Edgar Filing: ATMOS ENERGY CORP

10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



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

For the quarterly period ended December 31, 2015



¨	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 29, 2016.



Class		Shares Outstanding
No Par Value		102,106,896

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

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS



	December 31, 2015			September 30, 2015
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	9,502,944		$	9,240,100
Less accumulated depreciation and amortization	1,849,657			1,809,520
Net property, plant and equipment	7,653,287			7,430,580
Current assets
Cash and cash equivalents	78,903			28,653
Accounts receivable, net	456,904			295,160
Gas stored underground	236,017			236,603
Other current assets	91,446			70,569
Total current assets	863,270			630,985
Goodwill	742,702			742,702
Deferred charges and other assets	295,394			288,678
	$	9,554,653		$	9,092,945
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, 2015 — 102,079,316 shares; September 30, 2015 — 101,478,818 shares	$	510		$	507
Additional paid-in capital	2,242,307			2,230,591
Accumulated other comprehensive loss	(102,962		)	(109,330		)
Retained earnings	1,132,254			1,073,029
Shareholders’ equity	3,272,109			3,194,797
Long-term debt	2,455,474			2,455,388
Total capitalization	5,727,583			5,650,185
Current liabilities
Accounts payable and accrued liabilities	280,487			238,942
Other current liabilities	471,333			457,954
Short-term debt	763,236			457,927
Total current liabilities	1,515,056			1,154,823
Deferred income taxes	1,441,325			1,411,315
Regulatory cost of removal obligation	425,555			427,553
Pension and postretirement liabilities	289,939			287,373
Deferred credits and other liabilities	155,195			161,696
	$	9,554,653		$	9,092,945

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended December 31
	2015			2014
	(Unaudited) (In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	638,602		$	846,772
Regulated pipeline segment	94,677			83,567
Nonregulated segment	272,524			462,288
Intersegment eliminations	(99,582		)	(133,862		)
	906,221			1,258,765
Purchased gas cost
Regulated distribution segment	305,141			522,960
Regulated pipeline segment	—			—
Nonregulated segment	256,766			446,249
Intersegment eliminations	(99,449		)	(133,729		)
	462,458			835,480
Gross profit	443,763			423,285
Operating expenses
Operation and maintenance	124,848			118,582
Depreciation and amortization	71,239			67,593
Taxes, other than income	51,471			49,385
Total operating expenses	247,558			235,560
Operating income	196,205			187,725
Miscellaneous expense	(1,209		)	(1,707		)
Interest charges	30,483			29,764
Income before income taxes	164,513			156,254
Income tax expense	61,652			58,659
Net income	$	102,861		$	97,595
Basic and diluted net income per share	$	1.00		$	0.96
Cash dividends per share	$	0.42		$	0.39
Basic and diluted weighted average shares outstanding	102,713			101,581

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended December 31
	2015			2014
	(Unaudited) (In thousands)
Net income	$	102,861		$	97,595
Other comprehensive income (loss), net of tax
Net unrealized holding losses on available-for-sale securities, net of tax of $442 and $613	(768		)	(1,067		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $2,749 and $(29,768)	4,783			(51,787		)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $1,505 and $(18,696)	2,353			(28,952		)
Total other comprehensive income (loss)	6,368			(81,806		)
Total comprehensive income	$	109,229		$	15,789

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Three Months Ended December 31
	2015			2014
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	102,861		$	97,595
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization	71,239			67,593
Charged to other accounts	326			275
Deferred income taxes	59,299			55,418
Other	4,407			4,889
Net assets / liabilities from risk management activities	(7,495		)	(20,828		)
Net change in operating assets and liabilities	(160,144		)	(177,527		)
Net cash provided by operating activities	70,493			27,415
Cash Flows From Investing Activities
Capital expenditures	(291,674		)	(261,313		)
Other, net	1,029			(739		)
Net cash used in investing activities	(290,645		)	(262,052		)
Cash Flows From Financing Activities
Net increase in short-term debt	305,309			350,574
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	(43,636		)	(39,592		)
Repurchase of equity awards	—			(7,985		)
Issuance of common stock	8,729			6,312
Net cash provided by financing activities	270,402			316,211
Net increase in cash and cash equivalents	50,250			81,574
Cash and cash equivalents at beginning of period	28,653			42,258
Cash and cash equivalents at end of period	$	78,903		$	123,832

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2015

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, 2015, 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, 2015. 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, 2015. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2015 are not indicative of our results of operations for the full 2016 fiscal year, which ends September 30, 2016.

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, 2015.

In May 2014, the Financial Accounting Standards Board (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, 2018 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 effect on our financial position, results of operations and cash flows, as well as the transition approach we will select.

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new standard will be effective for us beginning on October 1, 2016, and will be applied retrospectively. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

In November 2015, the FASB issued guidance that requires all deferred income tax liabilities and assets to be presented as noncurrent in a classified balance sheet. Currently, entities are required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. The new standard will become effective for us beginning on October 1, 2017, with the option to early adopt, and can be applied either prospectively or retrospectively. The adoption of this

guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent will affect the presentation of our balance sheet.

Regulatory assets and liabilities

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

Significant regulatory assets and liabilities as of December 31, 2015 and September 30, 2015 included the following:



	December 31, 2015		September 30, 2015
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	116,485	$	121,183
Infrastructure mechanisms⁽²⁾	43,385		32,813
Deferred gas costs	16,310		9,715
Recoverable loss on reacquired debt	15,680		16,319
APT annual adjustment mechanism	—		1,002
Rate case costs	1,568		1,533
Other	11,878		9,774
	$	205,306	$	192,339
Regulatory liabilities:
Regulatory cost of removal obligation	$	482,544	$	483,676
Deferred gas costs	32,895		28,100
Asset retirement obligation	9,063		9,063
APT annual adjustment mechanism	1,721		—
Other	3,415		3,693
	$	529,638	$	524,532


⁽¹⁾	Includes $14.3 million and $16.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.


⁽²⁾	Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

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, 2015. We evaluate performance based on net income or loss of the respective operating units.

Income statements for the three month periods ended December 31, 2015 and 2014 by segment are presented in the following tables:



	Three Months Ended December 31, 2015
	Regulated Distribution			Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	637,167		$	23,407		$	245,647		$	—		$	906,221
Intersegment revenues	1,435			71,270			26,877			(99,582		)	—
	638,602			94,677			272,524			(99,582		)	906,221
Purchased gas cost	305,141			—			256,766			(99,449		)	462,458
Gross profit	333,461			94,677			15,758			(133		)	443,763
Operating expenses
Operation and maintenance	91,349			27,088			6,544			(133		)	124,848
Depreciation and amortization	57,334			12,770			1,135			—			71,239
Taxes, other than income	45,261			5,571			639			—			51,471
Total operating expenses	193,944			45,429			8,318			(133		)	247,558
Operating income	139,517			49,248			7,440			—			196,205
Miscellaneous income (expense)	(752		)	(429		)	379			(407		)	(1,209		)
Interest charges	20,705			9,147			1,038			(407		)	30,483
Income before income taxes	118,060			39,672			6,781			—			164,513
Income tax expense	44,805			14,086			2,761			—			61,652
Net income	$	73,255		$	25,586		$	4,020		$	—		$	102,861
Capital expenditures	$	166,544		$	125,283		$	(153	)	$	—		$	291,674



	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

Balance sheet information at December 31, 2015 and September 30, 2015 by segment is presented in the following tables:



	December 31, 2015
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,779,479	$	1,821,114	$	52,694		$	—		$	7,653,287
Investment in subsidiaries	1,020,629		—		—			(1,020,629		)	—
Current assets
Cash and cash equivalents	57,691		—		21,212			—			78,903
Assets from risk management activities	716		—		18,229			—			18,945
Other current assets	589,257		20,008		420,897			(264,740		)	765,422
Intercompany receivables	943,005		—		—			(943,005		)	—
Total current assets	1,590,669		20,008		460,338			(1,207,745		)	863,270
Goodwill	575,449		132,542		34,711			—			742,702
Noncurrent assets from risk management activities	96		—		—			—			96
Deferred charges and other assets	277,662		17,095		541			—			295,298
	$	9,243,984	$	1,990,759	$	548,284		$	(2,228,374	)	$	9,554,653
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,272,109	$	602,861	$	417,768		$	(1,020,629	)	$	3,272,109
Long-term debt	2,455,474		—		—			—			2,455,474
Total capitalization	5,727,583		602,861		417,768			(1,020,629		)	5,727,583
Current liabilities
Short-term debt	1,017,236		—		—			(254,000		)	763,236
Liabilities from risk management activities	6,738		—		—			—			6,738
Other current liabilities	625,055		28,197		102,570			(10,740		)	745,082
Intercompany payables	—		923,366		19,639			(943,005		)	—
Total current liabilities	1,649,029		951,563		122,209			(1,207,745		)	1,515,056
Deferred income taxes	1,008,353		434,497		(1,525		)	—			1,441,325
Noncurrent liabilities from risk management activities	103,337		—		—			—			103,337
Regulatory cost of removal obligation	425,555		—		—			—			425,555
Pension and postretirement liabilities	289,939		—		—			—			289,939
Deferred credits and other liabilities	40,188		1,838		9,832			—			51,858
	$	9,243,984	$	1,990,759	$	548,284		$	(2,228,374	)	$	9,554,653



	September 30, 2015
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,670,306	$	1,706,449	$	53,825		$	—		$	7,430,580
Investment in subsidiaries	1,038,670		—		(2,096		)	(1,036,574		)	—
Current assets
Cash and cash equivalents	23,863		—		4,790			—			28,653
Assets from risk management activities	378		—		8,854			—			9,232
Other current assets	426,270		24,628		480,503			(338,301		)	593,100
Intercompany receivables	887,713		—		—			(887,713		)	—
Total current assets	1,338,224		24,628		494,147			(1,226,014		)	630,985
Goodwill	575,449		132,542		34,711			—			742,702
Noncurrent assets from risk management activities	368		—		—			—			368
Deferred charges and other assets	265,693		17,288		5,329			—			288,310
	$	8,888,710	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,092,945
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,194,797	$	577,275	$	461,395		$	(1,038,670	)	$	3,194,797
Long-term debt	2,455,388		—		—			—			2,455,388
Total capitalization	5,650,185		577,275		461,395			(1,038,670		)	5,650,185
Current liabilities
Short-term debt	782,927		—		—			(325,000		)	457,927
Liabilities from risk management activities	9,568		—		—			—			9,568
Other current liabilities	569,273		29,780		99,480			(11,205		)	687,328
Intercompany payables	—		867,409		20,304			(887,713		)	—
Total current liabilities	1,361,768		897,189		119,784			(1,223,918		)	1,154,823
Deferred income taxes	1,008,091		406,254		(3,030		)	—			1,411,315
Noncurrent liabilities from risk management activities	110,539		—		—			—			110,539
Regulatory cost of removal obligation	427,553		—		—			—			427,553
Pension and postretirement liabilities	287,373		—		—			—			287,373
Deferred credits and other liabilities	43,201		189		7,767			—			51,157
	$	8,888,710	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,092,945

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, 2015 and 2014 are calculated as follows:



	Three Months Ended December 31
	2015		2014
	(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share
Net income	$	102,861	$	97,595
Less: Income allocated to participating securities	172		216
Income available to common shareholders	$	102,689	$	97,379
Basic and diluted weighted average shares outstanding	102,713		101,581
Net income per share - Basic and Diluted	$	1.00	$	0.96

2011 Share Repurchase Program

We did not repurchase any shares during the three months ended December 31, 2015 and 2014 under our 2011 share repurchase program, which is scheduled to end on September 30, 2016.

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, 2015. Except as noted below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2015.

Long-term debt

Long-term debt at December 31, 2015 and September 30, 2015 consisted of the following:



	December 31, 2015		September 30, 2015
	(In thousands)
Unsecured 6.35% Senior Notes, due June 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		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	4,526		4,612
	$	2,455,474	$	2,455,388

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 million 4.95% 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, 2015 and September 30, 2015 a total of $763.2 million and $457.9 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, 2015.

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 (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million bilateral credit facility and one committed $15 million bilateral credit facility that were renewed and extended in December 2015. The uncommitted $25 million bilateral credit facility currently expires in March 2016 and the $15 million bilateral credit facility expires in September 2016. 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 $36.2 million at December 31, 2015.

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. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016.

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, 2015, $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, 2015, 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, 2015. 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, 2015 and 2014 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.



	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2015			2014			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,698		$	5,051		$	2,706		$	3,896
Interest cost	7,095			6,699			3,106			3,596
Expected return on assets	(6,881		)	(6,436		)	(1,566		)	(1,608		)
Amortization of transition obligation	—			—			21			68
Amortization of prior service credit	(57		)	(49		)	(411		)	(411		)
Amortization of actuarial loss	3,320			3,917			(542		)	—
Net periodic pension cost	$	8,175		$	9,182		$	3,314		$	5,541

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2015 and 2014 are as follows:



	Pension Benefits				Other Benefits
	2015		2014		2015		2014
Discount rate	4.55	%	4.43	%	4.55	%	4.43	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected return on plan assets	7.00	%	7.25	%	4.45	%	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, 2016. Based on that determination, we are not required to make a minimum contribution to our defined benefit plans during the first quarter of fiscal 2016, nor do we anticipate making a contribution during the remainder of the fiscal year.

We contributed $5.5 million to our other post-retirement benefit plans during the three months ended December 31, 2015. We expect to contribute between $15 million and $25 million to these plans during fiscal 2016.

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, 2015, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2015.

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.

Purchase Commitments

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. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. There were no material changes to the purchase commitments for the three months ended December 31, 2015.

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. Except for purchases made in the normal course of business under these contracts, there were no material changes to the purchase commitments for the three months ended December 31, 2015.

Our nonregulated segment maintains long-term contracts related to storage and transportation. These 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, 2015. There were no material changes to the estimated storage and transportation fees for the three months ended December 31, 2015.

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, 2015, rate cases were in progress in our Colorado, Kansas and Kentucky service areas and formula rate filing mechanisms were in progress in Colorado, Kansas, Louisiana and West Texas. 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 nonregulated 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, 2015. During the three months ended December 31, 2015 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 2015-2016 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 33 percent, or 23.0 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 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, 2015, 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 swaps were executed. As of December 31, 2015, we had $18.6 million of 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 extend 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, 2015, 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, 2015, 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	—	(23,528	)
	Cash Flow	—	63,305
	Not designated	11,792	51,663
		11,792	91,440

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, 2015 and September 30, 2015. 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, 2015
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	24,704		$	(38,275	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			432			(8,821		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(103,142		)	—			—
Total		—		(103,142		)	25,136			(47,096		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	716		(6,738		)	41,780			(42,232		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	96		(195		)	17,577			(16,184		)
Total		812		(6,933		)	59,357			(58,416		)
Gross Financial Instruments		812		(110,075		)	84,493			(105,512		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(84,493		)	84,493
Net Financial Instruments		812		(110,075		)	—			(21,019		)
Cash collateral		—		—			18,229			21,019
Net Assets/Liabilities from Risk Management Activities		$	812	$	(110,075	)	$	18,229		$	—



		Regulated Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
September 30, 2015
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	11,680		$	(36,067	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			126			(9,918		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(110,539		)	—			—
Total		—		(110,539		)	11,806			(45,985		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	378		(9,568		)	65,239			(65,780		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	368		—			14,318			(14,218		)
Total		746		(9,568		)	79,557			(79,998		)
Gross Financial Instruments		746		(120,107		)	91,363			(125,983		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(91,363		)	91,363
Net Financial Instruments		746		(120,107		)	—			(34,620		)
Cash collateral		—		—			8,854			34,620
Net Assets/Liabilities from Risk Management Activities		$	746	$	(120,107	)	$	8,854		$	—

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of purchased gas cost 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, 2015 and 2014 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $7.9 million and $(2.2) million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2015 and 2014 is presented below.



	Three Months Ended December 31
	2015		2014
	(In thousands)
Commodity contracts	$	5,744	$	15,090
Fair value adjustment for natural gas inventory designated as the hedged item	2,161		(16,782		)
Total (increase) decrease in purchased gas cost	$	7,905	$	(1,692	)
The (increase) decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	1,289	$	986
Timing ineffectiveness	6,616		(2,678		)
	$	7,905	$	(1,692	)

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, 2015 and 2014 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, 2015
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(22,965	)	$	(22,965	)
Loss arising from ineffective portion of commodity contracts	—			(43		)	(43		)
Total impact on purchased gas cost	—			(23,008		)	(23,008		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(137		)	—			(137		)
Total Impact from Cash Flow Hedges	$	(137	)	$	(23,008	)	$	(23,145	)



	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	)

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, 2015 and 2014. 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
	2015			2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	4,696		$	(52,069	)
Forward commodity contracts	(11,656		)	(28,742		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	87			282
Forward commodity contracts	14,009			(210		)
Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	7,136		$	(80,739	)


⁽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, 2015. 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	)	$	(17,979	)	$	(18,326	)
Thereafter	(18,217		)	(5,105		)	(23,322		)
Total⁽¹⁾	$	(18,564	)	$	(23,084	)	$	(41,648	)


⁽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, 2015 and 2014 was an (increase) decrease in purchased gas cost of $(2.2) million and $0.9 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.



	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2015	$	4,949		$	(88,842	)	$	(25,437	)	$	(109,330	)
Other comprehensive income (loss) before reclassifications	(768		)	4,696			(11,656		)	(7,728		)
Amounts reclassified from accumulated other comprehensive income	—			87			14,009			14,096
Net current-period other comprehensive income (loss)	(768		)	4,783			2,353			6,368
December 31, 2015	$	4,181		$	(84,059	)	$	(23,084	)	$	(102,962	)



	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	)

The following tables detail reclassifications out of AOCI for the three months ended December 31, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.



	Three Months Ended December 31, 2015
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	$	(137	)	Interest charges
Commodity contracts	(22,965		)	Purchased gas cost
	(23,102		)	Total before tax
	9,006			Tax benefit
Total reclassifications	$	(14,096	)	Net of tax



	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

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, 2015. During the three months ended December 31, 2015, 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, 2015.

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, 2015 and September 30, 2015. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.



	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral⁽²⁾			December 31, 2015
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	812	$	—	$	—		$	812
Nonregulated segment	—		84,493		—		(66,264		)	18,229
Total financial instruments	—		85,305		—		(66,264		)	19,041
Hedged portion of gas stored underground	53,347		—		—		—			53,347
Available-for-sale securities
Money market funds	—		72		—		—			72
Registered investment companies	41,978		—		—		—			41,978
Bonds	—		33,129		—		—			33,129
Total available-for-sale securities	41,978		33,201		—		—			75,179
Total assets	$	95,325	$	118,506	$	—	$	(66,264	)	$	147,567
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	110,075	$	—	$	—		$	110,075
Nonregulated segment	—		105,512		—		(105,512		)	—
Total liabilities	$	—	$	215,587	$	—	$	(105,512	)	$	110,075



	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, 2015
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	746	$	—	$	—		$	746
Nonregulated segment	—		91,363		—		(82,509		)	8,854
Total financial instruments	—		92,109		—		(82,509		)	9,600
Hedged portion of gas stored underground	43,901		—		—		—			43,901
Available-for-sale securities
Money market funds	—		1,072		—		—			1,072
Registered investment companies	40,619		—		—		—			40,619
Bonds	—		32,509		—		—			32,509
Total available-for-sale securities	40,619		33,581		—		—			74,200
Total assets	$	84,520	$	125,690	$	—	$	(82,509	)	$	127,701
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	120,107	$	—	$	—		$	120,107
Nonregulated segment	—		125,983		—		(125,983		)	—
Total liabilities	$	—	$	246,090	$	—	$	(125,983	)	$	120,107

⁽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.

⁽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, 2015, we had $39.2 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $21.0 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $18.2 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, 2015, we had $43.5 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $8.9 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, 2015
Domestic equity mutual funds	$	30,054	$	6,843	$	(1,133	)	$	35,764
Foreign equity mutual funds	5,346		868		—			6,214
Bonds	33,149		40		(60		)	33,129
Money market funds	72		—		—			72
	$	68,621	$	7,751	$	(1,193	)	$	75,179
As of September 30, 2015
Domestic equity mutual funds	$	27,643	$	7,332	$	(456	)	$	34,519
Foreign equity mutual funds	5,261		905		(66		)	6,100
Bonds	32,423		106		(20		)	32,509
Money market funds	1,072		—		—			1,072
	$	66,399	$	8,343	$	(542	)	$	74,200

At December 31, 2015 and September 30, 2015, our available-for-sale securities included $42.1 million and $41.7 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2015, we maintained investments in bonds that have contractual maturity dates ranging from January 2016 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, 2015 and September 30, 2015:



	December 31, 2015		September 30, 2015
	(In thousands)
Carrying Amount	$	2,460,000	$	2,460,000
Fair Value	$	2,666,801	$	2,669,323

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, 2015. During the three months ended December 31, 2015, there were no material changes in our concentration of credit risk.

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, 2015 and the related condensed consolidated statements of income, comprehensive income and cash flows for the three-month periods ended December 31, 2015 and 2014. 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, 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and we expressed an unqualified audit opinion on those consolidated financial statements in our report dated November 6, 2015. In our opinion, the accompanying condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2015, is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 2, 2016



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, 2015.

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 commodity price volatility, counterparty creditworthiness or performance and interest rate risk; 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 regulated distribution business; increased costs of providing health care benefits along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain appropriate personnel; 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 climate changes or related additional legislation or regulation in the future; the inherent hazards and risks involved in operating our distribution and pipeline and storage businesses; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers throughout our six regulated distribution divisions, which at December 31, 2015 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.

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, 2015 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, 2015.

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 $102.9 million, or $1.00 per diluted share, a five percent increase over the first quarter of fiscal 2015. Regulated operations represented 96 percent of our consolidated net income for the three months ended December 31, 2015. The following table reflects the segregation of our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:



	Three Months Ended December 31
	2015		2014		Change
	(In thousands, except per share data)
Regulated operations	$	98,841	$	93,422	$	5,419
Nonregulated operations	4,020		4,173		(153		)
Net income	$	102,861	$	97,595	$	5,266

Diluted EPS from regulated operations	$	0.96	$	0.92	$	0.04
Diluted EPS from nonregulated operations	0.04		0.04		—
Consolidated diluted EPS	$	1.00	$	0.96	$	0.04

Positive rate outcomes achieved in our regulated businesses during fiscal 2015 offset the effect of weather that was 29 percent warmer than the prior-year period. As of December 31, 2015, we had completed four regulatory proceedings resulting in a $13.3 million increase in annual operating income and had seven ratemaking efforts in progress seeking $27.4 million of additional annual operating income.

Capital expenditures for the first three months of fiscal 2016 were $291.7 million. Approximately 83 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between $1 billion and $1.1 billion for fiscal 2016. We funded our capital expenditure program primarily through operating cash flows of $70.5 million and net short-term borrowings.

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 7.7 percent for fiscal 2016.

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.

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 includes franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.

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, 2015 compared with Three Months Ended December 31, 2014

Financial and operational highlights for our regulated distribution segment for the three months ended December 31, 2015 and 2014 are presented below.



	Three Months Ended December 31
	2015			2014			Change
	(In thousands, unless otherwise noted)
Gross profit	$	333,461		$	323,812		$	9,649
Operating expenses	193,944			185,715			8,229
Operating income	139,517			138,097			1,420
Miscellaneous expense	(752		)	(1,329		)	577
Interest charges	20,705			21,640			(935		)
Income before income taxes	118,060			115,128			2,932
Income tax expense	44,805			43,741			1,064
Net income	$	73,255		$	71,387		$	1,868
Consolidated regulated distribution sales volumes — MMcf	68,717			86,922			(18,205		)
Consolidated regulated distribution transportation volumes — MMcf	32,211			36,512			(4,301		)
Total consolidated regulated distribution throughput — MMcf	100,928			123,434			(22,506		)
Consolidated regulated distribution average cost of gas per Mcf sold	$	4.44		$	6.02		$	(1.58	)

Income for our regulated distribution segment increased three percent, primarily due to a $9.6 million increase in gross profit, partially offset by an $8.2 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:


•	a $13.5 million net increase in rate adjustments. Our Mid-Tex Division accounted for $7.1 million of this increase. We also experienced increases in our Mississippi and West Texas Divisions.


•	a $1.3 million decrease in revenue-related taxes in our Mid-Tex and West Texas Divisions, offset by a corresponding $0.3 million decrease in the related tax expense.


•	a $1.1 million decrease in consumption. Current-quarter weather was 29 percent warmer than the prior-year quarter, before adjusting for weather normalization mechanisms. As a result, sales volumes decreased 21 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 operation and maintenance expenses due to increased administrative expenses, increased property taxes and depreciation expense associated with increased capital investments.

The following table shows our operating income by regulated distribution division, in order of total rate base, for the three months ended December 31, 2015 and 2014. 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
	2015		2014		Change
	(In thousands)
Mid-Tex	$	68,131	$	59,114	$	9,017
Kentucky/Mid-States	18,918		19,796		(878		)
Louisiana	15,052		16,725		(1,673		)
West Texas	12,930		11,098		1,832
Mississippi	12,827		14,299		(1,472		)
Colorado-Kansas	10,126		9,989		137
Other	1,533		7,076		(5,543		)
Total	$	139,517	$	138,097	$	1,420

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 2016, we completed four regulatory proceedings, resulting in a $13.3 million increase in annual operating income as summarized below:



Rate Action	Annual Increase to Operating Income
	(In thousands)
Annual formula rate mechanisms	$	13,346
Rate case filings	—
Other rate activity	—
	$	13,346

Additionally, the following ratemaking efforts seeking $27.4 million in annual operating income were in progress as of December 31, 2015:



Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Rate Case⁽¹⁾	Colorado	$	5,276
Colorado-Kansas	Infrastructure Mechanism⁽²⁾	Colorado	764
Colorado-Kansas	Rate Case	Kansas	5,667
Colorado-Kansas	Ad Valorem Tax Rider⁽³⁾	Kansas	(183		)
Kentucky/Mid-States	Rate Case	Kentucky	5,531
Louisiana	Formula Rate Filing	Trans LA	6,216
West Texas	Formula Rate Filing	WT Cities	4,168
			$	27,439


⁽¹⁾	The Colorado Public Utilities Commission (PUC) issued a final order approving a $2.1 million increase in annual operating income on January 1, 2016.


⁽²⁾	The PUC allowed the $0.8 million requested amount effected by operation of law on January 1, 2016.


⁽³⁾	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.

Annual Formula Rate Mechanisms

As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi and Tennessee operations and in substantially all of our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state.



	Annual Formula Rate Mechanisms
State	Infrastructure Programs	Formula Rate Mechanisms

Colorado	System Safety and Integrity Rider (SSIR)	—
Kansas	Gas System Reliability Surcharge (GSRS)	—
Kentucky	Pipeline Replacement Program (PRP)	—
Louisiana	(1)	Rate Stabilization Clause (RSC)
Mississippi	System Integrity Rider (SIR)	Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee	—	Annual Rate Mechanism (ARM)
Texas	Gas Infrastructure Reliability Program (GRIP), (1)	Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia	Steps to Advance Virginia Energy (SAVE)	—

⁽¹⁾Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

The following annual formula rate mechanisms had approval dates during the three months ended December 31, 2015.



Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income		Effective Date
		(In thousands)
2016 Filings:
Mississippi	Mississippi-SRF⁽¹⁾	10/31/2016	$	9,192	01/01/2016
Mississippi	Mississippi-SGR ⁽²⁾	10/31/2016	250		12/01/2015
Kentucky/Mid-States	Kentucky-PRP	09/30/2016	3,786		10/01/2015
Kentucky/Mid-States	Virginia-SAVE	09/30/2016	118		10/01/2015
Total 2016 Filings			$	13,346


⁽¹⁾	The commission issued a final order approving a $9.2 million increase in annual operating income on December 21, 2015 with an effective date of January 1, 2016.


⁽²⁾	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 third year of the SGR program.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. No rate cases were completed during the three months ended December 31, 2015.

Other Ratemaking Activity

No other ratemaking activity was completed during the three months ended December 31, 2015.

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 and stores natural gas for our Mid-Tex Division and third party local distribution companies and manages five underground storage facilities in Texas. We also provide interruptible transportation, storage and ancillary services to electric generation and industrial customers as well as producers, marketers and other shippers.

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 and storage 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 the volumes of gas transported for shippers through our pipeline system and the rates for such transportation.

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 transporter 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. Additionally, APT annually uses GRIP to recover capital costs incurred in the prior calendar-year.

Three Months Ended December 31, 2015 compared with Three Months Ended December 31, 2014

Financial and operational highlights for our regulated pipeline segment for the three months ended December 31, 2015 and 2014 are presented below.



	Three Months Ended December 31
	2015			2014			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	68,287		$	60,079		$	8,208
Third-party transportation	21,288			20,394			894
Storage and park and lend services	976			1,004			(28		)
Other	4,126			2,090			2,036
Gross profit	94,677			83,567			11,110
Operating expenses	45,429			40,862			4,567
Operating income	49,248			42,705			6,543
Miscellaneous expense	(429		)	(252		)	(177		)
Interest charges	9,147			8,324			823
Income before income taxes	39,672			34,129			5,543
Income tax expense	14,086			12,094			1,992
Net income	$	25,586		$	22,035		$	3,551
Gross pipeline transportation volumes — MMcf	178,202			181,362			(3,160		)
Consolidated pipeline transportation volumes — MMcf	129,159			120,634			8,525

Net income for our regulated pipeline segment increased 16 percent, primarily due to an $11.1 million increase in gross profit, partially offset by a $4.6 million increase in operating expenses. The increase in gross profit primarily reflects a $10.1 million increase in rates from the approved 2015 GRIP filing. Consolidated volumes are up primarily due to increased market demand from electric generation customers.

Operating expenses increased $4.6 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.


•	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.

Three Months Ended December 31, 2015 compared with Three Months Ended December 31, 2014

Financial and operating highlights for our nonregulated segment for the three months ended December 31, 2015 and 2014 are presented below.



	Three Months Ended December 31
	2015			2014			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	11,850		$	10,759		$	1,091
Storage and transportation services	3,255			3,313			(58		)
Other	(11,251		)	(5,831		)	(5,420		)
Total realized margins	3,854			8,241			(4,387		)
Unrealized margins	11,904			7,798			4,106
Gross profit	15,758			16,039			(281		)
Operating expenses	8,318			9,116			(798		)
Operating income	7,440			6,923			517
Miscellaneous income	379			300			79
Interest charges	1,038			226			812
Income before income taxes	6,781			6,997			(216		)
Income tax expense	2,761			2,824			(63		)
Net income	$	4,020		$	4,173		$	(153	)
Gross nonregulated delivered gas sales volumes — MMcf	96,733			108,193			(11,460		)
Consolidated nonregulated delivered gas sales volumes — MMcf	85,131			90,930			(5,799		)
Net physical position (Bcf)	23.5			17.1			6.4

The $0.3 million quarter-over-quarter decrease in gross profit reflects a $4.4 million decrease in realized margins, combined with a $4.1 million increase in unrealized margins. The $4.4 million decrease in realized margins primarily reflects:


•	A $1.1 million increase in gas delivery and related services margins, primarily due to an increase in per-unit margins from 10 cents to 12 cents per Mcf, partially offset by a six percent decrease in consolidated sales volumes due to warmer weather in the current-year quarter.


•	A $5.4 million decrease in other realized margins, primarily due to larger losses on the settlement of financial positions in a period of falling gas prices combined with increased third-party storage fees.

Unrealized margins increased $4.1 million, primarily due to the quarter-over-quarter favorable movement of the physical mark on the fair value natural gas inventory hedged positions.

Operating expenses decreased $0.8 million, primarily due to lower bad debt expense.

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 under our short-term facilities.

We plan to continue 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 on file with the Securities 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, 2015, 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, 2015, September 30, 2015 and December 31, 2014:



	December 31, 2015				September 30, 2015				December 31, 2014
	(In thousands, except percentages)
Short-term debt	$	763,236	11.8	%	$	457,927	7.5	%	$	550,903	9.1	%
Long-term debt	2,455,474		37.8	%	2,455,388		40.2	%	2,455,131		40.4	%
Shareholders’ equity	3,272,109		50.4	%	3,194,797		52.3	%	3,063,925		50.5	%
Total	$	6,490,819	100.0	%	$	6,108,112	100.0	%	$	6,069,959	100.0	%

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, 2015 and 2014 are presented below.



	Three Months Ended December 31
	2015			2014			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	70,493		$	27,415		$	43,078
Investing activities	(290,645		)	(262,052		)	(28,593		)
Financing activities	270,402			316,211			(45,809		)
Change in cash and cash equivalents	50,250			81,574			(31,324		)
Cash and cash equivalents at beginning of period	28,653			42,258			(13,605		)
Cash and cash equivalents at end of period	$	78,903		$	123,832		$	(44,929	)

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, 2015, we generated cash flow of $70.5 million from operating activities compared with $27.4 million for the three months ended December 31, 2014. The $43.1 million increase 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 target our capital spending on regulatory mechanisms that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Substantially all of our regulated jurisdictions 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 our ongoing construction program, which enables us to enhance the safety and reliability of the systems used to provide 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. Over the last three fiscal years, approximately 80 percent of our capital spending has been committed to improving the safety and reliability of our system. We anticipate our annual capital spending will be in the range of $1 billion to $1.1 billion through fiscal 2018.

For the three months ended December 31, 2015, capital expenditures were $291.7 million, compared with $261.3 million in the prior-year period. The $30.4 million increase primarily reflects an 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.

Cash flows from financing activities

For the three months ended December 31, 2015, our financing activities generated $270.4 million of cash compared with $316.2 million generated in the prior-year period. The $45.8 million decrease of cash generated is primarily due to lower net short-term debt borrowings due to higher operating cash flow and period-over-period changes in working capital funding needs compared to the prior year.

The following table summarizes our share issuances for the three months ended December 31, 2015 and 2014.



	Three Months Ended December 31
	2015	2014
Shares issued:
Direct Stock Purchase Plan	35,417	60,936
1998 Long-Term Incentive Plan	458,607	477,649
Retirement Savings Plan and Trust	106,474	75,580
Outside Directors Stock-for-Fee Plan	—	424
Total shares issued	600,498	614,589

The year-over-year decrease in the number of shares issued primarily reflects a decrease in shares issued under the 1998 Long-Term Incentive Plan. For the three months ended December 31, 2015, we did not cancel and retire any shares attributable to federal income tax withholdings on equity awards. For the three months ended December 31, 2014, we canceled and retired 148,464 such shares.

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, 2015, the amount available to us under our credit facilities, net of outstanding letters of credit, was $0.6 billion.

Credit Ratings

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

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch). As of December 31, 2015, Moody's and Fitch maintained a stable outlook. S&P issued a revised outlook from stable to positive on October 29, 2015, citing the potential for an upgraded rating in the future if we maintain our current level of financial performance as capital spending levels remain elevated. 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, 2015. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Except as noted 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, 2015.

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.

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, 2015 and 2014:



	Three Months Ended December 31
	2015			2014
	(In thousands)
Fair value of contracts at beginning of period	$	(119,361	)	$	14,284
Contracts realized/settled	(12,630		)	(23,156		)
Fair value of new contracts	(183		)	(365		)
Other changes in value	22,911			(85,611		)
Fair value of contracts at end of period	$	(109,263	)	$	(94,848	)

The fair value of our regulated distribution segment’s financial instruments at December 31, 2015 is presented below by time period and fair value source:



	Fair Value of Contracts at December 31, 2015
	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	$	(6,022	)	$	(103,241	)	$	—	$	—	$	(109,263	)
Prices based on models and other valuation methods	—			—			—		—		—
Total Fair Value	$	(6,022	)	$	(103,241	)	$	—	$	—	$	(109,263	)

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, 2015 and 2014:



	Three Months Ended December 31
	2015			2014
	(In thousands)
Fair value of contracts at beginning of period	$	(34,620	)	$	(3,033	)
Contracts realized/settled	18,898			7,165
Fair value of new contracts	—			—
Other changes in value	(5,297		)	(30,231		)
Fair value of contracts at end of period	(21,019		)	(26,099		)
Netting of cash collateral	39,248			43,501
Cash collateral and fair value of contracts at period end	$	18,229		$	17,402

The fair value of our nonregulated segment’s financial instruments at December 31, 2015 is presented below by time period and fair value source:



	Fair Value of Contracts at December 31, 2015
	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	$	(14,023	)	$	(6,378	)	$	(618	)	$	—	$	(21,019	)
Prices based on models and other valuation methods	—			—			—			—		—
Total Fair Value	$	(14,023	)	$	(6,378	)	$	(618	)	$	—	$	(21,019	)

Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2015 and 2014, our total net periodic pension and other benefits costs were $11.5 million and $14.7 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 2016 costs were determined using a September 30, 2015 measurement date. As of September 30, 2015, interest and corporate bond rates utilized to determine our discount rates were higher than the interest and corporate bond rates as of September 30, 2014, the measurement date for our fiscal 2015 net periodic cost. Therefore, we increased the discount rate used to measure our fiscal 2016 net periodic cost from 4.43 percent to 4.55 percent. We lowered our expected return on plan assets from 7.25 percent to 7.00 percent in the determination of our fiscal 2016 net periodic pension cost based upon expected market returns for our targeted asset allocation. 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 and in October 2015, the Society of Actuaries issued an additional report related to mortality tables and the mortality improvement scale. As of September 30, 2015, we updated our assumed mortality tables to incorporate both of these updates. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2016 net periodic pension cost to decrease by approximately 20 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 the determination as of January 1, 2015, we are not required to make a minimum contribution to our defined benefit plans during fiscal 2016. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.

For the three months ended December 31, 2015 we contributed $5.5 million to our postretirement medical plans. We anticipate contributing between $15 million and $25 million to our postretirement plans during fiscal 2016.

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.

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, 2015 and 2014.

Regulated Distribution Sales and Statistical Data



	Three Months Ended December 31
	2015		2014
METERS IN SERVICE, end of period
Residential	2,891,676		2,862,369
Commercial	265,766		261,593
Industrial	1,489		1,538
Public authority and other	8,421		8,451
Total meters	3,167,352		3,133,951

INVENTORY STORAGE BALANCE — Bcf	58.5		53.0
SALES VOLUMES — MMcf⁽¹⁾
Gas sales volumes
Residential	40,169		52,218
Commercial	23,418		28,715
Industrial	3,456		3,890
Public authority and other	1,674		2,099
Total gas sales volumes	68,717		86,922
Transportation volumes	35,124		38,835
Total throughput	103,841		125,757
OPERATING REVENUES (000’s)⁽¹⁾
Gas sales revenues
Residential	$	415,985	$	541,725
Commercial	172,025		241,630
Industrial	14,285		22,911
Public authority and other	10,533		14,998
Total gas sales revenues	612,828		821,264
Transportation revenues	19,481		19,152
Other gas revenues	6,293		6,356
Total operating revenues	$	638,602	$	846,772
Average cost of gas per Mcf sold	$	4.44	$	6.02

See footnote following these tables.

Regulated Pipeline and Nonregulated Operations Sales and Statistical Data



	Three Months Ended December 31
	2015		2014
CUSTOMERS, end of period
Industrial	758		747
Municipal	128		129
Other	523		539
Total	1,409		1,415
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf	25.4		21.6
REGULATED PIPELINE VOLUMES — MMcf⁽¹⁾	178,202		181,362
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf⁽¹⁾	96,733		108,193
OPERATING REVENUES (000’s)⁽¹⁾
Regulated pipeline	$	94,677	$	83,567
Nonregulated	272,524		462,288
Total operating revenues	$	367,201	$	545,855

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, 2015. During the three months ended December 31, 2015, there were no material changes in our quantitative and qualitative disclosures about market risk.



Item 4.	Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure 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, 2015 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, 2016 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, 2015, 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, 2015. 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.

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/ BRET J. ECKERT
			Bret J. Eckert Senior Vice President and Chief Financial Officer (Duly authorized signatory)

Date: February 2, 2016

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.