UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2014

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 January 30, 2015.

Class	Shares Outstanding
No Par Value	100,862,051

GLOSSARY OF KEY TERMS

AEC	Atmos Energy Corporation
AEH	Atmos Energy Holdings, Inc.
AEM	Atmos Energy Marketing, LLC
AOCI	Accumulated other comprehensive income
Bcf	Billion cubic feet
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings, Ltd.
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
Mcf	Thousand cubic feet
MMcf	Million cubic feet
Moody’s	Moody’s Investors Services, Inc.
NYMEX	New York Mercantile Exchange, Inc.
PPA	Pension Protection Act of 2006
PRP	Pipeline Replacement Program
RRC	Railroad Commission of Texas
RRM	Rate Review Mechanism
S&P	Standard & Poor’s Corporation
SEC	United States Securities and Exchange Commission
WNA	Weather Normalization Adjustment

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	December 31, 2014			September 30, 2014
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	8,661,288		$	8,447,700
Less accumulated depreciation and amortization	1,748,747			1,721,794
Net property, plant and equipment	6,912,541			6,725,906
Current assets
Cash and cash equivalents	123,832			42,258
Accounts receivable, net	607,421			343,400
Gas stored underground	277,916			278,917
Other current assets	109,595			111,265
Total current assets	1,118,764			775,840
Goodwill	742,029			742,029
Deferred charges and other assets	341,759			350,929
	$	9,115,093		$	8,594,704
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2014 — 100,854,217 shares; September 30, 2014 — 100,388,092 shares	$	504		$	502
Additional paid-in capital	2,181,645			2,180,151
Retained earnings	975,975			917,972
Accumulated other comprehensive loss	(94,199		)	(12,393		)
Shareholders’ equity	3,063,925			3,086,232
Long-term debt	2,455,131			2,455,986
Total capitalization	5,519,056			5,542,218
Current liabilities
Accounts payable and accrued liabilities	397,595			308,086
Other current liabilities	472,113			405,869
Short-term debt	550,903			196,695
Total current liabilities	1,420,611			910,650
Deferred income taxes	1,256,443			1,286,616
Regulatory cost of removal obligation	443,931			445,387
Pension and postretirement liabilities	345,350			340,963
Deferred credits and other liabilities	129,702			68,870
	$	9,115,093		$	8,594,704

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months Ended   December 31
	2014			2013
	(Unaudited) (In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	846,772		$	843,865
Regulated pipeline segment	83,567			71,341
Nonregulated segment	462,288			436,431
Intersegment eliminations	(133,862		)	(107,779		)
	1,258,765			1,243,858
Purchased gas cost
Regulated distribution segment	522,960			544,694
Regulated pipeline segment	—			—
Nonregulated segment	446,249			417,865
Intersegment eliminations	(133,729		)	(107,658		)
	835,480			854,901
Gross profit	423,285			388,957
Operating expenses
Operation and maintenance	118,582			115,757
Depreciation and amortization	67,593			60,469
Taxes, other than income	49,385			42,011
Total operating expenses	235,560			218,237
Operating income	187,725			170,720
Miscellaneous expense	(1,707		)	(2,132		)
Interest charges	29,764			32,115
Income before income taxes	156,254			136,473
Income tax expense	58,659			49,457
Net income	$	97,595		$	87,016
Basic net income per share	$	0.96		$	0.95
Diluted net income per share	$	0.96		$	0.95
Cash dividends per share	$	0.39		$	0.37
Weighted average shares outstanding:
Basic	101,581			91,841
Diluted	101,581			91,843

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended   December 31
	2014			2013
	(Unaudited) (In thousands)
Net income	$	97,595		$	87,016
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(613) and $1,435	(1,067		)	2,394
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(29,768) and $8,013	(51,787		)	13,942
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(18,696) and $4,999	(28,952		)	7,818
Total other comprehensive income (loss)	(81,806		)	24,154
Total comprehensive income	$	15,789		$	111,170

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended   December 31
	2014			2013
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	97,595		$	87,016
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization	67,593			60,469
Charged to other accounts	275			221
Deferred income taxes	55,418			47,127
Other	4,889			5,228
Net assets / liabilities from risk management activities	(20,828		)	(5,477		)
Net change in operating assets and liabilities	(177,527		)	(160,284		)
Net cash provided by operating activities	27,415			34,300
Cash Flows From Investing Activities
Capital expenditures	(261,313		)	(180,567		)
Other, net	(739		)	(5,867		)
Net cash used in investing activities	(262,052		)	(186,434		)
Cash Flows From Financing Activities
Net increase in short-term debt	350,574			320,783
Net proceeds from issuance of long-term debt	493,538			—
Settlement of interest rate agreements	13,364			—
Repayment of long-term debt	(500,000		)	—
Cash dividends paid	(39,592		)	(33,984		)
Repurchase of equity awards	(7,985		)	(6,289		)
Issuance of common stock	6,312			(12		)
Net cash provided by financing activities	316,211			280,498
Net increase in cash and cash equivalents	81,574			128,364
Cash and cash equivalents at beginning of period	42,258			66,199
Cash and cash equivalents at end of period	$	123,832		$	194,563

See accompanying notes to condensed consolidated financial statements.

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ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2014

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 pipeline businesses as well as other nonregulated natural gas businesses. Historically, our regulated businesses have generated over 90 percent of our consolidated net income.

Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at December 31, 2014, covered service areas located in eight states. In addition, we transport natural gas for others through our distribution system. Our regulated businesses also include our regulated pipeline and storage operations, which include the transportation of natural gas to our North Texas 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 regulated 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.

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, 2014. 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, 2014. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2014 are not indicative of our results of operations for the full 2015 fiscal year, which ends September 30, 2015.

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, 2014.

Certain prior-year amounts have been reclassified to conform with the current year presentation.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. The new standard is currently scheduled to become effective for us beginning on October 1, 2017 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

There were no other significant changes to our accounting policies during the three months ended December 31, 2014 that will become applicable to the Company in future periods.

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.

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Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.

Significant regulatory assets and liabilities as of December 31, 2014 and September 30, 2014 included the following:

	December 31, 2014		September 30, 2014
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	158,190	$	162,777
Merger and integration costs, net	4,595		4,730
Deferred gas costs	38,022		20,069
Rate case costs	2,427		3,757
Texas Rule 8.209(2)	36,100		26,948
APT annual adjustment mechanism	5,623		8,479
Recoverable loss on reacquired debt	18,238		18,877
Other	4,297		4,672
	$	267,492	$	250,309
Regulatory liabilities:
Deferred gas costs	$	61,530	$	35,063
Deferred franchise fees	7,367		5,268
Regulatory cost of removal obligation	489,210		490,448
Other	13,808		14,980
	$	571,915	$	545,759

⁽¹⁾  Includes $17.7 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.

⁽²⁾  Texas Rule 8.209 is a Railroad Commission rule that 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.

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years.

3.    Segment Information

We operate the Company through the following three segments:

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

• The regulated pipeline 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 regulated distribution segment operations are geographically dispersed, they are reported as a single segment as each regulated 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, 2014. We evaluate performance based on net income or loss of the respective operating units.

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Income statements for the three month periods ended December 31, 2014 and 2013 by segment are presented in the following tables:

	Three Months Ended December 31, 2014
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	845,404		$	20,551		$	392,810	$	—		$	1,258,765
Intersegment revenues	1,368			63,016			69,478		(133,862		)	—
	846,772			83,567			462,288		(133,862		)	1,258,765
Purchased gas cost	522,960			—			446,249		(133,729		)	835,480
Gross profit	323,812			83,567			16,039		(133		)	423,285
Operating expenses
Operation and maintenance	86,985			24,615			7,115		(133		)	118,582
Depreciation and amortization	55,086			11,382			1,125		—			67,593
Taxes, other than income	43,644			4,865			876		—			49,385
Total operating expenses	185,715			40,862			9,116		(133		)	235,560
Operating income	138,097			42,705			6,923		—			187,725
Miscellaneous income (expense)	(1,329		)	(252		)	300		(426		)	(1,707		)
Interest charges	21,640			8,324			226		(426		)	29,764
Income before income taxes	115,128			34,129			6,997		—			156,254
Income tax expense	43,741			12,094			2,824		—			58,659
Net income	$	71,387		$	22,035		$	4,173	$	—		$	97,595
Capital expenditures	$	166,247		$	94,754		$	312	$	—		$	261,313

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	Three Months Ended December 31, 2013
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	842,432		$	21,170		$	380,256	$	—		$	1,243,858
Intersegment revenues	1,433			50,171			56,175		(107,779		)	—
	843,865			71,341			436,431		(107,779		)	1,243,858
Purchased gas cost	544,694			—			417,865		(107,658		)	854,901
Gross profit	299,171			71,341			18,566		(121		)	388,957
Operating expenses
Operation and maintenance	89,663			17,300			8,915		(121		)	115,757
Depreciation and amortization	49,551			9,786			1,132		—			60,469
Taxes, other than income	37,084			4,663			264		—			42,011
Total operating expenses	176,298			31,749			10,311		(121		)	218,237
Operating income	122,873			39,592			8,255		—			170,720
Miscellaneous income (expense)	(471		)	(1,181		)	324		(804		)	(2,132		)
Interest charges	23,325			8,957			637		(804		)	32,115
Income before income taxes	99,077			29,454			7,942		—			136,473
Income tax expense	36,320			10,008			3,129		—			49,457
Net income	$	62,757		$	19,446		$	4,813	$	—		$	87,016
Capital expenditures	$	127,506		$	52,921		$	140	$	—		$	180,567

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Balance sheet information at December 31, 2014 and September 30, 2014 by segment is presented in the following tables:

	December 31, 2014
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,310,469	$	1,544,320	$	57,752		$	—		$	6,912,541
Investment in subsidiaries	949,428		—		(2,096		)	(947,332		)	—
Current assets
Cash and cash equivalents	79,345		—		44,487			—			123,832
Assets from risk management activities	852		—		17,402			—			18,254
Other current assets	733,736		13,881		500,168			(271,107		)	976,678
Intercompany receivables	835,928		—		—			(835,928		)	—
Total current assets	1,649,861		13,881		562,057			(1,107,035		)	1,118,764
Goodwill	574,816		132,502		34,711			—			742,029
Noncurrent assets from risk management activities	124		—		—			—			124
Deferred charges and other assets	316,704		19,578		5,353			—			341,635
	$	8,801,402	$	1,710,281	$	657,777		$	(2,054,367	)	$	9,115,093
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,063,925	$	504,648	$	444,780		$	(949,428	)	$	3,063,925
Long-term debt	2,455,131		—		—			—			2,455,131
Total capitalization	5,519,056		504,648		444,780			(949,428		)	5,519,056
Current liabilities
Short-term debt	791,503		—		—			(240,600		)	550,903
Liabilities from risk management activities	13,701		—		—			—			13,701
Other current liabilities	675,685		23,722		185,011			(28,411		)	856,007
Intercompany payables	—		805,723		30,205			(835,928		)	—
Total current liabilities	1,480,889		829,445		215,216			(1,104,939		)	1,420,611
Deferred income taxes	887,452		376,018		(7,027		)	—			1,256,443
Noncurrent liabilities from risk management activities	82,123		—		—			—			82,123
Regulatory cost of removal obligation	443,931		—		—			—			443,931
Pension and postretirement liabilities	345,350		—		—			—			345,350
Deferred credits and other liabilities	42,601		170		4,808			—			47,579
	$	8,801,402	$	1,710,281	$	657,777		$	(2,054,367	)	$	9,115,093

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	September 30, 2014
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,202,761	$	1,464,572	$	58,573		$	—		$	6,725,906
Investment in subsidiaries	952,171		—		(2,096		)	(950,075		)	—
Current assets
Cash and cash equivalents	33,303		—		8,955			—			42,258
Assets from risk management activities	23,102		—		22,725			—			45,827
Other current assets	490,408		14,009		526,161			(342,823		)	687,755
Intercompany receivables	790,442		—		—			(790,442		)	—
Total current assets	1,337,255		14,009		557,841			(1,133,265		)	775,840
Goodwill	574,816		132,502		34,711			—			742,029
Noncurrent assets from risk management activities	13,038		—		—			—			13,038
Deferred charges and other assets	309,965		21,826		6,100			—			337,891
	$	8,390,006	$	1,632,909	$	655,129		$	(2,083,340	)	$	8,594,704
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,086,232	$	482,612	$	469,559		$	(952,171	)	$	3,086,232
Long-term debt	2,455,986		—		—			—			2,455,986
Total capitalization	5,542,218		482,612		469,559			(952,171		)	5,542,218
Current liabilities
Short-term debt	522,695		—		—			(326,000		)	196,695
Liabilities from risk management activities	1,730		—		—			—			1,730
Other current liabilities	559,765		24,790		142,397			(14,727		)	712,225
Intercompany payables	—		763,635		26,807			(790,442		)	—
Total current liabilities	1,084,190		788,425		169,204			(1,131,169		)	910,650
Deferred income taxes	913,260		361,688		11,668			—			1,286,616
Noncurrent liabilities from risk management activities	20,126		—		—			—			20,126
Regulatory cost of removal obligation	445,387		—		—			—			445,387
Pension and postretirement liabilities	340,963		—		—			—			340,963
Deferred credits and other liabilities	43,862		184		4,698			—			48,744
	$	8,390,006	$	1,632,909	$	655,129		$	(2,083,340	)	$	8,594,704

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4.    Earnings Per Share

We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three months ended December 31, 2014 and 2013 are calculated as follows:

	Three Months Ended   December 31
	2014		2013
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	97,595	$	87,016
Less: Income allocated to participating securities	216		232
Income available to common shareholders	$	97,379	$	86,784
Basic weighted average shares outstanding	101,581		91,841
Net income per share - Basic	$	0.96	$	0.95
Diluted Earnings Per Share
Net income available to common shareholders	$	97,379	$	86,784
Effect of dilutive stock options and other shares	—		—
Net income available to common shareholders	$	97,379	$	86,784
Basic weighted average shares outstanding	101,581		91,841
Additional dilutive stock options and other shares	—		2
Diluted weighted average shares outstanding	101,581		91,843
Net income per share - Diluted	$	0.96	$	0.95

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2013 as their exercise price was less than the average market price of the common stock during those periods. As of December 31, 2014 there were no outstanding options.

2014 Equity Offering

On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, including the underwriters’ exercise of their overallotment option of 1,200,000 shares under our existing shelf registration statement. The offering was priced at $44.00 and generated net proceeds of $390.2 million, which were used to repay short-term debt outstanding under our commercial paper program, fund infrastructure spending primarily to enhance the safety and reliability of our system and for general corporate purposes.

2011 Share Repurchase Program

We did not repurchase any shares during the three months ended December 31, 2014 and 2013 under our 2011 share repurchase program.

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5.    Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. Except as noted below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2014.

Long-term debt

Long-term debt at December 31, 2014 and September 30, 2014 consisted of the following:

	December 31, 2014		September 30, 2014
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	—	$	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
Unsecured 4.15% Senior Notes, due 2043	500,000		500,000
Unsecured 4.125% Senior Notes, due 2044	500,000		—
Medium-term note Series A, 1995-1, 6.67%, due 2025	10,000		10,000
Unsecured 6.75% Debentures, due 2028	150,000		150,000
Total long-term debt	2,460,000		2,460,000
Less:
Original issue discount on unsecured senior notes and debentures	4,869		4,014
	$	2,455,131	$	2,455,986

On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds of approximately $494 million were used to repay our $500 million4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt

Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. Our short-term borrowing requirements are affected primarily 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 currently finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1.3 billion of working capital funding. At December 31, 2014 and September 30, 2014 a total of $550.9 million and $196.7 million was outstanding under our commercial paper program.

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 $1.3 billion of working capital funding, including a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 billion, a $25 million unsecured facility and a $10 million unsecured 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 $4.1 million at December 31, 2014.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or

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(ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility and one committed $15 million 364-day bilateral credit facility that expire in December 2015. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $31.1 million at December 31, 2014.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM's borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.

Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013 that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. At December 31, 2014, $845 million of securities remain available for issuance under the shelf registration statement until March 28, 2016.

Debt Covenants

The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2014, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 51 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.

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 certain of 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.

We were in compliance with all of our debt covenants as of December 31, 2014. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

6.     Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2014 and 2013 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. On October 2, 2013, due to the retirement of one of our executive officers, we recognized a settlement loss of $4.5 million associated with our Supplemental Executive Benefits Plan (SEBP). In association with his retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.

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	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2014			2013			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	5,051		$	4,738		$	3,896		$	4,196
Interest cost	6,699			6,824			3,596			3,988
Expected return on assets	(6,436		)	(5,901		)	(1,608		)	(1,292		)
Amortization of transition obligation	—			—			68			68
Amortization of prior service credit	(49		)	(34		)	(411		)	(363		)
Amortization of actuarial loss	3,917			3,932			—			158
Settlement loss	—			4,539			—			—
Net periodic pension cost	$	9,182		$	14,098		$	5,541		$	6,755

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2014 and 2013 are as follows:

	Pension Benefits				Other Benefits
	2014		2013		2014		2013
Discount rate	4.43	%	4.95	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected return on plan assets	7.25	%	7.25	%	4.60	%	4.60	%

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, 2015. Due to current market conditions, the current funded position of the plans and the funding requirements under the PPA, we were not required to make a contribution to our defined benefit plans during the first quarter of fiscal 2015, nor do we anticipate making a contribution during the remainder of the fiscal year.

We contributed $5.6 million to our other post-retirement benefit plans during the three months ended December 31, 2014. We expect to contribute a total of approximately $20 million to $25 million to these plans during all of fiscal 2015.

In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. We anticipate utilizing the new mortality data in our next actuarial calculation date on September 30, 2015. We are currently evaluating the impact the updated data will have on the valuation of our defined benefit and other post-retirement benefits plans. It is expected the use of this new data will increase the total amount of liabilities reported on our balance sheet in future periods by less than five percent.

7.    Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 10 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2014.

We are a party to various 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.

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Purchase Commitments

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2014, AEH was committed to purchase 93.2 Bcf within one year, 11.6 Bcf within one to three years and 0.4 Bcf after three years under indexed contracts. AEH is committed to purchase 5.1 Bcf within one year under fixed price contracts with prices ranging from $1.22 to $4.49 per Mcf. Purchases under these contracts totaled $383.0 million and $350.2 million for the three months ended December 31, 2014 and 2013.

Our regulated 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 also maintains a limited number of 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 prices indexed to natural gas distribution hubs. At December 31, 2014, we were committed to purchase 47.0 Bcf within one year and 57.7 Bcf within one to three years under indexed contracts. Purchases under these contracts totaled $46.5 million, and $30.4 million for the three months ended December 31, 2014 and 2013.

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, 2014. There were no material changes to the estimated storage and transportation fees for the three months ended December 31, 2014.

Regulatory Matters

Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations.  Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.

As of December 31, 2014, rate cases were in progress in our Mid-Tex and Tennessee service areas, annual rate filing mechanisms were in progress in Louisiana, Texas and Mississippi and an infrastructure program and an other ratemaking filing were in progress in Kansas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

8.    Financial Instruments

We currently use financial instruments in our regulated distribution and nonregulated segments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments, which have been tailored to our regulated distribution and nongregulated segments, and the related accounting for these financial instruments are fully described in Notes 2 and 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the three months ended December 31, 2014 there were no changes in our objectives, strategies and accounting for using financial instruments. 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. The following summarizes those objectives and strategies.

Regulated Commodity Risk Management Activities

Our purchased gas cost adjustment mechanisms essentially insulate our regulated distribution segment from commodity price risk; however, 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.

We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2014-2015 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 37 percent, or 28.2 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Nonregulated Commodity Risk Management Activities

Our nonregulated segment is exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. We manage our exposure to such risks through

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a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Specifically, these operations use financial instruments in the following ways:

• Gas delivery and related services - Certain financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, are used to mitigate the commodity price risk associated with deliveries under fixed-priced forward contracts to either deliver gas to customers or purchase gas from suppliers. These financial instruments have maturity dates ranging from one to 58 months.

• Transportation and storage services - Our nonregulated operations 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 for accounting purposes.

• Aggregating and purchasing gas supply - Certain financial instruments, designated as fair value hedges, are used to hedge our natural gas inventory used in asset optimization activities.

Interest Rate Risk Management Activities

We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

As of December 31, 2014, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $250 million and $450 million unsecured senior notes in fiscal 2017 and fiscal 2019, at 3.37% and 3.78%, which we designated as cash flow hedges at the time the agreements were executed. As of December 31, 2014, we had $18.9 million net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extends through fiscal 2045.

Quantitative Disclosures Related to Financial Instruments

The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.

As of December 31, 2014, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2014, we had net long/(short) commodity contracts outstanding in the following quantities:

Contract Type	Hedge Designation	Regulated Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(17,225	)
	Cash Flow	—	65,720
	Not designated	16,493	76,750
		16,493	125,245

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Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2014 and September 30, 2014. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties.

		Regulated Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
December 31, 2014
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	38,443		$	(62,886	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			1,123			(9,136		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(80,721		)	—			—
Total		—		(80,721		)	39,566			(72,022		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	852		(13,701		)	179,884			(175,804		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	124		(1,402		)	9,036			(6,759		)
Total		976		(15,103		)	188,920			(182,563		)
Gross Financial Instruments		976		(95,824		)	228,486			(254,585		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(228,486		)	228,486
Net Financial Instruments		976		(95,824		)	—			(26,099		)
Cash collateral		—		—			17,402			26,099
Net Assets/Liabilities from Risk Management Activities		$	976	$	(95,824	)	$	17,402		$	—

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		Regulated Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
September 30, 2014
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	8,912		$	(7,082	)
Interest rate contracts	Other current assets / Other current liabilities	21,869		—			—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			757			(2,459		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	12,608		(19,835		)	—			—
Total		34,477		(19,835		)	9,669			(9,541		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	1,233		(1,730		)	43,677			(47,729		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	430		(291		)	15,677			(14,786		)
Total		1,663		(2,021		)	59,354			(62,515		)
Gross Financial Instruments		36,140		(21,856		)	69,023			(72,056		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(69,023		)	69,023
Net Financial Instruments		36,140		(21,856		)	—			(3,033		)
Cash collateral		—		—			22,725			3,033
Net Assets/Liabilities from Risk Management Activities		$	36,140	$	(21,856	)	$	22,725		$	—

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended December 31, 2014 and 2013 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(2.2) million and $5.1 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 months ended December 31, 2014 and 2013 is presented below.

	Three Months Ended   December 31
	2014			2013
	(In thousands)
Commodity contracts	$	15,090		$	(8,561	)
Fair value adjustment for natural gas inventory designated as the hedged item	(16,782		)	13,779
Total (increase) decrease in purchased gas cost	$	(1,692	)	$	5,218
The (increase) decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	986		$	(620	)
Timing ineffectiveness	(2,678		)	5,838
	$	(1,692	)	$	5,218

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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 purchased gas cost. 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.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2014 and 2013 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	Three Months Ended December 31, 2014
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	344		$	344
Loss arising from ineffective portion of commodity contracts	—			(490		)	(490		)
Total impact on purchased gas cost	—			(146		)	(146		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(444		)	—			(444		)
Total Impact from Cash Flow Hedges	$	(444	)	$	(146	)	$	(590	)

	Three Months Ended December 31, 2013
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(2,609	)	$	(2,609	)
Loss arising from ineffective portion of commodity contracts	—			(119		)	(119		)
Total impact on purchased gas cost	—			(2,728		)	(2,728		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(1,058		)	—			(1,058		)
Total Impact from Cash Flow Hedges	$	(1,058	)	$	(2,728	)	$	(3,786	)

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The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three months ended December 31, 2014 and 2013. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.

	Three Months Ended   December 31
	2014			2013
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(52,069	)	$	13,270
Forward commodity contracts	(28,742		)	6,226
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	282			672
Forward commodity contracts	(210		)	1,592
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(80,739	)	$	21,760

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

Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred gains (losses) associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2014. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
Next twelve months	$	(347	)	$	(25,704	)	$	(26,051	)
Thereafter	(18,563		)	(4,922		)	(23,485		)
Total(1)	$	(18,910	)	$	(30,626	)	$	(49,536	)

⁽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 December 31, 2014 and 2013 was an increase (decrease) in gross profit of $0.9 million and $(0.8) 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 regulated distribution segment are not designated as hedges. However, there is no earnings impact on our regulated 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.

9.    Accumulated Other Comprehensive Income

We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.

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	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2014	$	7,662		$	(18,381	)	$	(1,674	)	$	(12,393	)
Other comprehensive income (loss) before reclassifications	(1,063		)	(52,069		)	(28,742		)	(81,874		)
Amounts reclassified from accumulated other comprehensive income	(4		)	282			(210		)	68
Net current-period other comprehensive income (loss)	(1,067		)	(51,787		)	(28,952		)	(81,806		)
December 31, 2014	$	6,595		$	(70,168	)	$	(30,626	)	$	(94,199	)

	Available- for-Sale Securities		Interest Rate Agreement Cash Flow Hedges		Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2013	$	5,448	$	37,906	$	(4,476	)	$	38,878
Other comprehensive income (loss) before reclassifications	2,394		13,270		6,226			21,890
Amounts reclassified from accumulated other comprehensive income	—		672		1,592			2,264
Net current-period other comprehensive income (loss)	2,394		13,942		7,818			24,154
December 31, 2013	$	7,842	$	51,848	$	3,342		$	63,032

The following tables detail reclassifications out of AOCI for the three months ended December 31, 2014 and 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.

	Three Months Ended December 31, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	6		Operation and maintenance expense
	6			Total before tax
	(2		)	Tax expense
	$	4		Net of tax
Cash flow hedges
Interest rate agreements	$	(444	)	Interest charges
Commodity contracts	344			Purchased gas cost
	(100		)	Total before tax
	28			Tax benefit
	$	(72	)	Net of tax
Total reclassifications	$	(68	)	Net of tax

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	Three Months Ended December 31, 2013
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Cash flow hedges
Interest rate agreements	$	(1,058	)	Interest charges
Commodity contracts	(2,609		)	Purchased gas cost
	(3,667		)	Total before tax
	1,403			Tax benefit
Total reclassifications	$	(2,264	)	Net of tax

10.    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, 2014. During the three months ended December 31, 2014, 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 6 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2014.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data is 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 December 31, 2014 and September 30, 2014. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

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	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(2)			December 31, 2014
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	976	$	—	$	—		$	976
Nonregulated segment	14		228,472		—		(211,084		)	17,402
Total financial instruments	14		229,448		—		(211,084		)	18,378
Hedged portion of gas stored underground	49,800		—		—		—			49,800
Available-for-sale securities
Money market funds	—		1,184		—		—			1,184
Registered investment companies	45,060		—		—		—			45,060
Bonds	—		33,548		—		—			33,548
Total available-for-sale securities	45,060		34,732		—		—			79,792
Total assets	$	94,874	$	264,180	$	—	$	(211,084	)	$	147,970
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	95,824	$	—	$	—		$	95,824
Nonregulated segment	13		254,572		—		(254,585		)	—
Total liabilities	$	13	$	350,396	$	—	$	(254,585	)	$	95,824

	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, 2014
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	36,140	$	—	$	—		$	36,140
Nonregulated segment	25		68,998		—		(46,298		)	22,725
Total financial instruments	25		105,138		—		(46,298		)	58,865
Hedged portion of gas stored underground	40,492		—		—		—			40,492
Available-for-sale securities
Money market funds	—		2,185		—		—			2,185
Registered investment companies	44,014		—		—		—			44,014
Bonds	—		33,414		—		—			33,414
Total available-for-sale securities	44,014		35,599		—		—			79,613
Total assets	$	84,531	$	140,737	$	—	$	(46,298	)	$	178,970
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	21,856	$	—	$	—		$	21,856
Nonregulated segment	12		72,044		—		(72,056		)	—
Total liabilities	$	12	$	93,900	$	—	$	(72,056	)	$	21,856

⁽¹⁾  Our Level 2 measurements consist of over-the-counter options and swaps which are valued 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, municipal and corporate bonds which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

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⁽²⁾  This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of December 31, 2014, we had $43.5 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $26.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $17.4 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, 2014 we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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

	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of December 31, 2014
Domestic equity mutual funds	$	29,231	$	8,956	$	(101	)	$	38,086
Foreign equity mutual funds	5,512		1,462		—			6,974
Bonds	33,474		110		(36		)	33,548
Money market funds	1,184		—		—			1,184
	$	69,401	$	10,528	$	(137	)	$	79,792
As of September 30, 2014
Domestic equity mutual funds	$	26,633	$	10,136	$	—		$	36,769
Foreign equity mutual funds	5,382		1,863		—			7,245
Bonds	33,266		161		(13		)	33,414
Money market funds	2,185		—		—			2,185
	$	67,466	$	12,160	$	(13	)	$	79,613

At December 31, 2014 and September 30, 2014, our available-for-sale securities included $46.2 million and $46.2 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2014, we maintained investments in bonds that have contractual maturity dates ranging from January 2015 through September 2020.

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.

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, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of December 31, 2014 and September 30, 2014:

	December 31, 2014		September 30, 2014
	(In thousands)
Carrying Amount	$	2,460,000	$	2,460,000
Fair Value	$	2,817,435	$	2,769,541

11.    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, 2014. During the three months ended December 31, 2014, there were no material changes in our concentration of credit risk.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of December 31, 2014, the related condensed consolidated statements of income and comprehensive income for the three-month periods ended December 31, 2014 and 2013, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2014 and 2013. 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, 2014, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 6, 2014, 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, 2014, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/    ERNST & YOUNG LLP

Dallas, Texas

February 3, 2015

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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, 2014.

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; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our gas distribution business; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; 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 threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; the risks of accidents and additional operating costs associating with distributing, transporting and storing natural gas; 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 distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers throughout our six regulated distribution divisions, which at December 31, 2014 covered service areas located in eight states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems.

Through our nonregulated businesses, we 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 regulated distribution divisions and to third parties.

As discussed in Note 3, we operate the Company through the following three segments:

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

• the regulated pipeline 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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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, 2014 and include the following:

• Regulation

• Unbilled revenue

• Pension and other postretirement plans

• Contingencies

• Financial instruments and hedging activities

• Fair value measurements

• Impairment assessments

Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the three months ended December 31, 2014.

RESULTS OF OPERATIONS

Executive Summary

Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. To achieve this objective, we are investing in our infrastructure and seeking to achieve positive rate outcomes that benefit both our customers and the Company.

During the first three months of fiscal 2015, we earned $97.6 million, or $0.96 per diluted share, a 12 percent increase over the first quarter of fiscal 2014. The increase primarily reflects the positive impact of rate increases received in our regulated operations during fiscal 2014. As of December 31, 2014, we had completed three regulatory proceedings in our regulated segments resulting in a $5.3 million increase in annual operating income and had seven ratemaking efforts in progress seeking $54.1 million of additional annual operating income.

Capital expenditures for the first quarter of fiscal 2015 were $261.3 million. Approximately 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, and a significant portion of this investment was incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between $900 million and $1 billion for fiscal 2015, and we plan to fund our growth through the use of operating cash flows and debt and equity securities, while maintaining a balanced capital structure.

As a result of the continued contribution and stability of our regulated earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 5.4 percent in the first quarter of fiscal 2015.

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Consolidated Results

The following table presents our consolidated financial highlights for the three months ended December 31, 2014 and 2013:

	Three Months Ended   December 31
	2014			2013
	(In thousands, except per share data)
Operating revenues	$	1,258,765		$	1,243,858
Gross profit	423,285			388,957
Operating expenses	235,560			218,237
Operating income	187,725			170,720
Miscellaneous expense	(1,707		)	(2,132		)
Interest charges	29,764			32,115
Income before income taxes	156,254			136,473
Income tax expense	58,659			49,457
Net income	$	97,595		$	87,016
Diluted net income per share	$	0.96		$	0.95

Our consolidated net income during the three month periods ended December 31, 2014 and 2013 was earned in each of our business segments as follows:

	Three Months Ended December 31
	2014		2013		Change
	(In thousands)
Regulated distribution segment	$	71,387	$	62,757	$	8,630
Regulated pipeline segment	22,035		19,446		2,589
Nonregulated segment	4,173		4,813		(640		)
Net income	$	97,595	$	87,016	$	10,579

Regulated operations represented 96 percent of our consolidated net income for the three months ended December 31, 2014. The following tables reflect the segregation of our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:

	Three Months Ended December 31
	2014		2013		Change
	(In thousands, except per share data)
Regulated operations	$	93,422	$	82,203	$	11,219
Nonregulated operations	4,173		4,813		(640		)
Net income	$	97,595	$	87,016	$	10,579
Diluted EPS from regulated operations	$	0.92	$	0.90	$	0.02
Diluted EPS from nonregulated operations	0.04		0.05		(0.01		)
Consolidated diluted EPS	$	0.96	$	0.95	$	0.01

Regulated Distribution Segment

The primary factors that impact the results of our regulated 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.

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Seasonal weather patterns can also affect our regulated distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 97 percent of our residential and commercial meters in the following states for the following time periods:

Kansas, West Texas	October — May
Tennessee	October — April
Kentucky, Mississippi, Mid-Tex	November — April
Louisiana	December — March
Virginia	January — December

Our regulated 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 does include 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.

As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which 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. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.

Three Months Ended December 31, 2014 compared with Three Months Ended December 31, 2013

Financial and operational highlights for our regulated distribution segment for the three months ended December 31, 2014 and 2013 are presented below.

	Three Months Ended December 31
	2014			2013			Change
	(In thousands, unless otherwise noted)
Gross profit	$	323,812		$	299,171		$	24,641
Operating expenses	185,715			176,298			9,417
Operating income	138,097			122,873			15,224
Miscellaneous expense	(1,329		)	(471		)	(858		)
Interest charges	21,640			23,325			(1,685		)
Income before income taxes	115,128			99,077			16,051
Income tax expense	43,741			36,320			7,421
Net income	$	71,387		$	62,757		$	8,630
Consolidated regulated distribution sales volumes — MMcf	86,922			98,278			(11,356		)
Consolidated regulated distribution transportation volumes — MMcf	36,512			32,207			4,305
Total consolidated regulated distribution throughput — MMcf	123,434			130,485			(7,051		)
Consolidated regulated distribution average transportation revenue per Mcf	$	0.49		$	0.48		$	0.01
Consolidated regulated distribution average cost of gas per Mcf sold	$	6.02		$	5.54		$	0.48

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Income for our regulated distribution segment increased 14 percent, primarily due to an $24.6 million increase in gross profit, partially offset by a $9.4 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:

• a $19.3 million net increase in rate adjustments, primarily in our Mid-Tex, West Texas and Kentucky Divisions.

• a $2.9 million increase in revenue-related taxes in our Mid-Tex and West Texas Divisions, offset by a corresponding $2.8 million increase in the related tax expense.

• a $2.1 million increase in transportation revenue.  Transportation volumes increased 13 percent due to increased economic activity primarily in our West Texas and Kentucky/Mid-States Divisions.

• a $1.8 million increase in service fees attributable to customer reconnection and installment plan revenues.

• a $2.0 million decrease in consumption.  Current quarter weather approximated normal conditions and was 14 percent warmer than the prior-year quarter.  As a result, sales volumes decreased 12 percent.

The increase in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to increased depreciation expense associated with increased capital investments and increased taxes, other than income, primarily due to increases in ad valorem and franchise taxes. These increases were partially offset by lower operation and maintenance expense, largely due to decreased legal costs.

The following table shows our operating income by regulated distribution division, in order of total rate base, for the three months ended December 31, 2014 and 2013. The presentation of our regulated distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	Three Months Ended December 31
	2014		2013		Change
	(In thousands)
Mid-Tex	$	59,114	$	57,104	$	2,010
Kentucky/Mid-States	19,796		18,097		1,699
Louisiana	16,725		17,426		(701		)
West Texas	11,098		8,042		3,056
Mississippi	14,299		12,418		1,881
Colorado-Kansas	9,989		8,813		1,176
Other	7,076		973		6,103
Total	$	138,097	$	122,873	$	15,224

Recent Ratemaking Developments

The amounts described in the following sections 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. During the first three months of fiscal 2015, we completed three regulatory proceedings, resulting in a $5.3 million increase in annual operating income as summarized below:

Rate Action	Annual Increase  to Operating Income
	(In thousands)
Infrastructure programs	$	4,515
Annual rate filing mechanisms	782
Rate case filings	—
Other rate activity	—
	$	5,297

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Additionally, the following ratemaking efforts seeking $54.1 million in annual operating income were in progress as of December 31, 2014:

Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Ad Valorem(1)	Kansas	$	78
Colorado-Kansas	GSRS(2)	Kansas	403
Louisiana	Rate Stabilization Clause	Trans LA	473
Kentucky/Mid-States	Rate Case	Tennessee	5,889
Mid-Tex	Rate Review Mechanism(3)	Mid-Tex Cities	33,415
Mississippi	Stable Rate Filing(4)	Mississippi	8,922
West Texas	Rate Review Mechanism	WT Cities	4,969
			$	54,149

⁽¹⁾  The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service

area’s base rates. The commission issued a final order on January 6, 2015 approving our requested operating income increase.

⁽²⁾    The Gas System Reliability Surcharge (GSRS) filing relates to a collection of qualified infrastructure in Kansas. The

Commission issued an order on January 27, 2015, approving an increase of $0.3 million.

⁽³⁾  Mid-Tex Cities RRM rates were put into effect on June 1, 2014, subject to refund. The Company appealed the Mid-Tex Cities decision to deny the 2013 RRM increase to the Texas Railroad Commission on May 30, 2014. A proposal for decision is expected in February 2015.

⁽⁴⁾  The commission issued a final order on February 3, 2015 approving a $4.4 million increase in annual operating income.

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. As of December 31, 2014, we had infrastructure programs approved in Kansas, Kentucky, Louisiana, Texas and Virginia. The following table summarizes our infrastructure program filings with effective dates occurring during the three months ended December 31, 2014.

Division	Period End	Incremental Net Utility Plant Investment		Increase in Annual Operating Income		Effective Date
		(In thousands)		(In thousands)
2015 Infrastructure Programs:
Kentucky/Mid-States - Kentucky	09/30/2015	$	35,382	$	4,382	10/10/2014
Kentucky/Mid-States - Virginia	09/30/2015	1,553		133		10/01/2014
Total 2015 Infrastructure Programs		$	36,935	$	4,515

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. As of December 31, 2014, we had annual rate filing mechanisms in our Louisiana and Mississippi service areas and in a portion of our Texas divisions. These mechanisms are referred to as the Dallas annual rate review (DARR) and rate review mechanism (RRM) in our Mid-Tex Division, as the RRM in our West Texas Division, stable rate/supplemental growth filings in the Mississippi Division and the rate stabilization clause in the Louisiana Division. One annual rate filing mechanism was completed during the three months ended December 31, 2014.

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Division	Jurisdiction	Test Year Ended	Additional Annual Operating Income		Effective Date
		(In thousands)
2015 Filings:
Mississippi	Mississippi-SGR (1)	10/31/15	$	782	11/01/2014
Total 2015 Filings			$	782

⁽¹⁾The Mississippi Supplemental Growth Rider (SGR) permits the Company to pursue up to $5.0 million of eligible industrial growth projects beyond the division’s normal main extension policies. This is the second year of the SGR program.Regulated Pipeline Segment

Our regulated pipeline segment consists of the 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 to third parties customary in the pipeline industry including parking arrangements, lending arrangements and sales of excess gas.

Our regulated pipeline segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Mid-Tex service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve could influence customers to transport gas through our pipeline to capture arbitrage gains.

The results of Atmos Pipeline — Texas Division are also significantly impacted by the natural gas requirements of the Mid-Tex Division because it is the primary supplier of natural gas for our Mid-Tex Division.

Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Three Months Ended December 31, 2014 compared with Three Months Ended December 31, 2013

Financial and operational highlights for our regulated pipeline segment for the three months ended December 31, 2014 and 2013 are presented below.

	Three Months Ended December 31
	2014			2013			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	60,079		$	49,744		$	10,335
Third-party transportation	20,394			17,159			3,235
Storage and park and lend services	1,004			1,821			(817		)
Other	2,090			2,617			(527		)
Gross profit	83,567			71,341			12,226
Operating expenses	40,862			31,749			9,113
Operating income	42,705			39,592			3,113
Miscellaneous expense	(252		)	(1,181		)	929
Interest charges	8,324			8,957			(633		)
Income before income taxes	34,129			29,454			4,675
Income tax expense	12,094			10,008			2,086
Net income	$	22,035		$	19,446		$	2,589
Gross pipeline transportation volumes — MMcf	181,362			189,176			(7,814		)
Consolidated pipeline transportation volumes — MMcf	120,634			118,774			1,860

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Net income for our regulated pipeline segment increased 13 percent, primarily due to a $12.2 million increase in gross profit, partially offset by an $9.1 million increase in operating expenses. The increase in gross profit primarily reflects a $12.5 million increase in rates from the approved 2014 GRIP filing. Additionally, gross profit reflects increased pipeline demand fees and transportation rates that were offset by lower park and lend, storage and blending fees, and the absence of a $1.8 million increase recorded in the prior-year quarter associated with the renewal of an annual adjustment mechanism.

Operating expenses increased $9.1 million primarily due to increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system and increased depreciation expense associated with increased capital investments.

Nonregulated Segment

Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and, historically, have represented approximately five percent of our consolidated net income.

AEH's primary business is to buy, sell and deliver natural gas at competitive prices to approximately 1,000 customers located primarily in the Midwest and Southeast areas of the United States. AEH accomplishes this objective by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.

AEH also earns storage and transportation demand fees primarily from our regulated distribution operations in Louisiana and Kentucky. These demand fees are subject to regulatory oversight and are renewed periodically.

Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of buying, selling and delivering natural gas to offer more competitive pricing to those customers.

Natural gas prices can influence:

• The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources.

Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy

sources to natural gas.

• The collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment and

• The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this

segment.

Natural gas price volatility can also influence our nonregulated business in the following ways:

• Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost

alternative among the natural gas supplies, transportation and markets to which we have access.

• Increased or decreased volatility impacts the amounts of unrealized margins recorded in our gross profit and could

impact the amount of cash required to collateralize our risk management liabilities.

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 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. 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 December 31, 2014 compared with Three Months Ended December 31, 2013

Financial and operating highlights for our nonregulated segment for the three months ended December 31, 2014 and 2013 are presented below.

	Three Months Ended December 31
	2014			2013			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	10,759		$	12,463		$	(1,704	)
Storage and transportation services	3,313			3,535			(222		)
Other	(5,831		)	(8,002		)	2,171
Total realized margins	8,241			7,996			245
Unrealized margins	7,798			10,570			(2,772		)
Gross profit	16,039			18,566			(2,527		)
Operating expenses	9,116			10,311			(1,195		)
Operating income	6,923			8,255			(1,332		)
Miscellaneous income	300			324			(24		)
Interest charges	226			637			(411		)
Income before income taxes	6,997			7,942			(945		)
Income tax expense	2,824			3,129			(305		)
Net income	$	4,173		$	4,813		$	(640	)
Gross nonregulated delivered gas sales volumes — MMcf	108,193			107,579			614
Consolidated nonregulated delivered gas sales volumes — MMcf	90,930			92,637			(1,707		)
Net physical position (Bcf)	17.1			15.5			1.6

The $2.5 million quarter-over-quarter decrease in gross profit reflected a $0.2 million increase in realized margins, combined with a $2.8 million decrease in unrealized margins. The $0.2 million increase in realized margins primarily reflects:

• A $2.2 million increase in other realized margins, primarily due to a reduction in third-party storage fees and the timing and magnitude of settled financial positions quarter over quarter.

• A $1.7 million decrease in gas delivery and related services margins, largely due to a reduction in per unit margins from 12 cents per Mcf in the prior-year quarter to 10 cents, and a two percent decrease in consolidated sales volumes. Both per unit margins and consolidated sales volumes reflect the impact of warmer weather during the current quarter compared to the prior-year period. Additionally, increased transportation costs adversely impacted per-unit margins.

Unrealized margins decreased $2.8 million primarily due to the quarter-over-quarter timing of realized margins on the settlement of hedged natural gas inventory positions.

Operating expenses decreased $1.2 million, primarily due to lower employee-related expenses.

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 capital structure to ensure that we (i) have sufficient liquidity for our short-term and long-term needs in a cost-effective manner and (ii) maintain a balanced capital structure with a debt-to-capitalization ratio in a target range of 50 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of capacity from our short-term facilities.

We plan to fund our growth through the use of operating cash flows, debt and equity securities while maintaining a balanced capital structure. To support our capital market activities, we have a shelf registration statement with the Securities

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and Exchange Commission (SEC) that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. As of December 31, 2014, approximately $845 million of securities remained available for issuance under the shelf registration statement until March 28, 2016.

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of December 31, 2014, September 30, 2014 and December 31, 2013:

	December 31, 2014				September 30, 2014				December 31, 2013
	(In thousands, except percentages)
Short-term debt	$	550,903	9.1	%	$	196,695	3.4	%	$	689,795	11.9	%
Long-term debt	2,455,131		40.4	%	2,455,986		42.8	%	2,455,750		42.3	%
Shareholders’ equity	3,063,925		50.5	%	3,086,232		53.8	%	2,661,314		45.8	%
Total	$	6,069,959	100.0	%	$	5,738,913	100.0	%	$	5,806,859	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 49.5 percent at December 31, 2014, 46.2 percent at September 30, 2014 and 54.2 percent at December 31, 2013.

Cash Flows

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

Cash flows from operating, investing and financing activities for the three months ended December 31, 2014 and 2013 are presented below.

	Three Months Ended December 31
	2014			2013			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	27,415		$	34,300		$	(6,885	)
Investing activities	(262,052		)	(186,434		)	(75,618		)
Financing activities	316,211			280,498			35,713
Change in cash and cash equivalents	81,574			128,364			(46,790		)
Cash and cash equivalents at beginning of period	42,258			66,199			(23,941		)
Cash and cash equivalents at end of period	$	123,832		$	194,563		$	(70,731	)

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 regulated distribution segment resulting from changes in the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the three months ended December 31, 2014, we generated cash flow of $27.4 million from operating activities compared with $34.3 million for the three months ended December 31, 2013. The $6.9 million decrease in operating cash flows primarily reflects the timing of customer collections and vendor payments.

Cash flows from investing activities

In executing our regulatory strategy, we focus our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, substantially all of our regulated distribution divisions and our Atmos Pipeline–Texas Division have rate tariffs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

In recent years, a substantial portion of our cash resources has been used to fund growth projects in our regulated operations, our ongoing construction program and improvements to information technology systems. Over the last two fiscal years, approximately 80 percent of our capital spending has been committed to improving the safety and reliability of our system. Our ongoing construction program enables us to enhance the safety and reliability of the systems used to provide

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regulated 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.

We anticipate our annual capital spending will be in the range of $900 million to $1.1 billion through fiscal 2018 as we continue to invest in the safety and reliability of our distribution and transportation system. Where possible, we will also continue to focus our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system.

For the three months ended December 31, 2014, capital expenditures were $261.3 million, compared with $180.6 million in the prior-year period. The $80.7 million increase primarily reflects:

• A $41.8 million increase in capital spending in our regulated pipeline segment primarily related to the enhancement and fortification of two storage fields to ensure the reliability of gas service to our Mid-Tex Division.

• A $38.7 million increase in capital spending in our regulated distribution segment, which primarily reflects the timing of the spending combined with a planned increase in safety and reliability investment in fiscal 2015.

Cash flows from financing activities

For the three months ended December 31, 2014, our financing activities generated $316.2 million of cash compared with $280.5 million generated in the prior-year period. The $35.7 million increase is primarily due to timing between short-term debt borrowings and repayments during the current year, proceeds from the issuance of $500 million unsecured 4.125% senior notes in October 2014 and the settlement of the associated forward starting interest rate swaps, partially offset by the repayment of $500 million4.95% senior unsecured notes at maturity on October 15, 2014

The following table summarizes our share issuances for the three months ended December 31, 2014 and 2013.

	Three Months Ended   December 31
	2014	2013
Shares issued:
Direct stock purchase plan	60,936	—
1998 Long-Term Incentive Plan	477,649	450,943
Retirement Savings Plan and Trust	75,580	—
Outside Directors Stock-for-Fee Plan	424	473
Total shares issued	614,589	451,416

The year-over-year increase in the number of shares issued primarily reflects the fact that we have begun issuing shares for the Direct Stock Purchase Plan and the Retirement Savings Plan rather than using shares purchased in the open market. For the three months ended December 31, 2014 and 2013, we canceled and retired 148,464 and 133,325 shares attributable to federal income tax withholdings on equity awards.

Credit Facilities

Our short-term borrowing requirements are affected primarily by the seasonal nature of the natural gas business and the level of our capital expenditures. Changes in the price of natural gas, the amount of natural gas we need to supply to meet our customers’ needs and our capital spending activities 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 $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1.3 billion of working capital funding. As of December 31, 2014, the amount available to us under our credit facilities, net of outstanding letters of credit, was $759.3 million.

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 December 31, 2014, S&P and Moody's maintained a stable outlook while Fitch maintained a positive outlook. Our current debt ratings are all considered investment grade and are as follows:

	S&P	Moody’s	Fitch
Senior unsecured long-term debt	A-	A2	A-
Commercial paper	A-2	P-1	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 December 31, 2014. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 7 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the three months ended December 31, 2014.

Risk Management Activities

We conduct risk management activities through our regulated distribution and nonregulated segments. In our regulated 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. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

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.

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The following table shows the components of the change in fair value of our regulated distribution segment’s financial instruments for the three months ended December 31, 2014 and 2013:

	Three Months Ended   December 31
	2014			2013
	(In thousands)
Fair value of contracts at beginning of period	$	14,284		$	109,648
Contracts realized/settled	(23,156		)	(1,671		)
Fair value of new contracts	(365		)	519
Other changes in value	(85,611		)	26,280
Fair value of contracts at end of period	$	(94,848	)	$	134,776

The fair value of our regulated distribution segment’s financial instruments at December 31, 2014 is presented below by time period and fair value source:

	Fair Value of Contracts at December 31, 2014
	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	$	(12,849	)	$	(81,999	)	$	—	$	—	$	(94,848	)
Prices based on models and other valuation methods	—			—			—		—		—
Total Fair Value	$	(12,849	)	$	(81,999	)	$	—	$	—	$	(94,848	)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three months ended December 31, 2014 and 2013:

	Three Months Ended   December 31
	2014			2013
	(In thousands)
Fair value of contracts at beginning of period	$	(3,033	)	$	(14,700	)
Contracts realized/settled	7,165			9,943
Fair value of new contracts	—			—
Other changes in value	(30,231		)	(336		)
Fair value of contracts at end of period	(26,099		)	(5,093		)
Netting of cash collateral	43,501			16,708
Cash collateral and fair value of contracts at period end	$	17,402		$	11,615

The fair value of our nonregulated segment’s financial instruments at December 31, 2014 is presented below by time period and fair value source:

	Fair Value of Contracts at December 31, 2014
	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	$	(20,363	)	$	(6,128	)	$	392	$	—	$	(26,099	)
Prices based on models and other valuation methods	—			—			—		—		—
Total Fair Value	$	(20,363	)	$	(6,128	)	$	392	$	—	$	(26,099	)

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Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2014 and 2013, our total net periodic pension and other benefits costs were $14.7 million and $20.9 million. A substantial portion of those costs relating to our regulated 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 2015 costs were determined using a September 30, 2014 measurement date. As of September 30, 2014, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2013, the measurement date for our fiscal 2014 net periodic cost. Therefore, we decreased the discount rate used to measure our fiscal 2015 net periodic cost from 4.95 percent to 4.43 percent. We maintained our expected return on plan assets at 7.25 percent in the determination of our fiscal 2015 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of changes of these and other assumptions and the absence of a $4.5 million non-recurring settlement loss recorded during the first quarter of fiscal 2014, we expect our fiscal 2015 net periodic pension cost to decrease by approximately 10 percent.

The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. Based upon current market conditions, the current funded position of the plans and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2015. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels. For the three months ended December 31, 2014 we contributed $5.6 million to our postretirement medical plans. We anticipate contributing a total of between $20 million and $25 million to these plans during fiscal 2015.

The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans 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 plans and changes in the demographic composition of the participants in the plans.

In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. We anticipate utilizing the new mortality data in our next actuarial calculation date on September 30, 2015. We are currently evaluating the impact the updated data will have on the valuation of our defined benefit and other post-retirement benefits plans. It is expected the use of this new data will increase the total amount of liabilities reported on our balance sheet in future periods by less than five percent.

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OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our regulated distribution, regulated pipeline and nonregulated segments for the three month periods ended December 31, 2014 and 2013.

Regulated Distribution Sales and Statistical Data

	Three Months Ended   December 31
	2014		2013
METERS IN SERVICE, end of period
Residential	2,862,369		2,782,064
Commercial	261,593		249,348
Industrial	1,538		1,508
Public authority and other	8,451		10,011
Total meters	3,133,951		3,042,931
INVENTORY STORAGE BALANCE — Bcf	53.0		52.5
SALES VOLUMES — MMcf(1)
Gas sales volumes
Residential	52,218		60,416
Commercial	28,715		31,414
Industrial	3,890		4,019
Public authority and other	2,099		2,429
Total gas sales volumes	86,922		98,278
Transportation volumes	38,835		35,424
Total throughput	125,757		133,702
OPERATING REVENUES (000’s)(1)
Gas sales revenues
Residential	$	541,725	$	545,417
Commercial	241,630		235,423
Industrial	22,911		23,748
Public authority and other	14,998		16,449
Total gas sales revenues	821,264		821,037
Transportation revenues	19,152		16,817
Other gas revenues	6,356		6,011
Total operating revenues	$	846,772	$	843,865
Average transportation revenue per Mcf	$	0.49	$	0.47
Average cost of gas per Mcf sold	$	6.02	$	5.54

See footnote following these tables.

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Regulated Pipeline and Nonregulated Operations Sales and Statistical Data

	Three Months Ended   December 31
	2014		2013
CUSTOMERS, end of period
Industrial	747		758
Municipal	129		126
Other	539		546
Total	1,415		1,430
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf	21.6		21.1
REGULATED PIPELINE VOLUMES — MMcf(1)	181,362		189,176
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf(1)	108,193		107,579
OPERATING REVENUES (000’s)(1)
Regulated pipeline	$	83,567	$	71,341
Nonregulated	462,288		436,431
Total operating revenues	$	545,855	$	507,772

Note to preceding tables:

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

RECENT ACCOUNTING DEVELOPMENTS

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the three months ended December 31, 2014, 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 December 31, 2014 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter of the fiscal year ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

During the three months ended December 31, 2014, except as noted in Note 7 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 10 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

Item 6. Exhibits

A list of exhibits required by Item 601 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/    BRETJ. ECKERT

Bret J. Eckert

Senior Vice President and Chief Financial Officer

(Duly authorized signatory)

Date: February 3, 2015

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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.

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