	(48,460)
Shareholders' equity	2,360,712	2,255,421
Long-term debt	1,956,213	2,206,117
Total capitalization	4,316,925	4,461,538
Current liabilities
Accounts payable and accrued liabilities	309,864	291,205
Other current liabilities	374,123	367,563
Short-term debt	173,996	206,396
Current maturities of long-term debt	250,131	2,434
Total current liabilities	1,108,114	867,598
Deferred income taxes	1,062,488	960,093
Regulatory cost of removal obligation	414,001	428,947
Deferred credits and other liabilities	467,199	564,695
Total shareholders' equity and liabilities	$ 7,368,727	$ 7,282,871

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flows From Operating Activities
Net income (loss)	$ 177,618	$ 206,206
Adjustments to reconcile net income to net cash provided by operating activities:
Asset impairments	0	19,282
Depreciation and amortization:
Charged to depreciation and amortization	122,532	113,297
Charged to other accounts	203	98
Other
Deferred income taxes	102,052	115,302
Other	9,874	10,255
Net assets / liabilities from risk management activities	15,690	(17,478)
Net change in operating assets and liabilities	(67,246)	(8,491)
Net cash provided (used) by operating activities	360,723	438,471
Cash Flows From Investing Activities
Capital expenditures	(311,123)	(246,663)
Other, net	(3,878)	(1,535)
Net cash used in investing activities	(315,001)	(248,198)
Cash Flows From Financing Activities
Net increase in short-term debt	(48,945)	(128,884)
Unwinding of Treasury lock agreements	0	27,803
Repayment of long-term debt	(2,369)	(10,066)
Cash dividends paid	(62,907)	(62,067)
Repurchase of common stock	(12,535)	0
Repurchase of equity awards	(3,509)	(3,333)
Issuance of common stock	164	7,568
Net cash provided by (used in) financing activities	(130,101)	(168,979)
Net increase (decrease) in cash and cash equivalents	(84,379)	21,294
Cash and cash equivalents at beginning of period	131,419	131,952
Cash and cash equivalents at end of period	$ 47,040	$ 153,246

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Interim Pension and Other Postretirement Benefits (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount Rate			5.05%	5.68%
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	$ 4,257,000	$ 8,596,000	$ 8,637,000
Interest Cost	6,678,000	7,055,000	13,355,000	13,979,000
Expected return on assets	5,369,000	6,285,000	10,737,000	12,248,000
Amortization of transition asset	0	0	0	0
Amortization of prior service cost	(36,000)	(105,000)	(71,000)	(217,000)
Recognized actuarial loss	(4,143,000)	(2,748,000)	(8,285,000)	(6,242,000)
Curtailment Loss	0	40,000	0	40,000
Defined Benefit Plan Net Periodic Benefit Cost	9,714,000	7,630,000	19,428,000	16,353,000
Current Year Benefit Plan Contributions [Abstract]
Contributions Actual			34,200,000
Contributions Estimate	12,400,000		12,400,000
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	8,176,000	7,202,000
Interest Cost	3,466,000	3,203,000	6,931,000	6,406,000
Expected return on assets	652,000	682,000	1,304,000	1,364,000
Amortization of transition asset	378,000	378,000	756,000	756,000
Amortization of prior service cost	(363,000)	(363,000)	(725,000)	(725,000)
Recognized actuarial loss	(662,000)	(86,000)	(1,324,000)	(173,000)
Curtailment Loss	0	0	0	0
Defined Benefit Plan Net Periodic Benefit Cost	7,579,000	6,223,000	15,158,000	12,448,000
Current Year Benefit Plan Contributions [Abstract]
Contributions Actual			9,100,000
Contributions Estimate Minimum	10,000,000		10,000,000
Contributions Estimate Maximum	$ 15,000,000		$ 15,000,000
Other 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%

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Discontinued Operations (Table)

6 Months Ended

Mar. 31, 2012

Discontinued Operations [Abstract]

Discontinued operations income statement detail table

The following table presents statement of income data related to discontinued operations.
			Three Months Ended				Six Months Ended
			March 31				March 31
			2012		2011		2012		2011
			(In thousands)
Operating revenues			$	26,374	$	35,790	$	49,825	$	59,523
Purchased gas cost				17,026		24,636		31,977		39,533
	Gross profit			9,348		11,154		17,848		19,990
Operating expenses				4,275		4,431		8,449		8,447
Operating income				5,073		6,723		9,399		11,543
Other nonoperating expense				(38)		(32)		(86)		(65)
Income from discontinued operations
	before income taxes			5,035		6,691		9,313		11,478
Income tax expense				1,834		2,642		3,393		4,532
		Net income	$	3,201	$	4,049	$	5,920	$	6,946

Assets held for sale table

The following table presents balance sheet data related to assets held for sale.
		March 31,		September 30,
		2012		2011
		(In thousands)
Net plant, property & equipment		$	126,587	$	127,577
Gas stored underground			6,517		11,931
Other current assets			515		786
Deferred charges and other assets			49		277
	Assets held for sale	$	133,668	$	140,571
Accounts payable and accrued liabilities		$	5,404	$	1,917
Other current liabilities			6,857		4,877
Regulatory cost of removal			7,687		10,498
Deferred credits and other liabilities			872		1,153
	Liabilities held for sale	$	20,820	$	18,445

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Commitments and Contingencies (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Loss Contingency Information About Litigation Matters Abstract
Description of Pending Litigation			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 appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court on March 19, 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. On March 27, 2012 the court denied the motion to dismiss. 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.
Long Term Commitment Purchases [Abstract]
Significant Purchase Commitment Amount Description	$ 264,300,000	$ 576,400,000	$ 438,900,000	$ 773,100,000
Long Term Purchase Commitment [Abstract]
Significant Purchase Commitment Remaining Minimum Amount Committed Current Fiscal Year	33,347,000		33,347,000
Significant Purchase Commitment Remaining Minimum Amount Committed Next Fiscal Year	71,496,000		71,496,000
Significant Purchase Commitment Remaining Minimum Amount Committed Second Fiscal Year	61,594,000		61,594,000
Significant Purchase Commitment Remaining Minimum Amount Committed Third Fiscal Year	0		0
Significant Purchase Commitment Remaining Minimum Amount Committed Fourth Fiscal Year	0		0
Significant Purchase Commitment Remaining Minimum Amount Committed Thereafter	0		0
Total Estimated Purchase Commitments	166,437,000		166,437,000
Other Matters [Abstract]
Steel Service Line Replacement Cost			81,400,000
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 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	96.2		96.2
Long Term Purchase Commitment Minimum Quantity Required One To Three Years	23.5		23.5
Long Term Purchase Commitment Minimum Quantity Required After Three Years	0.6		0.6
Inventories Under Fixed Price Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year	3.5		3.5
Long Term Purchase Commitment Minimum Quantity Required One To Three Years	0.6		0.6
Purchase Commitment Amount Minimum	1.75		1.75
Purchase Commitment Amount Maximum	$ 6.36		$ 6.36

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Earnings Per Share (Table)

6 Months Ended

Mar. 31, 2012

Disclosure Earnings Per Share

Earnings per share table

			Three Months Ended				Six Months Ended
			March 31				March 31
			2012		2011		2012		2011
			(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
	Income from continuing operations		$	105,910	$	128,160	$	171,698	$	199,260
	Less: Income from continuing operations allocated
		to participating securities		1,109		1,342		1,794		2,089
	Income from continuing operations available to
		common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Income from continuing operations per share - Basic		$	1.16	$	1.41	$	1.89	$	2.18
Basic Earnings Per Share from discontinued operations
	Income from discontinued operations		$	3,201	$	4,049	$	5,920	$	6,946
	Less: Income from discontinued operations
		allocated to participating securities		34		42		62		73
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Income from discontinued operations per share -
		Basic	$	0.04	$	0.04	$	0.06	$	0.08
	Net income per share - Basic		$	1.20	$	1.45	$	1.95	$	2.26
Diluted Earnings Per Share from continuing operations
	Income from continuing operations available to
		common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
	Effect of dilutive stock options and other shares			3		3		4		5
	Income from continuing operations available to
		common shareholders	$	104,804	$	126,821	$	169,908	$	197,176
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Additional dilutive stock options and other shares			302		287		303		298
	Diluted weighted average shares outstanding			90,322		90,533		90,440		90,455
	Income from continuing operations per share -
		Diluted	$	1.16	$	1.41	$	1.88	$	2.18
Diluted Earnings Per Share from discontinued operations
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Effect of dilutive stock options and other shares			-		-		-		-
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Additional dilutive stock options and other shares			302		287		303		298
	Diluted weighted average shares outstanding			90,322		90,533		90,440		90,455
	Income from discontinued operations per share -
		Diluted	$	0.04	$	0.04	$	0.06	$	0.08
	Net income per share - Diluted		$	1.20	$	1.45	$	1.94	$	2.26

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1. Nature of Business

6 Months Ended

Mar. 31, 2012

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 currently cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system. In May 2011, we entered into a definitive agreement to sell ournatural gasdistribution 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.Ourregulated 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.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (PARENTHETICALS) (USD $)	Mar. 31, 2012	Sep. 30, 2011
CONDENSED CONSOLIDATED BALANCE SHEETS
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	90,029,852	90,296,482

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11. Segment Information

6 Months Ended

Mar. 31, 2012

Segment Reporting [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, 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.

Income statements for the three and six month periods ended March 31, 2012 and 2011 by segment are presented in the following tables:

			Three Months Ended March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	888,685	$	20,430	$	334,335	$	-	$	1,243,450
Intersegment revenues				323		37,607		36,428		(74,358)		-
				889,008		58,037		370,763		(74,358)		1,243,450
Purchased gas cost				508,206		-		374,992		(74,009)		809,189
	Gross profit			380,802		58,037		(4,229)		(349)		434,261
Operating expenses
	Operation and maintenance			89,443		15,847		5,769		(351)		110,708
	Depreciation and amortization			51,755		7,792		725		-		60,272
	Taxes, other than income			50,313		3,915		691		-		54,919
Total operating expenses				191,511		27,554		7,185		(351)		225,899
Operating income (loss)				189,291		30,483		(11,414)		2		208,362
Miscellaneous income (expense)				733		(56)		567		(628)		616
Interest charges				28,833		7,614		839		(626)		36,660
Income (loss) from continuing
	operations before income taxes			161,191		22,813		(11,686)		-		172,318
Income tax expense (benefit)				62,890		8,193		(4,675)		-		66,408
Income (loss) from continuing
	operations			98,301		14,620		(7,011)		-		105,910
Income from discontinued
	operations, net of tax			3,201		-		-		-		3,201
		Net income (loss)	$	101,502	$	14,620	$	(7,011)	$	-	$	109,111
Capital expenditures			$	114,402	$	38,871	$	3,456	$	-	$	156,729

			Three Months Ended March 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,077,178	$	21,597	$	482,722	$	-	$	1,581,497
Intersegment revenues				236		33,379		100,809		(134,424)		-
				1,077,414		54,976		583,531		(134,424)		1,581,497
Purchased gas cost				698,410		-		563,473		(134,054)		1,127,829
	Gross profit			379,004		54,976		20,058		(370)		453,668
Operating expenses
	Operation and maintenance			92,266		15,231		7,035		(370)		114,162
	Depreciation and amortization			48,555		5,798		1,114		-		55,467
	Taxes, other than income			50,088		4,113		(643)		-		53,558
	Asset impairment			-		-		19,282		-		19,282
Total operating expenses				190,909		25,142		26,788		(370)		242,469
Operating income (loss)				188,095		29,834		(6,730)		-		211,199
Miscellaneous income				20,156		5,861		306		(121)		26,202
Interest charges				29,605		8,085		306		(121)		37,875
Income (loss) from continuing
	operations before income taxes			178,646		27,610		(6,730)		-		199,526
Income tax expense (benefit)				64,085		9,871		(2,590)		-		71,366
Income (loss) from continuing
	operations			114,561		17,739		(4,140)		-		128,160
Income from discontinued
	operations, net of tax			4,049		-		-		-		4,049
		Net income (loss)	$	118,610	$	17,739	$	(4,140)	$	-	$	132,209
Capital expenditures			$	109,762	$	11,818	$	1,921	$	-	$	123,501

			Six Months Ended March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,581,753	$	39,870	$	723,000	$	-	$	2,344,623
Intersegment revenues				547		74,926		91,939		(167,412)		-
				1,582,300		114,796		814,939		(167,412)		2,344,623
Purchased gas cost				910,413		-		803,763		(166,696)		1,547,480
	Gross profit			671,887		114,796		11,176		(716)		797,143
Operating expenses
	Operation and maintenance			182,857		32,812		11,820		(719)		226,770
	Depreciation and amortization			102,586		15,443		1,458		-		119,487
	Taxes, other than income			88,792		7,699		1,626		-		98,117
Total operating expenses				374,235		55,954		14,904		(719)		444,374
Operating income (loss)				297,652		58,842		(3,728)		3		352,769
Miscellaneous income (expense)				(1,023)		(336)		603		(503)		(1,259)
Interest charges				56,688		14,823		1,091		(500)		72,102
Income (loss) from continuing
	operations before income taxes			239,941		43,683		(4,216)		-		279,408
Income tax expense (benefit)				93,735		15,649		(1,674)		-		107,710
Income (loss) from continuing
	operations			146,206		28,034		(2,542)		-		171,698
Income from discontinued
	operations, net of tax			5,920		-		-		-		5,920
		Net income (loss)	$	152,126	$	28,034	$	(2,542)	$	-	$	177,618
Capital expenditures			$	243,135	$	62,991	$	4,997	$	-	$	311,123

			Six Months Ended March 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,780,439	$	42,830	$	891,490	$	-	$	2,714,759
Intersegment revenues				437		61,153		167,681		(229,271)		-
				1,780,876		103,983		1,059,171		(229,271)		2,714,759
Purchased gas cost				1,110,936		-		1,013,935		(228,504)		1,896,367
	Gross profit			669,940		103,983		45,236		(767)		818,392
Operating expenses
	Operation and maintenance			181,495		30,805		17,119		(767)		228,652
	Depreciation and amortization			96,449		11,597		2,198		-		110,244
	Taxes, other than income			84,536		7,666		1,524		-		93,726
	Asset impairment			-		-		19,282		-		19,282
Total operating expenses				362,480		50,068		40,123		(767)		451,904
Operating income				307,460		53,915		5,113		-		366,488
Miscellaneous income				19,458		5,579		596		(157)		25,476
Interest charges				59,302		16,149		1,476		(157)		76,770
Income from continuing
	operations before income taxes			267,616		43,345		4,233		-		315,194
Income tax expense				98,634		15,504		1,796		-		115,934
Income from continuing
	operations			168,982		27,841		2,437		-		199,260
Income from discontinued
	operations, net of tax			6,946		-		-		-		6,946
		Net income	$	175,928	$	27,841	$	2,437	$	-	$	206,206
Capital expenditures			$	219,261	$	24,557	$	2,845	$	-	$	246,663

Balance sheet information at March 31, 2012 and September 30, 2011 by segment is presented to reflect our business structure as of March 31, 2012in the following tables.

			March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,382,291	$	886,507	$	65,214	$	-	$	5,334,012
Investment in subsidiaries				674,594		-		(2,096)		(672,498)		-
Current assets
	Cash and cash equivalents			40,140		-		6,900		-		47,040
	Assets from risk
		management activities		502		-		2,877		-		3,379
	Other current assets			632,486		13,278		399,389		(201,731)		843,422
	Intercompany receivables			584,018		-		-		(584,018)		-
		Total current assets		1,257,146		13,278		409,166		(785,749)		893,841
Intangible assets				-		-		185		-		185
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			-		-		10,841		-		10,841
Deferred charges and other
	assets			366,329		13,203		10,316		-		389,848
			$	7,253,268	$	1,045,369	$	528,337	$	(1,458,247)	$	7,368,727
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,360,712	$	293,135	$	381,459	$	(674,594)	$	2,360,712
Long-term debt				1,956,147		-		66		-		1,956,213
		Total capitalization		4,316,859		293,135		381,525		(674,594)		4,316,925
Current liabilities
	Current maturities of
		long-term debt		250,000		-		131		-		250,131
	Short-term debt			371,996		-		-		(198,000)		173,996
	Liabilities from risk
		management activities		47,281		-		5,296		-		52,577
	Other current liabilities			507,354		6,309		119,382		(1,635)		631,410
	Intercompany payables			-		551,330		32,688		(584,018)		-
		Total current liabilities		1,176,631		557,639		157,497		(783,653)		1,108,114
Deferred income taxes				890,455		188,936		(16,903)		-		1,062,488
Noncurrent liabilities from
	risk management activities			1		-		5,300		-		5,301
Regulatory cost of removal
	obligation			414,001		-		-		-		414,001
Deferred credits and other
	liabilities			455,321		5,659		918		-		461,898
			$	7,253,268	$	1,045,369	$	528,337	$	(1,458,247)	$	7,368,727

			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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Document and Entity Information (USD $)	6 Months Ended
	Mar. 31, 2012	Apr. 27, 2012
Document And Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
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	Q2
Entity Common Stock Shares Outstanding		90,030,471
Entity Public Float	$ 2,764,486,845

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Accounting Policies (Policy)

6 Months Ended

Mar. 31, 2012

Disclosure Unaudited Interim Financial Information

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.

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 three and six months ended March 31, 2012, there were no changes in these methods.

Earnings Per Share, Policy [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 our 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.

Segment Reporting Policy [Policy Text Block]

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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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Operating revenues
Operating revenues	$ 1,243,450	$ 1,581,497	$ 2,344,623	$ 2,714,759
Purchased gas cost
Purchased gas cost	809,189	1,127,829	1,547,480	1,896,367
Gross profit	434,261	453,668	797,143	818,392
Operating expenses
Operation and maintenance	110,708	114,162	226,770	228,652
Depreciation and amortization	60,272	55,467	119,487	110,244
Taxes, other than income	54,919	53,558	98,117	93,726
Asset impairments	0	19,282	0	19,282
Total operating expenses	225,899	242,469	444,374	451,904
Operating income	208,362	211,199	352,769	366,488
Miscellaneous income (expense)	616	26,202	(1,259)	25,476
Interest charges	36,660	37,875	72,102	76,770
Income (loss) before income taxes	172,318	199,526	279,408	315,194
Income tax expense (benefit)	66,408	71,366	107,710	115,934
Income (loss) from continuing operations	105,910	128,160	171,698	199,260
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	3,201	4,049	5,920	6,946
Net income (loss)	109,111	132,209	177,618	206,206
Income Loss From Continuing Operations Per Basic Share	$ 1.16	$ 1.41	$ 1.89	$ 2.18
Income Loss From Discontinued Operations Net Of Tax Per Basic Share	$ 0.04	$ 0.04	$ 0.06	$ 0.08
Basic net income (loss) per share	$ 1.20	$ 1.45	$ 1.95	$ 2.26
Income Loss From Continuing Operations Per Diluted Share	$ 1.16	$ 1.41	$ 1.88	$ 2.18
Income Loss From Discontinued Operations Net Of Tax Per Diluted Share	$ 0.04	$ 0.04	$ 0.06	$ 0.08
Diluted net income (loss) per share	$ 1.20	$ 1.45	$ 1.94	$ 2.26
Cash dividends per share	$ 0.345	$ 0.340	$ 0.690	$ 0.680
Weighted average shares outstanding:
Basic	90,020	90,246	90,137	90,157
Diluted	90,322	90,533	90,440	90,455
Natural Gas Distribution Segment [Member]
Operating revenues
Operating revenues	889,008	1,077,414	1,582,300	1,780,876
Purchased gas cost
Purchased gas cost	508,206	698,410	910,413	1,110,936
Gross profit	380,802	379,004	671,887	669,940
Operating expenses
Operation and maintenance	89,443	92,266	182,857	181,495
Depreciation and amortization	51,755	48,555	102,586	96,449
Taxes, other than income	50,313	50,088	88,792	84,536
Asset impairments	0	0	0	0
Total operating expenses	191,511	190,909	374,235	362,480
Operating income	189,291	188,095	297,652	307,460
Miscellaneous income (expense)	733	20,156	(1,023)	19,458
Interest charges	28,833	29,605	56,688	59,302
Income (loss) before income taxes	161,191	178,646	239,941	267,616
Income tax expense (benefit)	62,890	64,085	93,735	98,634
Income (loss) from continuing operations	98,301	114,561	146,206	168,982
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	3,201	4,049	5,920	6,946
Net income (loss)	101,502	118,610	152,126	175,928
Regulated Transmission and Storage Segment [Member]
Operating revenues
Operating revenues	58,037	54,976	114,796	103,983
Purchased gas cost
Purchased gas cost	0	0	0	0
Gross profit	58,037	54,976	114,796	103,983
Operating expenses
Operation and maintenance	15,847	15,231	32,812	30,805
Depreciation and amortization	7,792	5,798	15,443	11,597
Taxes, other than income	3,915	4,113	7,699	7,666
Asset impairments	0	0	0	0
Total operating expenses	27,554	25,142	55,954	50,068
Operating income	30,483	29,834	58,842	53,915
Miscellaneous income (expense)	(56)	5,861	(336)	5,579
Interest charges	7,614	8,085	14,823	16,149
Income (loss) before income taxes	22,813	27,610	43,683	43,345
Income tax expense (benefit)	8,193	9,871	15,649	15,504
Income (loss) from continuing operations	14,620	17,739	28,034	27,841
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	14,620	17,739	28,034	27,841
Nonregulated Segment [Member]
Operating revenues
Operating revenues	370,763	583,531	814,939	1,059,171
Purchased gas cost
Purchased gas cost	374,992	563,473	803,763	1,013,935
Gross profit	(4,229)	20,058	11,176	45,236
Operating expenses
Operation and maintenance	5,769	7,035	11,820	17,119
Depreciation and amortization	725	1,114	1,458	2,198
Taxes, other than income	691	(643)	1,626	1,524
Asset impairments	0	19,282	0	19,282
Total operating expenses	7,185	26,788	14,904	40,123
Operating income	(11,414)	(6,730)	(3,728)	5,113
Miscellaneous income (expense)	567	306	603	596
Interest charges	839	306	1,091	1,476
Income (loss) before income taxes	(11,686)	(6,730)	(4,216)	4,233
Income tax expense (benefit)	(4,675)	(2,590)	(1,674)	1,796
Income (loss) from continuing operations	(7,011)	(4,140)	(2,542)	2,437
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	(7,011)	(4,140)	(2,542)	2,437
Intersegment Elimination [Member]
Operating revenues
Operating revenues	(74,358)	(134,424)	(167,412)	(229,271)
Purchased gas cost
Purchased gas cost	(74,009)	(134,054)	(166,696)	(228,504)
Gross profit	(349)	(370)	(716)	(767)
Operating expenses
Operation and maintenance	(351)	(370)	(719)	(767)
Depreciation and amortization	0	0	0	0
Taxes, other than income	0	0	0	0
Asset impairments	0	0	0	0
Total operating expenses	(351)	(370)	(719)	(767)
Operating income	2	0	3	0
Miscellaneous income (expense)	(628)	(121)	(503)	(157)
Interest charges	(626)	(121)	(500)	(157)
Income (loss) before income taxes	0	0	0	0
Income tax expense (benefit)	0	0	0	0
Income (loss) from continuing operations	0	0	0	0
Discontinued Operation Income Loss From Discontinued Operation During Phase Out Period Net Of Tax	0	0	0	0
Net income (loss)	$ 0	$ 0	$ 0	$ 0

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6. Debt

6 Months Ended

Mar. 31, 2012

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 six months ended March 31, 2012.

Long-term debt

Long-term debt at March 31, 2012 and September 30, 2011 consisted of the following:

			March 31,		September 30,
			2012		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				196		262
		Total long-term debt		2,210,196		2,212,565
Less:
	Original issue discount on unsecured senior
		notes and debentures		(3,852)		(4,014)
	Current maturities			(250,131)		(2,434)
			$	1,956,213	$	2,206,117

Our unsecured 10% notes were paid on their maturity date on December 31, 2011 and were not replaced. As noted above, our Unsecured 5.125% Senior Notes will mature in January 2013; accordingly, these have been classified within the current maturities of long-term debt.

Short-term debt

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

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 March 31, 2012 and September 30, 2011, there was $174.0 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 March 31, 2012.Our $25 million unsecured facility was renewed effective April 1, 2012. This facility bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin.

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 $82.0 millionat March 31, 2012.

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 March 31, 2012, $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 March 31, 2012, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 52 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 March 31, 2012, AEM's ratio of total liabilities to tangible net worth, as defined, was 0.97to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $20 million to $40 million. As defined in the financial covenants, at March 31, 2012, AEM's net working capital was $105.9million and its tangible net worth was $142.5million.

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 March 31, 2012. 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

6 Months Ended

Mar. 31, 2012

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 acash 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 condensed consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overheadand 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 condensed consolidated balance sheets at March 31, 2012 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				Six Months Ended
			March 31				March 31
			2012		2011		2012		2011
			(In thousands)
Operating revenues			$	26,374	$	35,790	$	49,825	$	59,523
Purchased gas cost				17,026		24,636		31,977		39,533
	Gross profit			9,348		11,154		17,848		19,990
Operating expenses				4,275		4,431		8,449		8,447
Operating income				5,073		6,723		9,399		11,543
Other nonoperating expense				(38)		(32)		(86)		(65)
Income from discontinued operations
	before income taxes			5,035		6,691		9,313		11,478
Income tax expense				1,834		2,642		3,393		4,532
		Net income	$	3,201	$	4,049	$	5,920	$	6,946

The following table presents balance sheet data related to assets held for sale.
		March 31,		September 30,
		2012		2011
		(In thousands)
Net plant, property & equipment		$	126,587	$	127,577
Gas stored underground			6,517		11,931
Other current assets			515		786
Deferred charges and other assets			49		277
	Assets held for sale	$	133,668	$	140,571
Accounts payable and accrued liabilities		$	5,404	$	1,917
Other current liabilities			6,857		4,877
Regulatory cost of removal			7,687		10,498
Deferred credits and other liabilities			872		1,153
	Liabilities held for sale	$	20,820	$	18,445

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Debt (Table)

6 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Debt instrument [Table Text Block]

			March 31,		September 30,
			2012		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				196		262
		Total long-term debt		2,210,196		2,212,565
Less:
	Original issue discount on unsecured senior
		notes and debentures		(3,852)		(4,014)
	Current maturities			(250,131)		(2,434)
			$	1,956,213	$	2,206,117

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Unaudited Interim Financial Information (Table)

6 Months Ended

Mar. 31, 2012

Regulatory Assets And Liabilities Table [Abstract]

Regulatory assets and liabilities table

			March 31,		September 30,
			2012		2011
			(In thousands)
Regulatory assets:
	Pension and postretirement benefit costs	$	245,096	$	254,666
	Merger and integration costs, net		5,998		6,242
	Deferred gas costs		19,547		33,976
	Regulatory cost of removal asset		10,233		8,852
	Environmental costs		117		385
	Rate case costs		4,503		4,862
	Deferred franchise fees		333		379
	Other		8,861		3,534
		$	294,688	$	312,896
Regulatory liabilities:
	Deferred gas costs	$	15,232	$	8,130
	Regulatory cost of removal obligation		463,740		464,025
	Other		13,090		14,025
		$	492,062	$	486,180

Comprehensive Income Loss Table [Abstract]

Comprehensive income/loss table

		Three Months Ended				Six Months Ended
		March 31				March 31
		2012		2011		2012		2011
		(In thousands)
Net income		$	109,111	$	132,209	$	177,618	$	206,206
Unrealized holding gains on investments,
	net of tax expense of $1,203 and $477
	for the three months ended March 31,
	2012 and 2011 and of $1,717 and $932
	for the six months ended March 31, 2012
	and 2011		2,046		810		2,947		1,586
Amortization, unrealized gain and unwinding
	of treasury lock agreements, net of tax
	expense (benefit) of $9,042 and $(6,125)
	for the three months ended March 31, 2012
	and 2011 and $8,404 and $12,579 for the six
	month ended March 31, 2012 and 2011		15,396		(10,427)		14,309		21,420
Net unrealized gains (losses) on cash flow
	hedging transactions, net of tax expense
	(benefit) of $(3,399) and $2,573 for the three
	months ended March 31, 2012 and 2011 and
	$(13,996) and $9,190 for the six months
	ended March 31, 2012 and 2011		(5,315)		4,025		(21,890)		14,375
Comprehensive income		$	121,238	$	126,617	$	172,984	$	243,587

Accumulated Other Comprehensive Income Loss Table [Abstract]

Accumulated other comprehensive income/loss table

		March 31,		September 30,
		2012		2011
		(In thousands)
Accumulated other comprehensive income (loss):
	Unrealized holding gains on investments	$	5,505	$	2,558
	Treasury lock agreements		(19,848)		(34,157)
	Cash flow hedges		(38,751)		(16,861)
		$	(53,094)	$	(48,460)

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9. Commitments and Contingencies

6 Months Ended

Mar. 31, 2012

Commitments And Contingencies [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 six months ended March 31, 2012.

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 appellees' brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court on March 19, 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. On March 27, 2012 the court denied the motion to dismiss.

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 March 31, 2012, AEH was committed to purchase 96.2Bcf within one year, 23.5 Bcf within one to three years and 0.6Bcf after three yearsunder indexed contracts. AEH is committed to purchase 3.5Bcf within one year and0.6 Bcf within one to three years under fixed price contracts with prices ranging from $1.75to $6.36per Mcf. Purchases under these contracts totaled $264.3million and $438.9million for the three months ended March 31, 2012 and 2011 and $576.4million and $773.1 million for the six months ended March 31, 2012 and 2011.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of March 31, 2012 are as follows (in thousands):

2012	$	33,347
2013		71,496
2014		61,594
2015		-
2016		-
Thereafter		-
	$	166,437

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 six months ended March 31, 2012.

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 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 March 31, 2012, we had replaced 73,822 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 $81.4 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 Commodity Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the SEC and CFTC 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 the Company. 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. Additional reporting and disclosure obligations have been imposed upon the Company, the full extent of which will not be known until the SEC and the CFTC have completed their ongoing rulemaking process.

As of March 31, 2012, rate cases were in progress in our Mid-Tex, West Texas and Kansas service areas and annual rate filing mechanisms were in progress in our Mid-Tex and Louisiana service areas along with one infrastructure program filing in progress in our Atmos Pipeline – Texas 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

6 Months Ended

Mar. 31, 2012

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 our 1998 Long-Term Incentive Plan, are considered to be participating securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three and six months ended March 31, 2012 and 2011 are calculated as follows:

			Three Months Ended				Six Months Ended
			March 31				March 31
			2012		2011		2012		2011
			(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
	Income from continuing operations		$	105,910	$	128,160	$	171,698	$	199,260
	Less: Income from continuing operations allocated
		to participating securities		1,109		1,342		1,794		2,089
	Income from continuing operations available to
		common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Income from continuing operations per share - Basic		$	1.16	$	1.41	$	1.89	$	2.18
Basic Earnings Per Share from discontinued operations
	Income from discontinued operations		$	3,201	$	4,049	$	5,920	$	6,946
	Less: Income from discontinued operations
		allocated to participating securities		34		42		62		73
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Income from discontinued operations per share -
		Basic	$	0.04	$	0.04	$	0.06	$	0.08
	Net income per share - Basic		$	1.20	$	1.45	$	1.95	$	2.26
Diluted Earnings Per Share from continuing operations
	Income from continuing operations available to
		common shareholders	$	104,801	$	126,818	$	169,904	$	197,171
	Effect of dilutive stock options and other shares			3		3		4		5
	Income from continuing operations available to
		common shareholders	$	104,804	$	126,821	$	169,908	$	197,176
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Additional dilutive stock options and other shares			302		287		303		298
	Diluted weighted average shares outstanding			90,322		90,533		90,440		90,455
	Income from continuing operations per share -
		Diluted	$	1.16	$	1.41	$	1.88	$	2.18
Diluted Earnings Per Share from discontinued operations
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Effect of dilutive stock options and other shares			-		-		-		-
	Income from discontinued operations available to
		common shareholders	$	3,167	$	4,007	$	5,858	$	6,873
	Basic weighted average shares outstanding			90,020		90,246		90,137		90,157
	Additional dilutive stock options and other shares			302		287		303		298
	Diluted weighted average shares outstanding			90,322		90,533		90,440		90,455
	Income from discontinued operations per share -
		Diluted	$	0.04	$	0.04	$	0.06	$	0.08
	Net income per share - Diluted		$	1.20	$	1.45	$	1.94	$	2.26

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2012 and 2011 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. However, 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 March 31, 2012, 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

6 Months Ended

Mar. 31, 2012

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 and six months ended March 31, 2012 and 2011 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 March 31
			Pension Benefits				Other Benefits
			2012		2011		2012		2011
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	4,298	$	4,257	$	4,088	$	3,601
	Interest cost			6,678		7,055		3,466		3,203
	Expected return on assets			(5,369)		(6,285)		(652)		(682)
	Amortization of transition asset			-		-		378		378
	Amortization of prior service cost			(36)		(105)		(363)		(363)
	Amortization of actuarial loss			4,143		2,748		662		86
	Curtailment gain			-		(40)		-		-
		Net periodic pension cost	$	9,714	$	7,630	$	7,579	$	6,223
			Six Months Ended March 31
			Pension Benefits				Other Benefits
			2012		2011		2012		2011
			(In thousands)
Components of net periodic pension cost:
	Service cost		$	8,596	$	8,637	$	8,176	$	7,202
	Interest cost			13,355		13,979		6,931		6,406
	Expected return on assets			(10,737)		(12,248)		(1,304)		(1,364)
	Amortization of transition asset			-		-		756		756
	Amortization of prior service cost			(71)		(217)		(725)		(725)
	Amortization of actuarial loss			8,285		6,242		1,324		173
	Curtailment gain			-		(40)		-		-
		Net periodic pension cost	$	19,428	$	16,353	$	15,158	$	12,448

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2012 and 2011 are as follows:

	Pension				Other
	Account Plan				Pension Benefits				Other Benefits
	2012		2011		2012		2011		2012		2011
Discount rate	5.05	%	5.68	%	5.05	%	5.39	%	5.05	%	5.39	%
Rate of compensation increase	3.50	%	4.00	%	3.50	%	4.00	%	N/A		N/A
Expected return on plan assets	7.75	%	8.25	%	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 contributed $23.0 million to our defined benefit pension plans during the second fiscal quarter to achieve a desirable PPA funding threshold. The need for this funding reflects the increased pension benefit obligation due to a decrease in the discount rate compared to the prior year as well as a decline in the fair value of plan assets. During the first six months of fiscal 2012, we contributed $34.2 million to our defined benefit plans and we anticipate contributing an additional $12.4 million during the remainder of the fiscal year.

We contributed $9.1 million to our other post-retirement benefit plans during the six months ended March 31, 2012. We expect to contribute a total of approximately $10million to $15million to these plans during the remainder of the fiscal year.

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10. Concentration of Credit Risk

6 Months Ended

Mar. 31, 2012

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 six months ended March 31, 2012, there were no material changes in our concentration of credit risk.

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Earnings Per Share (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Basic Earnings per Share from Continuing Operations
Income (loss) from continuing operations	$ 105,910,000	$ 128,160,000	$ 171,698,000	$ 199,260,000
Less: Income (loss) from continuing operations allocated to participating securities	1,109,000	1,342,000	1,794,000	2,089,000
Income (loss) from continuing operations available to common shareholders	104,801,000	126,818,000	169,904,000	197,171,000
Income Loss From Continuing Operations Per Basic Share	$ 1.16	$ 1.41	$ 1.89	$ 2.18
Basic Earnings per Share from Discontinued Operations
Income (loss) from discontinued operations	3,201,000	4,049,000	5,920,000	6,946,000
Less: Income (loss) from discontinued operations allocated to participating securities	34,000	42,000	62,000	73,000
Income (loss) from discontinued operations available to common shareholders	3,167,000	4,007,000	5,858,000	6,873,000
Income (loss) from discontinued operations per share - Basic	$ 0.04	$ 0.04	$ 0.06	$ 0.08
Basic net income (loss) per share	$ 1.20	$ 1.45	$ 1.95	$ 2.26
Basic	90,020,000	90,246,000	90,137,000	90,157,000
Diluted Earnings per Share from Continuing Operations
Effect of dilutive stock options and other shares	3,000	3,000	4,000	5,000
Income (loss) from continuing operations available to common shareholders	104,804,000	126,821,000	169,908,000	197,176,000
Additional dilutive stock options and other shares	302,000	287,000	303,000	298,000
Diluted	90,322,000	90,533,000	90,440,000	90,455,000
Income Loss From Continuing Operations Per Diluted Share	$ 1.16	$ 1.41	$ 1.88	$ 2.18
Diluted Earnings per Share from Discontinued Operations
Effect of dilutive stock options and other shares	0	0	0	0
Income (loss) from discontinued operations available to common shareholders	3,167,000	4,007,000	5,858,000	6,873,000
Additional dilutive stock options and other shares	302,000	287,000	303,000	298,000
Diluted weighted average shares outstanding	90,322,000	90,533,000	90,440,000	90,455,000
Income (loss) from discontinued operations per share - Diluted	$ 0.04	$ 0.04	$ 0.06	$ 0.08
Diluted net income (loss) per share	$ 1.20	$ 1.45	$ 1.94	$ 2.26
Earnings Per Share Diluted Other Disclosures Abstract
Share Repurchase Program - Shares Purchased			387,991
Share Repurchase Program - Number of Shares Authorized	5,000,000		5,000,000
Share Repurchase Program - Years Authorized	5		5
Share Repurchase Program - Amount Purchased			$ 12,500,000

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Fair Value Measurements (Table)

6 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Abstract]

Fair value measurements table

		Quoted		Significant		Significant
		Prices in		Other		Other
		Active		Observable		Unobservable		Netting and
		Markets		Inputs		Inputs		Cash		March 31,
		(Level 1)		(Level 2)(1)		(Level 3)		Collateral(2)		2012
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	502	$	-	$	-	$	502
	Nonregulated segment		52,013		249,313		-		(287,608)		13,718
Total financial instruments			52,013		249,815		-		(287,608)		14,220
Hedged portion of gas stored
	underground		73,043		-		-		-		73,043
Available-for-sale securities
	Money market funds		-		3,358		-		-		3,358
	Registered investment companies		38,424		-		-		-		38,424
	Bonds		-		23,637		-		-		23,637
Total available-for-sale securities			38,424		26,995		-		-		65,419
Total assets		$	163,480	$	276,810	$	-	$	(287,608)	$	152,682
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	48,034	$	-	$	-	$	48,034
	Nonregulated segment		76,476		227,424		-		(293,304)		10,596
Total liabilities		$	76,476	$	275,458	$	-	$	(293,304)	$	58,630

		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

	March 31, 2012
	(In thousands)
Carrying Amount	$	2,210,196
Fair Value	$	2,583,071

Available for sale securities table

				Gross		Gross
		Amortized		Unrealized		Unrealized		Fair
		Cost		Gain		Loss		Value
		(In thousands)
As of March 31, 2012:
	Domestic equity mutual funds	$	24,471	$	7,821	$	-	$	32,292
	Foreign equity mutual funds		5,327		805		-		6,132
	Bonds		23,525		127		(15)		23,637
	Money market funds		3,358		-		-		3,358
		$	56,681	$	8,753	$	(15)	$	65,419
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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Commitments and Contingencies (Table)

6 Months Ended

Mar. 31, 2012

Commitments And Contingencies [Abstract]

Long-term supply contracts purchase commitments table

2012	$	33,347
2013		71,496
2014		61,594
2015		-
2016		-
Thereafter		-
	$	166,437

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CONDENSED CONSOLIDATED STATEMENT OF INCOME (UNAUDITED) (PARENTHETICALS) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Discontinued Operation Tax Effect Of Income Loss From Discontinued Operation During Phase Out Period	$ 1,834	$ 2,642	$ 3,393	$ 4,532

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4. Fair Value Measurements

6 Months Ended

Mar. 31, 2012

Fair Value Disclosures [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 three and six months ended March 31, 2012, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 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 tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 and September 30, 2011. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

		Quoted		Significant		Significant
		Prices in		Other		Other
		Active		Observable		Unobservable		Netting and
		Markets		Inputs		Inputs		Cash		March 31,
		(Level 1)		(Level 2)(1)		(Level 3)		Collateral(2)		2012
			(In thousands)
Assets:
Financial instruments
	Natural gas distribution segment	$	-	$	502	$	-	$	-	$	502
	Nonregulated segment		52,013		249,313		-		(287,608)		13,718
Total financial instruments			52,013		249,815		-		(287,608)		14,220
Hedged portion of gas stored
	underground		73,043		-		-		-		73,043
Available-for-sale securities
	Money market funds		-		3,358		-		-		3,358
	Registered investment companies		38,424		-		-		-		38,424
	Bonds		-		23,637		-		-		23,637
Total available-for-sale securities			38,424		26,995		-		-		65,419
Total assets		$	163,480	$	276,810	$	-	$	(287,608)	$	152,682
Liabilities:
Financial instruments
	Natural gas distribution segment	$	-	$	48,034	$	-	$	-	$	48,034
	Nonregulated segment		76,476		227,424		-		(293,304)		10,596
Total liabilities		$	76,476	$	275,458	$	-	$	(293,304)	$	58,630

		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 March 31, 2012, we had $5.7million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $2.8million was used to offset current risk management liabilities under master netting arrangements and the remaining $2.9 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 $28.8million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $12.4million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.4million 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 March 31, 2012:
	Domestic equity mutual funds	$	24,471	$	7,821	$	-	$	32,292
	Foreign equity mutual funds		5,327		805		-		6,132
	Bonds		23,525		127		(15)		23,637
	Money market funds		3,358		-		-		3,358
		$	56,681	$	8,753	$	(15)	$	65,419
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 March 31, 2012 and September 30, 2011, our available-for-sale securities included $41.8 million and $38.3 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At March 31, 2012 we maintained investments in bonds that have contractual maturity dates ranging from April 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 several bonds with a cumulative fair value of $4.4 million in an unrealized loss position of less than $0.1 million as of March 31, 2012. 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 March 31, 2012.

Other Fair Value Measures

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of March 31, 2012:

	March 31, 2012
	(In thousands)
Carrying Amount	$	2,210,196
Fair Value	$	2,583,071

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Segment Information (Table)

6 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

Schedule of segment reporting income statement, by segment

			Three Months Ended March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	888,685	$	20,430	$	334,335	$	-	$	1,243,450
Intersegment revenues				323		37,607		36,428		(74,358)		-
				889,008		58,037		370,763		(74,358)		1,243,450
Purchased gas cost				508,206		-		374,992		(74,009)		809,189
	Gross profit			380,802		58,037		(4,229)		(349)		434,261
Operating expenses
	Operation and maintenance			89,443		15,847		5,769		(351)		110,708
	Depreciation and amortization			51,755		7,792		725		-		60,272
	Taxes, other than income			50,313		3,915		691		-		54,919
Total operating expenses				191,511		27,554		7,185		(351)		225,899
Operating income (loss)				189,291		30,483		(11,414)		2		208,362
Miscellaneous income (expense)				733		(56)		567		(628)		616
Interest charges				28,833		7,614		839		(626)		36,660
Income (loss) from continuing
	operations before income taxes			161,191		22,813		(11,686)		-		172,318
Income tax expense (benefit)				62,890		8,193		(4,675)		-		66,408
Income (loss) from continuing
	operations			98,301		14,620		(7,011)		-		105,910
Income from discontinued
	operations, net of tax			3,201		-		-		-		3,201
		Net income (loss)	$	101,502	$	14,620	$	(7,011)	$	-	$	109,111
Capital expenditures			$	114,402	$	38,871	$	3,456	$	-	$	156,729

			Three Months Ended March 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,077,178	$	21,597	$	482,722	$	-	$	1,581,497
Intersegment revenues				236		33,379		100,809		(134,424)		-
				1,077,414		54,976		583,531		(134,424)		1,581,497
Purchased gas cost				698,410		-		563,473		(134,054)		1,127,829
	Gross profit			379,004		54,976		20,058		(370)		453,668
Operating expenses
	Operation and maintenance			92,266		15,231		7,035		(370)		114,162
	Depreciation and amortization			48,555		5,798		1,114		-		55,467
	Taxes, other than income			50,088		4,113		(643)		-		53,558
	Asset impairment			-		-		19,282		-		19,282
Total operating expenses				190,909		25,142		26,788		(370)		242,469
Operating income (loss)				188,095		29,834		(6,730)		-		211,199
Miscellaneous income				20,156		5,861		306		(121)		26,202
Interest charges				29,605		8,085		306		(121)		37,875
Income (loss) from continuing
	operations before income taxes			178,646		27,610		(6,730)		-		199,526
Income tax expense (benefit)				64,085		9,871		(2,590)		-		71,366
Income (loss) from continuing
	operations			114,561		17,739		(4,140)		-		128,160
Income from discontinued
	operations, net of tax			4,049		-		-		-		4,049
		Net income (loss)	$	118,610	$	17,739	$	(4,140)	$	-	$	132,209
Capital expenditures			$	109,762	$	11,818	$	1,921	$	-	$	123,501

			Six Months Ended March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,581,753	$	39,870	$	723,000	$	-	$	2,344,623
Intersegment revenues				547		74,926		91,939		(167,412)		-
				1,582,300		114,796		814,939		(167,412)		2,344,623
Purchased gas cost				910,413		-		803,763		(166,696)		1,547,480
	Gross profit			671,887		114,796		11,176		(716)		797,143
Operating expenses
	Operation and maintenance			182,857		32,812		11,820		(719)		226,770
	Depreciation and amortization			102,586		15,443		1,458		-		119,487
	Taxes, other than income			88,792		7,699		1,626		-		98,117
Total operating expenses				374,235		55,954		14,904		(719)		444,374
Operating income (loss)				297,652		58,842		(3,728)		3		352,769
Miscellaneous income (expense)				(1,023)		(336)		603		(503)		(1,259)
Interest charges				56,688		14,823		1,091		(500)		72,102
Income (loss) from continuing
	operations before income taxes			239,941		43,683		(4,216)		-		279,408
Income tax expense (benefit)				93,735		15,649		(1,674)		-		107,710
Income (loss) from continuing
	operations			146,206		28,034		(2,542)		-		171,698
Income from discontinued
	operations, net of tax			5,920		-		-		-		5,920
		Net income (loss)	$	152,126	$	28,034	$	(2,542)	$	-	$	177,618
Capital expenditures			$	243,135	$	62,991	$	4,997	$	-	$	311,123

			Six Months Ended March 31, 2011
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
Operating revenues from
	external parties		$	1,780,439	$	42,830	$	891,490	$	-	$	2,714,759
Intersegment revenues				437		61,153		167,681		(229,271)		-
				1,780,876		103,983		1,059,171		(229,271)		2,714,759
Purchased gas cost				1,110,936		-		1,013,935		(228,504)		1,896,367
	Gross profit			669,940		103,983		45,236		(767)		818,392
Operating expenses
	Operation and maintenance			181,495		30,805		17,119		(767)		228,652
	Depreciation and amortization			96,449		11,597		2,198		-		110,244
	Taxes, other than income			84,536		7,666		1,524		-		93,726
	Asset impairment			-		-		19,282		-		19,282
Total operating expenses				362,480		50,068		40,123		(767)		451,904
Operating income				307,460		53,915		5,113		-		366,488
Miscellaneous income				19,458		5,579		596		(157)		25,476
Interest charges				59,302		16,149		1,476		(157)		76,770
Income from continuing
	operations before income taxes			267,616		43,345		4,233		-		315,194
Income tax expense				98,634		15,504		1,796		-		115,934
Income from continuing
	operations			168,982		27,841		2,437		-		199,260
Income from discontinued
	operations, net of tax			6,946		-		-		-		6,946
		Net income	$	175,928	$	27,841	$	2,437	$	-	$	206,206
Capital expenditures			$	219,261	$	24,557	$	2,845	$	-	$	246,663

Schedule of segment reporting balance sheet information, by segment

			March 31, 2012
			Natural		Regulated
			Gas		Transmission
			Distribution		and Storage		Nonregulated		Eliminations		Consolidated
			(In thousands)
ASSETS
Property, plant and
	equipment, net		$	4,382,291	$	886,507	$	65,214	$	-	$	5,334,012
Investment in subsidiaries				674,594		-		(2,096)		(672,498)		-
Current assets
	Cash and cash equivalents			40,140		-		6,900		-		47,040
	Assets from risk
		management activities		502		-		2,877		-		3,379
	Other current assets			632,486		13,278		399,389		(201,731)		843,422
	Intercompany receivables			584,018		-		-		(584,018)		-
		Total current assets		1,257,146		13,278		409,166		(785,749)		893,841
Intangible assets				-		-		185		-		185
Goodwill				572,908		132,381		34,711		-		740,000
Noncurrent assets from risk
	management activities			-		-		10,841		-		10,841
Deferred charges and other
	assets			366,329		13,203		10,316		-		389,848
			$	7,253,268	$	1,045,369	$	528,337	$	(1,458,247)	$	7,368,727
CAPITALIZATION AND
	LIABILITIES
Shareholders' equity			$	2,360,712	$	293,135	$	381,459	$	(674,594)	$	2,360,712
Long-term debt				1,956,147		-		66		-		1,956,213
		Total capitalization		4,316,859		293,135		381,525		(674,594)		4,316,925
Current liabilities
	Current maturities of
		long-term debt		250,000		-		131		-		250,131
	Short-term debt			371,996		-		-		(198,000)		173,996
	Liabilities from risk
		management activities		47,281		-		5,296		-		52,577
	Other current liabilities			507,354		6,309		119,382		(1,635)		631,410
	Intercompany payables			-		551,330		32,688		(584,018)		-
		Total current liabilities		1,176,631		557,639		157,497		(783,653)		1,108,114
Deferred income taxes				890,455		188,936		(16,903)		-		1,062,488
Noncurrent liabilities from
	risk management activities			1		-		5,300		-		5,301
Regulatory cost of removal
	obligation			414,001		-		-		-		414,001
Deferred credits and other
	liabilities			455,321		5,659		918		-		461,898
			$	7,253,268	$	1,045,369	$	528,337	$	(1,458,247)	$	7,368,727

			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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Financial Instruments (Table)

6 Months Ended

Mar. 31, 2012

Financial Instruments [Abstract]

Oustanding commodity contracts volumes table

		Natural
	Hedge	Gas
Contract Type	Designation	Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	-	(38,340)
	Cash Flow	-	49,098
	Not designated	6,033	28,190
		6,033	38,948

Financial instruments on the balance sheet

						Natural
						Gas
				Balance Sheet Location		Distribution		Nonregulated		Total
March 31, 2012						(In thousands)
Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets		$	-	$	77,441	$	77,441
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		-		-
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities			(45,818)		(59,301)		(105,119)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		-		(10,914)		(10,914)
	Total						(45,818)		7,226		(38,592)
Not Designated As Hedges:
	Asset Financial Instruments
		Current commodity contracts		Other current assets			502		137,934		138,436
		Noncurrent commodity		Deferred charges and
			contracts		other assets		-		85,951		85,951
	Liability Financial Instruments
		Current commodity contracts		Other current liabilities(1)			(2,215)		(164,189)		(166,404)
		Noncurrent commodity		Deferred credits and
			contracts		other liabilities		(1)		(69,496)		(69,497)
	Total						(1,714)		(9,800)		(11,514)
Total Financial Instruments						$	(47,532)	$	(2,574)	$	(50,106)

						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 March 31
		2012		2011
		(In thousands)
Commodity contracts		$	29,090	$	(1,279)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(35,087)		5,586
Total impact on revenue		$	(5,997)	$	4,307
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	(739)	$	(509)
	Timing ineffectiveness		(5,258)		4,816
		$	(5,997)	$	4,307
		Six Months Ended March 31
		2012		2011
			(In thousands)
Commodity contracts		$	53,153	$	(3,003)
Fair value adjustment for natural gas
	inventory designated as the hedged item		(50,335)		21,211
Total impact on revenue		$	2,818	$	18,208
The impact on revenue is comprised of
the following:
	Basis ineffectiveness	$	102	$	412
	Timing ineffectiveness		2,716		17,796
		$	2,818	$	18,208

Cash flow hedges [Table Text Block]

		Three Months Ended March 31, 2012
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(21,181)	$	(21,181)
Loss arising from ineffective portion of
	commodity contracts		-		-		(238)		(238)
Total impact on revenue			-		-		(21,419)		(21,419)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(502)		-		-		(502)
Total Impact from Cash Flow Hedges		$	(502)	$	-	$	(21,419)	$	(21,921)
		Three Months Ended March 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(7,328)	$	(7,328)
Loss arising from ineffective portion of
	commodity contracts		-		-		(233)		(233)
Total impact on revenue			-		-		(7,561)		(7,561)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(669)		-		-		(669)
Gain on unwinding of Treasury lock reclassified
	from AOCI into miscellaneous income		21,803		6,000		-		27,803
Total Impact from Cash Flow Hedges		$	21,134	$	6,000	$	(7,561)	$	19,573
		Six Months Ended March 31, 2012
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(32,823)	$	(32,823)
Loss arising from ineffective portion of
	commodity contracts		-		-		(668)		(668)
Total impact on revenue			-		-		(33,491)		(33,491)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(1,004)		-		-		(1,004)
Total Impact from Cash Flow Hedges		$	(1,004)	$	-	$	(33,491)	$	(34,495)
		Six Months Ended March 31, 2011
		Natural		Regulated
		Gas		Transmission
		Distribution		and Storage		Nonregulated		Consolidated
		(In thousands)
Loss reclassified from AOCI into revenue
	for effective portion of commodity contracts	$	-	$	-	$	(21,581)	$	(21,581)
Loss arising from ineffective portion of
	commodity contracts		-		-		(677)		(677)
Total impact on revenue			-		-		(22,258)		(22,258)
Loss on settled Treasury lock agreements
	reclassified from AOCI into interest expense		(1,339)		-		-		(1,339)
Gain on unwinding of Treasury lock reclassified
	from AOCI into miscellaneous income		21,803		6,000		-		27,803
Total Impact from Cash Flow Hedges		$	20,464	$	6,000	$	(22,258)	$	4,206

Other comprehensive income from hedging table

		Three Months Ended				Six Months Ended
		March 31				March 31
		2012		2011		2012		2011
		(In thousands)
Increase (decrease) in fair value:
	Treasury lock agreements	$	15,079	$	6,667	$	13,676	$	38,092
	Forward commodity contracts		(18,234)		(446)		(41,912)		1,211
Recognition of (gains) losses in earnings due to
	settlements:
	Treasury lock agreements		317		(17,094)		633		(16,672)
	Forward commodity contracts		12,919		4,471		20,022		13,164
Total other comprehensive income (loss) from
	hedging, net of tax(1)	$	10,081	$	(6,402)	$	(7,581)	$	35,795

Expected recognition in earnings of deferred losses in AOCI table

	Treasury
	Lock		Commodity
	Agreements		Contracts		Total
	(In thousands)
Next twelve months	$	(1,266)	$	(32,130)	$	(33,396)
Thereafter		10,284		(6,621)		3,663
Total(1)	$	9,018	$	(38,751)	$	(29,733)