10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended September 30, 2016

OR

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

For the transition period from                      to                     

Commission file number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)

Texas and Virginia    75-1743247

(State or other jurisdiction of    (IRS employer

incorporation or organization)    identification no.)

Three Lincoln Centre, Suite 1800

5430 LBJ Freeway, Dallas, Texas    75240

(Address of principal executive offices)    (Zip code)

Registrant’s telephone number, including area code:

(972) 934-9227

Securities registered pursuant to Section 12(b) of the Act:

Name of Each Exchange

Title of Each Classon Which Registered

Common stock, No Par Value    New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  þ        No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨        No  þ

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.45) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer    þAccelerated 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 Act).    Yes  ¨       No  þ

The aggregate market value of the common voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2016, was $7,463,087,078.

As of November 9, 2016, the registrant had 103,964,735 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 8, 2017 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

		Page
Glossary of Key Terms		3
	Part I
Item 1.	Business	4
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	44
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	98
Item 9A.	Controls and Procedures	98
Item 9B.	Other Information	100
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	100
Item 11.	Executive Compensation	101
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	101
Item 13.	Certain Relationships and Related Transactions, and Director Independence	101
Item 14.	Principal Accountant Fees and Services	101
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	101

GLOSSARY OF KEY TERMS

AEC	Atmos Energy Corporation
AEH	Atmos Energy Holdings, Inc.
AEM	Atmos Energy Marketing, LLC
AOCI	Accumulated Other Comprehensive Income
APS	Atmos Pipeline and Storage, LLC
ATO	Trading symbol for Atmos Energy Corporation common stock on the New York Stock Exchange
Bcf	Billion cubic feet
CFTC	Commodity Futures Trading Commission
COSO	Committee of Sponsoring Organizations of the Treadway Commission
ERISA	Employee Retirement Income Security Act of 1974
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
GSRS	Gas System Reliability Surcharge
KPSC	Kentucky Public Service Commission
LTIP	1998 Long-Term Incentive Plan
Mcf	Thousand cubic feet
MDWQ	Maximum daily withdrawal quantity
Mid-Tex Cities	Represents all incorporated cities other than Dallas, or approximately 80 percent of the Mid-Tex Division’s customers, with whom a settlement agreement was reached during the fiscal 2008 second quarter.
MMcf	Million cubic feet
Moody’s	Moody’s Investor Service, Inc.
NYMEX	New York Mercantile Exchange, Inc.
NYSE	New York Stock Exchange
PAP	Pension Account Plan
PPA	Pension Protection Act of 2006
RRC	Railroad Commission of Texas
RRM	Rate Review Mechanism
RSC	Rate Stabilization Clause
S&P	Standard & Poor’s Corporation
SEC	United States Securities and Exchange Commission
SRF	Stable Rate Filing
WNA	Weather Normalization Adjustment

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PART I

The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.

ITEM 1. Business.

Overview and Strategy

Atmos Energy Corporation, headquartered in Dallas, Texas, and incorporated in Texas and Virginia, is engaged primarily in the regulated natural gas distribution and pipeline businesses as well as other nonregulated natural gas businesses. We deliver natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in eight states located primarily in the South, which makes us one of the country’s largest natural-gas-only distributors based on number of customers. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.

Our nonregulated businesses provide natural gas management, marketing, transportation and storage services to municipalities, local gas distribution companies, including certain of our natural gas distribution divisions and industrial customers principally in the Midwest and Southeast.

Atmos Energy's vision is to be the safest provider of natural gas services. We intend to achieve this vision by:

• operating our business exceptionally well

• investing in our people and infrastructure

• enhancing our culture.

We believe the successful execution of this strategy has delivered excellent shareholder value. Over the last five years, we have achieved growth by making significant capital investments to fortify and upgrade our distribution and transmission systems and successfully recovering these investments through regulatory mechanisms designed to minimize regulatory lag.

Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We continue to strengthen our culture through ongoing communications with our employees and enhanced employee training.

Operating Segments

We operate the Company through the following three segments:

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

• The regulated pipeline segment, which includes the 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.

These operating segments are described in greater detail below.

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Regulated Distribution Segment Overview

Our regulated distribution segment is comprised of our six regulated natural gas distribution divisions. This segment represents approximately 65 percent of our consolidated net income. The following table summarizes key information about these divisions, presented in order of total rate base. We operate in our service areas under terms of non-exclusive franchise agreements granted by the various cities and towns that we serve. At September 30, 2016, we held 1,003 franchises having terms generally ranging from five to 35 years. A significant number of our franchises expire each year, which require renewal prior to the end of their terms. Historically, we have successfully renewed these franchises and believe that we will continue to be able to renew our franchises as they expire.

Division	Service Areas	Communities Served	Customer Meters
Mid-Tex	Texas, including the Dallas/Fort Worth Metroplex	550	1,649,291
Kentucky/Mid-States	Kentucky	230	179,717
	Tennessee		143,942
	Virginia		23,820
Louisiana	Louisiana	280	358,972
West Texas	Amarillo, Lubbock, Midland	80	308,988
Mississippi	Mississippi	110	269,750
Colorado-Kansas	Colorado	170	117,017
	Kansas		134,012

Revenues in this operating segment are established by regulatory authorities in the states in which we operate. These rates are intended to be sufficient to cover the costs of conducting business and to provide a reasonable return on invested capital. In addition, we transport natural gas for others through our distribution system.

Rates established by regulatory authorities often include cost adjustment mechanisms for costs that (i) are subject to significant price fluctuations compared to our other costs, (ii) represent a large component of our cost of service and (iii) are generally outside our control.

Purchased gas cost adjustment mechanisms represent a common form of cost adjustment mechanism. Purchased gas cost adjustment mechanisms provide natural gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case because they provide a dollar-for-dollar offset to increases or decreases in natural gas distribution gas costs. Therefore, although substantially all of our distribution operating revenues fluctuate with the cost of gas that we purchase, distribution gross profit (which is defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas.

Additionally, some jurisdictions have performance-based ratemaking adjustments to provide incentives to distribution companies to minimize purchased gas costs through improved storage management and use of financial instruments to lock in gas costs. Under the performance-based ratemaking adjustment, purchased gas costs savings are shared between the utility and its customers.

Our supply of natural gas is provided by a variety of suppliers, including independent producers, marketers and pipeline companies and withdrawals of gas from proprietary and contracted storage assets. Additionally, the natural gas supply for our Mid-Tex Division includes peaking and spot purchase agreements.

Supply arrangements consist of both base load and swing supply (peaking) quantities and are contracted from our suppliers on a firm basis with various terms at market prices. Base load quantities are those that flow at a constant level throughout the month and swing supply quantities provide the flexibility to change daily quantities to match increases or decreases in requirements related to weather conditions.

Except for local production purchases, we select our natural gas suppliers through a competitive bidding process by periodically requesting proposals from suppliers that have demonstrated that they can provide reliable service. We select these suppliers based on their ability to deliver gas supply to our designated firm pipeline receipt points at the lowest reasonable cost. Major suppliers during fiscal 2016 were Concord Energy LLC, ConocoPhillips Company, Devon Gas Services, L.P., Gulf South Pipeline Company LP, Sequent Energy Management, LP, Targa Gas Marketing LLC, Tenaska Gas Storage, LLC, Texas

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Gas Transmission Corporation, Texla Energy Management, Inc. and Atmos Energy Marketing, LLC and Trans Louisiana Gas Pipeline, Inc., which are wholly owned subsidiaries in our nonregulated segment.

The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments. We estimate our peak-day availability of natural gas supply to be approximately 4.4 Bcf. The peak-day demand for our distribution operations in fiscal 2016 was on January 10, 2016, when sales to customers reached approximately 2.5 Bcf.

Currently, our distribution divisions, except for our Mid-Tex Division, utilize 40 pipeline transportation companies, both interstate and intrastate, to transport our natural gas. The pipeline transportation agreements are firm and many of them have “pipeline no-notice” storage service, which provides for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term necessary while still maintaining our right of first refusal. The natural gas supply for our Mid-Tex Division is delivered primarily by our Atmos Pipeline — Texas Division (APT).

To maintain our deliveries to high priority customers, we have the ability, and have exercised our right, to curtail deliveries to certain customers under the terms of interruptible contracts or applicable state regulations or statutes. Our customers’ demand on our system is not necessarily indicative of our ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering, storage and transmission systems, the duration and severity of cold weather, the availability of gas reserves from our suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Curtailment rights provide us the flexibility to meet the human-needs requirements of our customers on a firm basis. Priority allocations imposed by federal and state regulatory agencies, as well as other factors beyond our control, may affect our ability to meet the demands of our customers. We do not anticipate any problems with obtaining additional gas supply as needed for our customers.

Regulated Pipeline Segment Overview

Our regulated pipeline segment consists of the regulated pipeline and storage operations of APT. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Through it, APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage reservoirs in Texas. This segment represents approximately 30 percent of our consolidated operations.

Gross profit earned from transportation and storage services for APT is subject to traditional ratemaking governed by the RRC. Rates are updated through periodic filings made under Texas’ Gas Reliability Infrastructure Program (GRIP). GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years. APT’s existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates.

Nonregulated Segment Overview

Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation, and typically represent 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.

Ratemaking Activity

Overview

The method of determining regulated rates varies among the states in which our regulated businesses operate. The regulatory authorities have the responsibility of ensuring that utilities in their jurisdictions operate in the best interests of customers while providing utility companies the opportunity to earn a reasonable return on their investment. Generally, each regulatory authority reviews rate requests and establishes a rate structure intended to generate revenue sufficient to cover the costs of conducting business and to provide a reasonable return on invested capital.

Our rate strategy focuses on reducing or eliminating regulatory lag, obtaining adequate returns and providing stable, predictable margins, which benefit both our customers and the Company. As a result of our ratemaking efforts in recent years, Atmos Energy has:

• Formula rate mechanisms in place in four states that provide for an annual rate review and adjustment to rates.

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• Infrastructure programs in place in the majority of our states that provide for an annual rate adjustment to rates for qualifying capital expenditures. Through our annual formula rate mechanisms and infrastructure programs, we have the ability to recover over 90 percent of our capital expenditures within six months.

• Authorization in tariffs, statute or commission rules that allows us to defer certain elements of our cost of service until they are included in rates, such as depreciation, ad valorem taxes and pension costs.

• WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 97 percent of our distribution gross margin.

• The ability to recover the gas cost portion of bad debts in five states.

The following table provides a jurisdictional rate summary for our regulated operations. This information is for regulatory purposes only and may not be representative of our actual financial position.

Division	Jurisdiction	Effective Date of Last Rate/GRIP Action	Rate Base (thousands)(1)	Authorized Rate of Return(1)	Authorized Debt/ Equity Ratio	Authorized Return on Equity(1)
Atmos Pipeline — Texas	Texas	05/01/2011	$807,733	9.36%	50/50	11.80%
Atmos Pipeline — Texas — GRIP	Texas	05/03/2016	722,700(2)	9.36%	N/A	11.80%
Colorado-Kansas	Colorado	01/01/2016	129,094	7.82%	48/52	9.60%
	Colorado SSIR	01/01/2016	9,478	7.82%	48/52	9.60%
	Kansas	03/17/2016	200,564	(4)	(4)	(4)
Kentucky/Mid-States	Kentucky	08/15/2016	335,833	(4)	(4)	(4)
	Tennessee	06/01/2016	274,595	7.72%	47/53	9.80%
	Virginia	04/01/2016	49,132	(4)	(4)	9.00% - 10.00%
Louisiana	Trans La	04/01/2016	138,692	7.79%	46/54	9.80%
	LGS	07/01/2016	350,837	7.73%	46/54	9.80%
Mid-Tex Cities	Texas	06/01/2016	2,130,568(3)	8.43%	45/55	10.50%
Mid-Tex — Dallas	Texas	06/01/2016	2,076,415(3)	8.28%	43/57	10.10%
Mississippi	Mississippi	12/21/2015	357,646	7.94%	47/53	9.88%
	Mississippi - SGR	12/03/2015	3,475	9.37%	47/53	12.00%
West Texas(5)	Texas	03/15/2016	(4)	(4)	(4)	10.50%
	Texas-GRIP	05/03/2016	419,976	8.57%	48/52	10.50%

Division	Jurisdiction	Bad  Debt Rider(6)	Formula Rate	Infrastructure Mechanism	Performance Based Rate  Program(7)	WNA Period
Atmos Pipeline —  Texas	Texas	No	Yes	Yes	N/A	N/A
Colorado-Kansas	Colorado	No	No	Yes	No	N/A
	Kansas	Yes	No	Yes	No	October-May
Kentucky/Mid-States	Kentucky	Yes	No	Yes	Yes	November-April
	Tennessee	Yes	Yes	No	Yes	October-April
	Virginia	Yes	No	Yes	No	January-December
Louisiana	Trans La	No	Yes	Yes	No	December-March
	LGS	No	Yes	Yes	No	December-March
Mid-Tex Cities	Texas	Yes	Yes	Yes	No	November-April
Mid-Tex — Dallas	Texas	Yes	Yes	Yes	No	November-April
Mississippi	Mississippi	No	Yes	Yes	Yes	November-April
West Texas(5)	Texas	Yes	Yes	Yes	No	October-May

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⁽¹⁾  The rate base, authorized rate of return and authorized return on equity presented in this table are those from the most recent regulatory filing for each jurisdiction. These rate bases, rates of return and returns on equity are not necessarily indicative of current or future rate bases, rates of return or returns on equity.

⁽²⁾  This APT rate base represents the incremental rate base approved through annual GRIP filings since APT's last rate case in 2011.

⁽³⁾  The Mid-Tex Rate Base amounts for the Mid-Tex Cities and Dallas areas represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.

⁽⁴⁾  A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.

⁽⁵⁾  On April 1, 2014, a rate case settlement approved by the West Texas Cities reestablished an annual rate mechanism for all West Texas Division cities except Amarillo, Channing, Dalhart and Lubbock.

⁽⁶⁾  The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.

⁽⁷⁾  The performance-based rate program provides incentives to distribution companies to minimize purchased gas costs by allowing the companies and its customers to share the purchased gas costs savings.

Although substantial progress has been made in recent years by improving rate design and recovery of investment across Atmos Energy’s operating areas, we will continue to seek improvements in rate design to address cost variations and pursue tariffs that reduce regulatory lag associated with investments. Further, potential changes in federal energy policy, federal safety regulations and adverse economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.

Recent Ratemaking Activity

Substantially all of our regulated revenues in the fiscal years ended September 30, 2016, 2015 and 2014 were derived from sales at rates set by or subject to approval by local or state authorities. Net operating income increases resulting from ratemaking activity totaling $122.5 million, $114.5 million and $93.3 million, became effective in fiscal 2016, 2015 and 2014, as summarized below:

	Annual Increase to Operating Income For the Fiscal Year Ended September 30
Rate Action	2016			2015		2014
	(In thousands)
Annual formula rate mechanisms	$	114,974		$	113,706	$	71,749
Rate case filings	7,716			711		21,819
Other ratemaking activity	(183		)	78		(226		)
	$	122,507		$	114,495	$	93,342

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Additionally, the following ratemaking efforts were initiated during fiscal 2016 but had not been completed as of September 30, 2016:

Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Kentucky/Mid-States	SAVE(1)	Virginia	$	(181	)
	PRP(1)	Kentucky	4,938
	ARM(2) True-Up	Tennessee	5,514
Mississippi	SIR(1)	Mississippi	3,334
	SGR(3)	Mississippi	1,292
			$	14,897

⁽¹⁾  The Steps to Advance Virginia Energy (SAVE) Plan, the Pipeline Replacement Program (PRP) and the System Integrity Rider (SIR) surcharges relate to long-term programs to replace aging infrastructure.

⁽²⁾  The Annual Rate Mechanism (ARM) is a formula rate mechanism that refreshes the Company's rates on an annual basis.

⁽³⁾  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.

Our recent ratemaking activity is discussed in greater detail below.

Annual Formula Rate Mechanisms

As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual 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 and our Atmos Pipeline - Texas Division 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 Reliability Infrastructure 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 (Texas only), 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 table summarizes our annual formula rate mechanisms with effective dates during the fiscal years ended September 30, 2016, 2015 and 2014:

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Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
			(In thousands)
2016 Filings:
Louisiana	LGS(1)	12/2015	$	8,686		07/01/2016
Kentucky/Mid-States	Tennessee	05/2017	4,888			06/01/2016
Mid-Tex	Mid-Tex Cities RRM	12/2015	25,816			06/01/2016
Mid-Tex	Mid-Tex DARR	09/2015	5,429			06/01/2016
Mid-Tex	Mid-Tex Environs	12/2015	1,325			05/03/2016
Atmos Pipeline — Texas	Texas	12/2015	40,658			05/03/2016
West Texas	West Texas Environs	12/2015	646			05/03/2016
West Texas	West Texas ALDC	12/2015	3,484			04/26/2016
Louisiana	Trans La(1)	09/2015	6,216			04/01/2016
Colorado-Kansas	Colorado	12/2016	764			01/01/2016
Mississippi	Mississippi-SRF(2)	10/2016	9,192			01/01/2016
Mississippi	Mississippi-SGR	10/2016	250			12/01/2015
Kentucky/Mid-States	Kentucky-PRP	09/2016	3,786			10/01/2015
Kentucky/Mid-States	Virginia-SAVE	09/2016	118			10/01/2015
West Texas	West Texas Cities	09/2015	3,716			10/01/2015
Total 2016 Filings			$	114,974
2015 Filings:
Louisiana	LGS	12/2014	$	1,321		07/01/2015
West Texas	Environs	12/2014	697			06/12/2015
Mid-Tex	Environs	12/2014	1,158			06/01/2015
Mid-Tex	Mid-Tex Cities	12/2014	16,801			06/01/2015
Mid-Tex	Dallas	09/2014	4,420			06/01/2015
West Texas	Cities	12/2014	4,593			05/01/2015
Atmos Pipeline — Texas	Texas	12/2014	37,248			04/08/2015
Louisiana	Trans La	09/2014	(286		)	04/01/2015
West Texas	West Texas Cities	09/2014	4,300			03/15/2015
Colorado-Kansas	Kansas	09/2014	301			02/01/2015
Mississippi	Mississippi-SRF	10/2015	4,441			02/01/2015
Mississippi	Mississippi-SGR	10/2015	782			11/01/2014
Kentucky/Mid-States	Kentucky	09/2015	4,382			10/10/2014
Kentucky/Mid-States	Virginia	09/2015	133			10/01/2014
Mid-Tex	Mid-Tex Cities	12/2013	33,415			06/01/2014
Total 2015 Filings			$	113,706
2014 Filings:
Louisiana	LGS	12/2013	$	1,383		07/01/2014
West Texas	West Texas	12/2013	858			06/17/2014
Mid-Tex	City of Dallas	09/2013	5,638			06/01/2014
Mid-Tex	Environs	12/2013	881			05/22/2014
Atmos Pipeline — Texas	Texas	12/2013	45,589			05/06/2014
Louisiana	Trans La	09/2013	550			04/01/2014
Colorado-Kansas	Kansas	09/2013	882			02/01/2014
Mid-Tex	Mid-Tex Cities	12/2012	12,497			11/01/2013
Kentucky/Mid-States	Kentucky	09/2014	2,493			10/01/2013

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Kentucky/Mid-States	Virginia	09/2014	210		10/01/2013
Mid-Tex	Environs	12/2012	768		10/01/2013
Total 2014 Filings			$	71,749

⁽¹⁾  On April 1 and July 1, 2016, RSC rates, subject to refund, were implemented in our two Louisiana jurisdictions.

⁽²⁾  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.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to 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 safely deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:

Division	State	Increase in Annual Operating Income		Effective Date
		(In thousands)
2016 Rate Case Filings:
Kentucky/Mid-States	Kentucky	$	2,723	08/15/2016
Kentucky/Mid-States	Virginia(1)	537		04/01/2016
Colorado-Kansas	Kansas	2,372		03/17/2016
Colorado-Kansas	Colorado	2,084		01/01/2016
Total 2016 Rate Case Filings		$	7,716
2015 Rate Case Filings:
Kentucky/Mid-States	Tennessee	$	711	06/01/2015
Total 2015 Rate Case Filings		$	711
2014 Rate Case Filings:
Kentucky/Mid-States	Virginia	$	976	09/09/2014
Colorado-Kansas	Kansas	2,571		09/04/2014
Colorado-Kansas	Colorado	2,400		08/26/2014
Kentucky/Mid-States	Kentucky	5,823		04/22/2014
West Texas	Texas	8,440		04/01/2014
Colorado-Kansas	Colorado	1,609		03/01/2014
Total 2014 Rate Case Filings		$	21,819

⁽¹⁾  On April 1, 2016, interim rates, subject to refund, were implemented in Virginia.

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Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2016, 2015 and 2014:

Division	Jurisdiction	Rate Activity	Increase in Annual Operating Income			Effective Date
			(In thousands)
2016 Other Rate Activity:
Colorado-Kansas	Kansas	Ad-Valorem(1)	$	(183	)	02/01/2016
Total 2016 Other Rate Activity			$	(183	)
2015 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem(1)	$	78		02/01/2015
Total 2015 Other Rate Activity			$	78
2014 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem(1)	$	(226	)	02/01/2014
Total 2014 Other Rate Activity			$	(226	)

⁽¹⁾  The Ad Valorem filing relates to property taxes that are either over or uncollected compared to the amount included in our Kansas service area’s base rates.

Other Regulation

Each of our regulated distribution divisions and our regulated pipeline division is regulated by various state or local public utility authorities. We are also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of our transmission and distribution facilities. In addition, our regulated operations are also subject to various state and federal laws regulating environmental matters. From time to time we receive inquiries regarding various environmental matters. We believe that our properties and operations substantially comply with, and are operated in substantial conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. Our environmental claims have arisen primarily from former manufactured gas plant sites.

The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act, gas transportation services through our Atmos Pipeline—Texas assets “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting these assets to the jurisdiction of the FERC. Additionally, the FERC has regulatory authority over the sale of natural gas in the wholesale gas market and the use and release of interstate pipeline and storage capacity. The FERC also has authority to detect and prevent market manipulation and to enforce compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. We have taken what we believe are the necessary and appropriate steps to comply with these regulations.

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act required various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act. A number of those regulations have been adopted; we have enacted new procedures and modified existing business practices and contractual arrangements to comply with such regulations. We expect additional regulations to be issued, which should provide additional clarity regarding the extent of the impact of this legislation on us. The costs of participating in financial markets for hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted. We also anticipate that the Commodities Futures Trading Commission will issue additional regulations related to reporting and disclosure obligations.

Competition

Although our regulated distribution operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas, we do compete with other natural gas suppliers and suppliers of alternative fuels for sales to industrial customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. The principal means to compete against

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alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential, commercial and industrial markets.

Our regulated pipeline operations historically faced competition from other existing intrastate pipelines seeking to provide or arrange transportation, storage and other services for customers. In the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

Within our nonregulated operations, AEM competes with other natural gas marketers to provide natural gas management and other related services primarily to smaller customers requiring higher levels of balancing, scheduling and other related management services. AEM has experienced increased competition in recent years primarily from investment banks and major integrated oil and natural gas companies who offer lower cost, basic services. The increased competition has reduced margins most notably on its high-volume accounts.

Employees

At September 30, 2016, we had 4,747 employees, consisting of 4,639 employees in our regulated operations and 108 employees in our nonregulated operations.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, under “Publications and Filings” under the “Investors” tab, as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:

Shareholder Relations

Atmos Energy Corporation

P.O. Box 650205

Dallas, Texas 75265-0205

972-855-3729

Corporate Governance

In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer during fiscal 2016, Kim R. Cocklin, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on the Corporate Governance page of our website. We will also provide copies of all corporate governance documents free of charge upon request to Shareholder Relations at the address listed above.

ITEM 1A. Risk Factors.

Our financial and operating results are subject to a number of risk factors, many of which are not within our control. Although we have tried to discuss key risk factors below, please be aware that other or new risks may prove to be important in the future. Investors should carefully consider the following discussion of risk factors as well as other information appearing in this report. These factors include the following:

The Company is dependent on continued access to the credit and capital markets to execute our business strategy.

Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation, Moody’s Investors Service, Inc. and Fitch Ratings, Ltd. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private and public capital markets, we could see a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook or even a reduction in our credit ratings by one or more of the three credit rating agencies. Such a downgrade could further limit our access to private credit and/or public capital markets and increase our costs of borrowing.

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Further, if our credit ratings were downgraded, we could be required to provide additional liquidity to our nonregulated segment because the commodity financial instrument markets could become unavailable to us. Our nonregulated segment depends primarily upon an intercompany lending facility between AEH and Atmos Energy to finance its working capital needs, supplemented by two small credit facilities with outside lenders. Our ability to provide this liquidity to AEH for our nonregulated operations is limited by the terms of the lending arrangement with AEH, which is subject to annual approval by one state regulatory commission.

While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near term. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.

We are subject to state and local regulations that affect our operations and financial results.

Our regulated distribution and regulated pipeline segments are subject to regulatory oversight from various state and local regulatory authorities in the eight states that we serve in our regulated distribution and pipeline segments. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of business, as a regulated entity, we often need to place assets in service and establish historical test periods before rate cases that seek to adjust our allowed returns to recover that investment can be filed. Further, the regulatory review process can be lengthy in the context of traditional ratemaking. Because of this process, we suffer the negative financial effects of having placed assets in service without the benefit of rate relief, which is commonly referred to as “regulatory lag.”

However, in the last several years, a number of regulatory authorities in the states we serve have approved rate mechanisms that provide for annual adjustments to rates that allow us to recover the cost of investments made to replace existing infrastructure or reflect changes in our cost of service. These mechanisms work to effectively reduce the regulatory lag inherent in the ratemaking process. However, regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. The regulatory process also involves the risk that regulatory authorities may (i) review our purchases of natural gas and adjust the amount of our gas costs that we pass through to our customers or (ii) limit the costs we may have incurred from our cost of service that can be recovered from customers.

A deterioration in economic conditions could adversely affect our customers and negatively impact our financial results.

Any adverse changes in economic conditions in the United States, especially in the states in which we operate, could adversely affect the financial resources of many domestic households and lead to an increase in mortgage defaults and significant decreases in the values of our customers’ homes and investment assets. As a result, our customers could seek to use even less gas and make it more difficult for them to pay their gas bills. This would likely lead to slower collections and higher than normal levels of accounts receivable. This, in turn, would probably increase our financing requirements. Additionally, should economic conditions deteriorate, our industrial customers could seek alternative energy sources, which could result in lower sales volumes.

Inflation and increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.

Over time, inflation has caused increases in some of our operating expenses and has required assets to be replaced at higher costs. We have a process in place to continually review the adequacy of our distribution gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates and intend to continue to do so. However, the ability to control expenses is an important factor that could impact future financial results.

In addition, rapid increases in the costs of purchased gas would cause us to experience a significant increase in short-term debt. We must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our natural gas distribution collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal accounts receivable. This could result in higher short-term debt levels, greater collection efforts and increased bad debt expense.

If contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner, our ability to meet our customers’ natural gas requirements may be impaired and our financial condition may be adversely affected.

In order to meet our customers’ annual and seasonal natural gas demands, we must obtain a sufficient supply of natural gas, interstate pipeline capacity and storage capacity. If we are unable to obtain these, either from our suppliers’ inability to deliver

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the contracted commodity or the inability to secure replacement quantities, our financial condition and results of operations may be adversely affected. If a substantial disruption to or reduction in interstate natural gas pipelines’ transmission and storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, terrorist or cyber-attacks or acts of war, our operations or financial results could be adversely affected.

We are exposed to market risks that are beyond our control, which could adversely affect our financial results and capital requirements.

We are subject to market risks beyond our control, including (i) commodity price volatility caused by market supply and demand dynamics, counterparty performance or counterparty creditworthiness, and (ii) interest rate risk.

Our regulated operations are generally insulated from commodity price risk through its purchased gas cost mechanisms. Although our nonregulated operations represent only about five percent of our consolidated financial results, commodity price volatility experienced in this business segment could lead to some minor volatility in our earnings. Our nonregulated segment manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of a variety of financial instruments. However, contractual limitations could adversely affect our ability to withdraw gas from storage, which could cause us to purchase gas at spot prices in a rising market to obtain sufficient volumes to fulfill customer contracts. We could also realize financial losses on our efforts to limit risk as a result of volatility in the market prices of the underlying commodities or if a counterparty fails to perform under a contract.

With respect to interest rate risk, we have been operating in a relatively low interest-rate environment in recent years compared to historical norms for both short and long-term interest rates. However, increases in interest rates could adversely affect our future financial results.

The concentration of our distribution, pipeline and storage operations in the State of Texas exposes our operations and financial results to economic conditions, weather patterns and regulatory decisions in Texas.

Over 50 percent of our regulated distribution customers and most of our regulated pipeline assets and operations are located in the State of Texas. This concentration of our business in Texas means that our operations and financial results may be significantly affected by changes in the Texas economy in general, weather patterns and regulatory decisions by state and local regulatory authorities in Texas.

Our operations are subject to increased competition.

In residential and commercial customer markets, our regulated distribution operations compete with other energy products, such as electricity and propane. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This could adversely impact our business if, as a result, our customer growth slows, reducing our ability to make capital expenditures, or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.

In the case of industrial customers, such as manufacturing plants, adverse economic conditions, including higher gas costs, could cause these customers to use alternative sources of energy, such as electricity, or bypass our systems in favor of special competitive contracts with lower per-unit costs. Our regulated pipeline operations historically have faced limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, in the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

Finally, within our nonregulated operations, AEM competes with other natural gas marketers to provide natural gas management and other related services primarily to smaller customers requiring higher levels of balancing, scheduling and other related management services. AEM has experienced increased competition in recent years from competitors who offer lower cost, basic services.

Adverse weather conditions could affect our operations or financial results.

We have weather-normalized rates for over 95 percent of our residential and commercial meters in our regulated distribution business, which substantially mitigates the adverse effects of warmer-than-normal weather for meters in those service areas. However, there is no assurance that we will continue to receive such regulatory protection from adverse weather in our rates in the future. The loss of such weather-normalized rates could have an adverse effect on our operations and financial results. In addition, our regulated distribution and regulated pipeline operating results may continue to vary somewhat with the actual temperatures during the winter heating season. Sustained cold weather could adversely affect our nonregulated operations as we may be required to purchase gas at spot rates in a rising market to obtain sufficient volumes to fulfill some customer contracts. Additionally, sustained cold weather could challenge our ability to adequately meet customer demand in our natural gas distribution and pipeline and storage operations.

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Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.

The regulated natural gas distribution and pipeline business is capital-intensive. We must make significant capital expenditures to renew or replace our facilities on a long-term basis to improve the safety and reliability of our facilities and to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas we operate. In addition, we must continually build new capacity in our regulated distribution and regulated pipeline operations to serve the growing needs of the communities we serve. The magnitude of these expenditures may be affected by a number of factors, including new regulations, the general state of the economy and weather.

The liquidity required to fund our capital expenditures and other cash needs is provided from a variety of sources, including our cash flows from operations, borrowings under our short-term lending facilities, and, from time to time, funds raised from the public debt and equity capital markets. The cost and availability of borrowing funds from third party lenders or issuing equity is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit the amount of funds we can invest in our infrastructure.

The costs of providing health care benefits, pension and postretirement health care benefits and related funding requirements may increase substantially.

We provide health care benefits, a cash-balance pension plan and postretirement health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company are difficult to measure at this time.

The costs of providing a cash-balance pension plan to eligible full-time employees prior to 2011 and postretirement health care benefits to eligible full-time employees and related funding requirements could be influenced by changes in the market value of the assets funding our pension and postretirement health care plans. Any significant declines in the value of these investments due to sustained declines in equity markets or a reduction in bond yields could increase the costs of our pension and postretirement health care plans and related funding requirements in the future. Further, our costs of providing such benefits and related funding requirements are also subject to a number of factors, including (i) changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years; (ii) various actuarial calculations and assumptions which may differ materially from actual results due primarily to changing market and economic conditions, including changes in interest rates, and higher or lower withdrawal rates; and (iii) future government regulation.

The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.

The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.

The average age of the employee base of Atmos Energy has been increasing for a number of years, with a number of employees becoming eligible to retire within the next five to 10 years. If we were unable to hire appropriate personnel to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from the increased use of contractors to replace retiring employees, loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

We may experience increased federal, state and local regulation of the safety of our operations.

The safety and protection of the public, our customers and our employees is our top priority. We constantly monitor and maintain our pipeline and distribution system to ensure that natural gas is delivered safely, reliably and efficiently through our network of more than 72,000 miles of pipeline and distribution lines. However, in recent years, natural gas distribution and pipeline companies have continued to face increasing federal, state and local oversight of the safety of their operations. Although we believe these costs should be ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results.

Some of our operations are subject to increased federal regulatory oversight that could affect our operations and financial results.

FERC has regulatory authority over some of our operations, including sales of natural gas in the wholesale gas market and the use and release of interstate pipeline and storage capacity. FERC has adopted rules designed to prevent market power abuse and market manipulation and to promote compliance with FERC’s other rules, policies and orders by companies engaged in the

16

sale, purchase, transportation or storage of natural gas in interstate commerce. These rules carry increased penalties for violations. Although we have taken steps to structure current and future transactions to comply with applicable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regulations issued by FERC in the future could also adversely affect our business, financial condition or financial results.

We are subject to environmental regulations which could adversely affect our operations or financial results.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could be significant to our financial results. In addition, existing environmental regulations may be revised or our operations may become subject to new regulations.

The operations and financial results of the Company could be adversely impacted as a result of climate changes or related additional legislation or regulation in the future.

To the extent climate changes occur, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity.  To the extent climate changes would result in warmer temperatures in our service territories, financial results could be adversely affected through lower gas volumes and revenues.  Such climate changes could also cause shifts in population, including customers moving away from our service territories near the Gulf Coast in Louisiana and Mississippi. 

Another possible climate change would be more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase our costs to repair damaged facilities and restore service to our customers.  If we were unable to deliver natural gas to our customers, our financial results would be impacted by lost revenues, and we generally would have to seek approval from regulators to recover restoration costs.  To the extent we would be unable to recover those costs, or if higher rates resulting from our recovery of such costs would result in reduced demand for our services, our future business, financial condition or financial results could be adversely impacted. 

In addition, there have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The adoption of this type of legislation by Congress or similar legislation by states or the adoption of related regulations by federal or state governments mandating a substantial reduction in greenhouse gas emissions in the future could have far-reaching and significant impacts on the energy industry. Such new legislation or regulations could result in increased compliance costs for us or additional operating restrictions on our business, affect the demand for natural gas or impact the prices we charge to our customers. At this time, we cannot predict the potential impact of such laws or regulations that may be adopted on our future business, financial condition or financial results.

Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.

Our regulated distribution and regulated pipeline businesses involve a number of hazards and operating risks that cannot be completely avoided, such as leaks, accidents and operational problems, which could cause loss of human life, as well as substantial financial losses resulting from property damage, damage to the environment and to our operations. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our pipeline, storage and distribution facilities are near or are in populated areas, any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected.

Cyber-attacks or acts of cyber-terrorism could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information.

Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our distribution and intrastate pipeline operations and other business processes. Disruption of those systems could adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline systems or serve our customers timely. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected.

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In addition, we use our information technology systems to protect confidential or sensitive customer, employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of customer, employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. Even though we have insurance coverage in place for many of these cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.

Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.

Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance covering such risks may become more limited, which could increase the risk that an event could adversely affect our operations or financial results.

ITEM 1B. Unresolved Staff Comments.

Not applicable.

ITEM 2. Properties.

Distribution, transmission and related assets

At September 30, 2016, in our regulated distribution segment, we owned an aggregate of 70,593 miles of underground distribution and transmission mains throughout our distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Through our regulated pipeline segment we owned 5,446 miles of gas transmission lines as well as 111 miles of transmission and gathering lines through our nonregulated segment.

Storage Assets

We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities at September 30, 2016:

State	Usable Capacity (Mcf)	Cushion Gas (Mcf)(1)	Total Capacity (Mcf)	Maximum Daily Delivery Capability (Mcf)
Regulated Distribution Segment
Kentucky	4,442,696	6,322,283	10,764,979	105,100
Kansas	3,239,000	2,300,000	5,539,000	45,000
Mississippi	1,907,571	2,442,917	4,350,488	31,000
Total	9,589,267	11,065,200	20,654,467	181,100
Regulated Pipeline Segment — Texas	46,083,549	15,878,025	61,961,574	1,235,000
Nonregulated Segment
Kentucky	3,438,900	3,240,000	6,678,900	67,500
Louisiana	438,583	300,973	739,556	56,000
Total	3,877,483	3,540,973	7,418,456	123,500
Total	59,550,299	30,484,198	90,034,497	1,539,600

⁽¹⁾  Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

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Additionally, we contract for storage service in underground storage facilities on many of the interstate and intrastate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2016:

Segment	Division/Company	Maximum Storage Quantity (MMBtu)	Maximum Daily Withdrawal Quantity (MDWQ)(1)
Regulated Distribution Segment
	Colorado-Kansas Division	5,261,909	118,889
	Kentucky/Mid-States Division	11,181,603	268,739
	Louisiana Division	2,595,619	179,347
	Mid-Tex Division	3,500,000	175,000
	Mississippi Division	3,554,535	151,334
	West Texas Division	4,500,000	146,000
Total		30,593,666	1,039,309
Nonregulated Segment
	Atmos Energy Marketing, LLC	8,026,869	250,937
	Trans Louisiana Gas Pipeline, Inc.	1,674,000	67,507
Total		9,700,869	318,444
Total Contracted Storage Capacity		40,294,535	1,357,753

⁽¹⁾  Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season.

Offices

Our administrative offices and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our service territory, the majority of which are located in leased facilities. The headquarters for our nonregulated operations are in Houston, Texas, with offices in Houston and other locations, primarily in leased facilities.

ITEM 3. Legal Proceedings.

See Note 11 to the consolidated financial statements, which is incorporated in this Item 3 by reference.

ITEM 4. Mine Safety Disclosures.

Not applicable.

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PART II

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our stock trades on the New York Stock Exchange under the trading symbol “ATO.” The high and low sale prices and dividends paid per share of our common stock for fiscal 2016 and 2015 are listed below. The high and low prices listed are the closing NYSE quotes, as reported on the NYSE composite tape, for shares of our common stock:

	Fiscal 2016						Fiscal 2015
	High		Low		Dividends Paid		High		Low		Dividends Paid
Quarter ended:
December 31	$	64.25	$	57.82	$	0.42	$	58.08	$	47.35	$	0.39
March 31	74.33		61.74		0.42		58.81		52.02		0.39
June 30	81.32		70.60		0.42		56.41		51.28		0.39
September 30	81.16		71.88		0.42		58.18		51.48		0.39
					$	1.68					$	1.56

Dividends are payable at the discretion of our Board of Directors out of legally available funds. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. The number of record holders of our common stock on October 31, 2016 was 14,108. Future payments of dividends, and the amounts of these dividends, will depend on our financial condition, results of operations, capital requirements and other factors. We sold no securities during fiscal 2016 that were not registered under the Securities Act of 1933, as amended.

Performance Graph

The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the S&P 500 Stock Index and the cumulative total return of a customized peer company group, the Comparison Company Index. The Comparison Company Index is comprised of natural gas distribution companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2011 in our common stock, the S&P 500 Index and in the common stock of the companies in the Comparison Company Index, as well as a reinvestment of dividends paid on such investments throughout the period.

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Comparison of Five-Year Cumulative Total Return

among Atmos Energy Corporation, S&P 500 Index

and Comparison Company Index

	Cumulative Total Return
	9/30/2011	9/30/2012	9/30/2013	9/30/2014	9/30/2015	9/30/2016
Atmos Energy Corporation	100.00	114.96	141.77	163.78	205.60	269.55
S&P 500 Index	100.00	130.20	155.39	186.05	184.91	213.44
Peer Group	100.00	117.20	137.59	161.70	179.33	232.91

The Comparison Company Index reflects the cumulative total return of companies in our peer group, which is comprised of a hybrid group of utility companies, primarily natural gas distribution companies, recommended by our independent executive compensation consulting firm and approved by the Board of Directors. The companies in our peer group are AGL Resources Inc.⁽¹⁾, CenterPoint Energy, Inc., CMS Energy Corporation, NiSource Inc., ONE Gas, Inc., Piedmont Natural Gas Company, Inc., Questar Corporation⁽¹⁾, TECO Energy, Inc.⁽¹⁾, Spire, Inc. (formerly The Laclede Group, Inc.), Vectren Corporation and WGL Holdings, Inc.

⁽¹⁾  AGL Resources Inc., Questar Corporation and TECO Energy, Inc. were acquired prior to September 30, 2016. As a result, the cumulative total return of these companies is not included in the Comparison Company Index represented in the graph above.

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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2016.

	Number of securities to be issued upon exercise of outstanding options, restricted stock units, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders:
1998 Long-Term Incentive Plan	1,338,162	(1)	$	—	2,359,106
Total equity compensation plans approved by security holders	1,338,162		—		2,359,106
Equity compensation plans not approved by security holders	—		—		—
Total	1,338,162		$	—	2,359,106

⁽¹⁾  Comprised of a total of 614,588 time-lapse restricted stock units, 326,249 director share units and 397,325 performance-based restricted stock units at the target level of performance granted under our 1998 Long-Term Incentive Plan.

On September 28, 2011, the Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a five-year period. The program expired on September 30, 2016 and will not be renewed. We did not repurchase any shares during fiscal 2016 under the program.

ITEM 6. Selected Financial Data.

The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein.

	Fiscal Year Ended September 30
	2016		2015		2014		2013		2012(1)
	(In thousands, except per share data)
Results of Operations
Operating revenues	$	3,349,949	$	4,142,136	$	4,940,916	$	3,875,460	$	3,436,162
Gross profit	$	1,744,896	$	1,680,017	$	1,582,426	$	1,412,050	$	1,323,739
Income from continuing operations	$	350,104	$	315,075	$	289,817	$	230,698	$	192,196
Net income	$	350,104	$	315,075	$	289,817	$	243,194	$	216,717
Diluted income per share from continuing operations	$	3.38	$	3.09	$	2.96	$	2.50	$	2.10
Diluted net income per share	$	3.38	$	3.09	$	2.96	$	2.64	$	2.37
Cash dividends declared per share	$	1.68	$	1.56	$	1.48	$	1.40	$	1.38
Financial Condition
Net property, plant and equipment(2)	$	8,280,511	$	7,430,580	$	6,725,906	$	6,030,655	$	5,475,604
Total assets	$	10,010,889	$	9,075,072	$	8,581,006	$	7,919,069	$	7,484,518
Capitalization:
Shareholders’ equity	$	3,463,059	$	3,194,797	$	3,086,232	$	2,580,409	$	2,359,243
Long-term debt (excluding current maturities)	2,188,779		2,437,515		2,442,288		2,440,472		1,945,148
Total capitalization	$	5,651,838	$	5,632,312	$	5,528,520	$	5,020,881	$	4,304,391

⁽¹⁾  Financial results for fiscal 2012 reflect a $5.3 million pre-tax loss for the impairment of certain assets.

⁽²⁾  Amounts shown for fiscal 2012 are net of assets held for sale.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

This section provides management’s discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors”. They should be considered in connection with evaluating forward-looking statements contained in this report or otherwise made by or on behalf of us since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

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

The statements contained in this Annual Report on Form 10-K 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; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; 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.

CRITICAL ACCOUNTING POLICIES

Our 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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from estimates.

Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. The accounting policies discussed below are both important to the presentation of our financial condition and results of operations and require management to make difficult, subjective or complex accounting estimates. Accordingly, these critical accounting policies are reviewed periodically by the Audit Committee of the Board of Directors.

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Regulation	Our regulated distribution and pipeline operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the United States. Accordingly, the financial results for these operations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts expected to be recovered or recognized are based upon historical experience and our understanding of the regulations. Discontinuing the application of this method of accounting for regulatory assets and liabilities or changes in the accounting for our various regulatory mechanisms could significantly increase our operating expenses as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income.	Decisions of regulatory authorities Issuance of new regulations or regulatory mechanisms Assessing the probability of the recoverability of deferred costs Continuing to meet the criteria of a cost-based, rate regulated entity for accounting purposes
Unbilled Revenue	We follow the revenue accrual method of accounting for regulated distribution segment revenues whereby revenues attributable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. On occasion, we are permitted to implement new rates that have not been formally approved by our regulatory authorities, which are subject to refund. We recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.	Estimates of delivered sales volumes based on actual tariff information and weather information and estimates of customer consumption and/or behavior Estimates of purchased gas costs related to estimated deliveries Estimates of uncollectible amounts billed subject to refund

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Pension and other postretirement plans	Pension and other postretirement plan costs and liabilities are determined on an actuarial basis using a September 30 measurement date and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net periodic pension and postretirement benefit plan costs. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds. The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan costs are not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs over a period of approximately ten to twelve years. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this methodology will delay the impact of current market fluctuations on the pension expense for the period. We estimate the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.	General economic and market conditions Assumed investment returns by asset class Assumed future salary increases Assumed discount rate Projected timing of future cash disbursements Health care cost experience trends Participant demographic information Actuarial mortality assumptions Impact of legislation Impact of regulation
Contingencies	In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to uncollectible receivables, lawsuits, claims made by third parties or the action of various regulatory agencies. We recognize these contingencies in our consolidated financial statements when we determine, based on currently available facts and circumstances it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure. Changes in the estimates related to contingencies could have a negative impact on our consolidated results of operations, cash flows or financial position. Our contingencies are further discussed in Note 11 to our consolidated financial statements.	Currently available facts Management’s estimate of future resolution

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Financial instruments and hedging activities	We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives for using financial instruments have been tailored to meet the needs of our regulated and nonregulated businesses. These objectives are more fully described in Note 13 to the consolidated financial statements. We record all of our financial instruments on the balance sheet at fair value as required by accounting principles generally accepted in the United States, with changes in fair value ultimately recorded in the income statement. The recognition of the changes in fair value of these financial instruments recorded in the income statement is contingent upon whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Our accounting elections for financial instruments and hedging activities utilized are more fully described in Note 13 to the consolidated financial statements. The criteria used to determine if a financial instrument meets the definition of a derivative and qualifies for hedge accounting treatment are complex and require management to exercise professional judgment. Further, as more fully discussed below, significant changes in the fair value of these financial instruments could materially impact our financial position, results of operations or cash flows. Finally, changes in the effectiveness of the hedge relationship could impact the accounting treatment.	Designation of contracts under the hedge accounting rules Judgment in the application of accounting guidance Assessment of the probability that future hedged transactions will occur Changes in market conditions and the related impact on the fair value of the hedged item and the associated designated financial instrument Changes in the effectiveness of the hedge relationship
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). The assets and liabilities we recognize at fair value are subject to potentially significant volatility based on numerous considerations including, but not limited to changes in commodity prices, interest rates, maturity and timing of settlement. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices) for determining fair value measurement, as permitted under current accounting standards. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed. We utilize models and other valuation methods to determine fair value when external sources are not available. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then-current market conditions. We believe the market prices and models used to value these financial instruments represent the best information available with respect to the market in which transactions involving these financial instruments are executed, the closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.	General economic and market conditions Volatility in underlying market conditions Maturity dates of financial instruments Creditworthiness of our counterparties Creditworthiness of Atmos Energy Impact of credit risk mitigation activities on the assessment of the creditworthiness of Atmos Energy and its counterparties

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Impairment assessments	We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstance indicate that such carrying values may not be recoverable, and at least annually for goodwill, as required by U.S. accounting standards. The evaluation of our goodwill balances and other long-lived assets or identifiable assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to the commodity prices, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge.	General economic and market conditions Projected timing and amount of future discounted cash flows Judgment in the evaluation of relevant data

RESULTS OF OPERATIONS

Overview

Atmos Energy Corporation strives to operate its businesses safely and reliably while delivering superior shareholder value. In recent years we have implemented rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. Additionally, we have significantly increased investments in the safety and reliability of our natural gas distribution and transmission infrastructure. This increased level of investment and timely recovery of these investments through our various regulatory mechanisms has resulted in increased earnings and operating cash flow in recent years.

This trend continued during fiscal 2016 as net income increased to $350.1 million, or $3.38 per diluted share for the year ended September 30, 2016, compared with net income of $315.1 million or $3.09 per diluted share in the prior year. The year-over-year increase largely reflects positive rate outcomes, which more than offset weather that was 25 percent warmer than the prior year and increased pipeline maintenance and integrity spending.

Capital expenditures for fiscal 2016 totaled $1,087.0 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transmission systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce regulatory lag to six months or less. Fiscal 2015 spending under these and other mechanisms enabled the Company to complete 20 regulatory filings during fiscal 2016 that should increase annual operating income from regulated operations by $122.5 million. We funded our capital expenditure program primarily through operating cash flows of $795.0 million, net short-term borrowings and the issuance of common stock, including the At-the-Market Equity Sales (ATM) Program described below.

As we continue to invest in the safety and reliability of our distribution and transmission systems, we expect our capital spending will increase in future periods. We intend to fund this level of investment through available operating cash flows, the issuance of long-term debt securities and, to a lesser extent, the issuance of equity. In order to strengthen our ability to meet our financing needs, we:

•Entered into an ATM equity distribution agreement in March 2016 under which we may issue and sell shares of our common stock, up to an aggregate offering price of $200 million. We issued 1.4 million shares of common stock and received $98.6 million in net proceeds under the ATM program in fiscal 2016.

• Executed in September 2016 a new three-year, $200 million multi-draw term loan agreement with a syndicate of three lenders. The term loan will be used to refinance existing indebtedness and for working capital, capital expenditures and other general corporate purposes.

•Amended our existing five-year $1.25 billion unsecured credit facility in October 2016, which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021. The amended facility also retains the $250 million accordion feature, which allows for an increase in the total committed loan amount to $1.75 billion.

On May 13, 2016, Standard & Poor’s Corporation upgraded our senior unsecured debt rating to A from A- and upgraded our short-term debt rating to A-1 from A-2, with a ratings outlook of stable, citing strong financial performance largely due to our ability to timely recover capital investments.

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On October 31, 2016, we announced the proposed sale of AEM to CenterPoint Energy Services, Inc. The transaction will include the transfer of approximately 800 delivered gas customers and AEM’s related asset optimization business at an all cash price of $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. The proceeds from the sale will be redeployed to fund infrastructure investment in the regulated business. Upon completion of the sale, we will have fully exited the nonregulated gas marketing business.

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 7.1 percent for fiscal 2017.

Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2016, 2015 and 2014.

	For the Fiscal Year Ended September 30
	2016		2015		2014
	(In thousands, except per share data)
Operating revenues	$	3,349,949	$	4,142,136	$	4,940,916
Gross profit	1,744,896		1,680,017		1,582,426
Operating expenses	1,076,878		1,048,622		971,077
Operating income	668,018		631,395		611,349
Interest charges	115,948		116,241		129,295
Income before income taxes	550,477		510,765		476,819
Net income(1)	$	350,104	$	315,075	$	289,817
Diluted net income per share(1)	$	3.38	$	3.09	$	2.96

⁽¹⁾  Unrealized gains/losses in our nonregulated operations during fiscal 2016, 2015 and 2014 increased/(decreased) net income by $0.7 million, $(1.5) million and $5.8 million, or $0.01, $(0.01) and $0.06 per diluted share.

Regulated operations contributed 95 percent, 95 percent and 89 percent to our consolidated net income for fiscal years 2016, 2015 and 2014. Our consolidated net income during the last three fiscal years was earned across our business segments as follows:

	For the Fiscal Year Ended September 30
	2016		2015		2014
	(In thousands)
Regulated distribution segment	$	232,370	$	204,813	$	171,585
Regulated pipeline segment	101,689		94,662		86,191
Nonregulated segment	16,045		15,600		32,041
Net income	$	350,104	$	315,075	$	289,817

See the following discussion regarding the results of operations for each of our business operating segments.

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 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. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy, progress towards implementing that strategy and recent ratemaking initiatives in more detail.

We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore the cost of gas typically does not have an impact on our gross profit as 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 include franchise fees and gross receipt taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenue is influenced by the cost of gas and the level of gas sales volumes. We record the tax expense as a

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component of taxes, other than income. Although changes in revenue related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.

Although the cost of gas typically does not have a direct impact on our gross profit, higher gas costs 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. Currently, gas cost risk has been mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.

During fiscal 2016, we completed 19 regulatory proceedings in our regulated distribution segment, which should result in a $81.8 million increase in annual operating income.

Review of Financial and Operating Results

Financial and operational highlights for our regulated distribution segment for the fiscal years ended September 30, 2016, 2015 and 2014 are presented below.

	For the Fiscal Year Ended September 30
	2016		2015			2014			2016 vs. 2015			2015 vs. 2014
	(In thousands, unless otherwise noted)
Gross profit	$	1,272,805	$	1,237,577		$	1,176,515		$	35,228		$	61,062
Operating expenses	833,221		817,428			791,947			15,793			25,481
Operating income	439,584		420,149			384,568			19,435			35,581
Miscellaneous income (expense)	455		(377		)	(381		)	832			4
Interest charges	79,404		84,132			94,918			(4,728		)	(10,786		)
Income before income taxes	360,635		335,640			289,269			24,995			46,371
Income tax expense	128,265		130,827			117,684			(2,562		)	13,143
Net Income	$	232,370	$	204,813		$	171,585		$	27,557		$	33,228
Consolidated regulated distribution sales volumes — MMcf	242,589		293,350			317,320			(50,761		)	(23,970		)
Consolidated regulated distribution transportation volumes — MMcf	133,378		135,972			134,483			(2,594		)	1,489
Total consolidated regulated distribution throughput — MMcf	375,967		429,322			451,803			(53,355		)	(22,481		)
Consolidated regulated distribution average cost of gas per Mcf sold	$	4.20	$	5.20		$	5.94		$	(1.00	)	$	(0.74	)

Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our regulated distribution segment increased 13 percent, primarily due to a $35.2 million increase in gross profit, partially offset by a $15.8 million increase in operating expenses. The year-to-date increase in gross profit primarily reflects:

• a $47.5 million net increase in rate adjustments. Our Mid-Tex Division accounted for $20.9 million of this increase. We also experienced increases in our Mississippi and West Texas Divisions.

• The impact of weather that was 25 percent warmer than the prior year, before adjusting for weather normalization mechanisms. Therefore, although sales volumes declined 17 percent, gross margin experienced just a $3.4 million decline from lower consumption.

• Customer growth, primarily in our Mid-Tex, Louisiana and Tennessee service areas, which contributed an incremental $6.6 million.

• a $15.4 million decrease in revenue-related taxes primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $16.1 million decrease in the related tax expense.

The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, was primarily due to pipeline maintenance and related activities and increased depreciation expense associated with increased capital investments.

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Net income for the year ended September 30, 2016 includes a $5.0 million income tax benefit for equity awards that vested during the current year as a result of adopting the new stock-based accounting guidance, as described in Note 2 to our consolidated financial statements.

Fiscal year ended September 30, 2015 compared with fiscal year ended September 30, 2014

Net income for our regulated distribution segment increased 19 percent, primarily due to a $61.1 million increase in gross profit, partially offset by a $25.5 million increase in operating expenses. The year-over-year increase in gross profit primarily reflects:

• a $70.6 million net increase in rate adjustments, primarily in our Mid-Tex, West Texas, Kentucky/Mid-States and Colorado-Kansas Divisions.

• a $4.5 million increase in transportation revenue.  Transportation volumes increased one percent due to increased economic activity experienced in our Kentucky/Mid-States Division and increased consumption in our West Texas Division due to colder than normal weather.

• a $10.5 million decrease in consumption associated with an eight percent decrease in sales volumes. Fiscal 2015 weather was ten percent warmer compared to fiscal 2014, before adjusting for weather normalization mechanisms.

• a $2.5 million decrease in revenue-related taxes primarily in our Mid-Tex Division.

The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, was primarily due to increased depreciation expense associated with increased capital investments and increased ad valorem and franchise taxes.

Interest charges decreased by $10.8 million, primarily due to replacing our $500 million unsecured 4.95% senior notes with $500 million of 4.125% 30-year unsecured senior notes on October 15, 2014.

The following table shows our operating income by regulated distribution division, in order of total rate base, for the fiscal years ended September 30, 2016, 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.

	For the Fiscal Year Ended September 30
	2016		2015		2014			2016 vs. 2015			2015 vs. 2014
	(In thousands)
Mid-Tex	$	211,578	$	197,559	$	187,265		$	14,019		$	10,294
Kentucky/Mid-States	62,413		59,233		55,968			3,180			3,265
Louisiana	52,223		51,001		56,648			1,222			(5,647		)
West Texas	41,322		37,180		29,250			4,142			7,930
Mississippi	37,559		34,333		28,473			3,226			5,860
Colorado-Kansas	31,998		28,720		28,077			3,278			643
Other	2,491		12,123		(1,113		)	(9,632		)	13,236
Total	$	439,584	$	420,149	$	384,568		$	19,435		$	35,581

Regulated Pipeline Segment

Our regulated pipeline segment consists of the pipeline and storage operations of APT. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT manages five underground storage reservoirs in Texas.

Our regulated pipeline segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in APT's service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve determine the market value for transportation services between those geographic areas.

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The results of APT are also significantly impacted by the natural gas requirements of the Mid-Tex Division because APT is the Mid-Tex Division's primary transporter of natural gas.

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

Review of Financial and Operating Results

Financial and operational highlights for our regulated pipeline segment for the fiscal years ended September 30, 2016, 2015 and 2014 are presented below.

	For the Fiscal Year Ended September 30
	2016			2015			2014			2016 vs. 2015			2015 vs. 2014
	(In thousands, unless otherwise noted)
Mid-Tex Division transportation	$	308,621		$	264,059		$	227,230		$	44,562		$	36,829
Third-party transportation	85,996			94,893			76,109			(8,897		)	18,784
Storage and park and lend services	3,783			3,575			5,344			208			(1,769		)
Other	10,433			7,585			9,776			2,848			(2,191		)
Gross profit	408,833			370,112			318,459			38,721			51,653
Operating expenses	209,399			188,845			145,640			20,554			43,205
Operating income	199,434			181,267			172,819			18,167			8,448
Miscellaneous expense	(1,683		)	(1,243		)	(3,181		)	(440		)	1,938
Interest charges	36,574			33,151			36,280			3,423			(3,129		)
Income before income taxes	161,177			146,873			133,358			14,304			13,515
Income tax expense	59,488			52,211			47,167			7,277			5,044
Net income	$	101,689		$	94,662		$	86,191		$	7,027		$	8,471
Gross pipeline transportation volumes — MMcf	677,001			738,532			714,464			(61,531		)	24,068
Consolidated pipeline transportation volumes — MMcf	505,188			528,068			493,360			(22,880		)	34,708

Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our regulated pipeline segment increased seven percent, primarily due to a $38.7 million increase in gross profit, partially offset by a $20.6 million increase in operating expenses. The increase in gross profit primarily reflects a $39.6 million increase in rates from the approved 2015 and 2016 Gas Reliability Infrastructure Program (GRIP) filings. Additionally, gross profit reflects a $3.6 million increase from the sale of excess retention gas, which was offset by a $4.0 million decrease in through-system volumes and lower storage and blending fees due to warmer weather in the current year compared to the prior year.

Operating expenses increased $20.6 million, primarily due to increased levels of pipeline maintenance activities to improve the safety and reliability of our system and increased property taxes and depreciation expense associated with increased capital investments.

Fiscal year ended September 30, 2015 compared with fiscal year ended September 30, 2014

Net income for our regulated pipeline segment increased 10 percent, primarily due to a $51.7 million increase in gross profit, partially offset by a $43.2 million increase in operating expenses. The increase in gross profit primarily reflects a $47.0 million increase in rates from the approved 2014 and 2015 GRIP filings. Additionally, gross profit reflects increased pipeline demand fees and through-system transportation volumes and rates that were offset by lower park and lend, storage and blending fees and the absence of a $1.8 million increase recorded in the fiscal 2014 associated with the renewal of an annual adjustment mechanism.

Operating expenses increased $43.2 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, along with the absence of a $6.7 million refund received in fiscal 2014 as a result of the completion of a state use tax audit.

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Nonregulated Segment

Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and typically represent 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.

Further, natural gas market conditions, most notably the price of natural gas and the level of price volatility, affect our nonregulated businesses. Natural gas prices and the level of volatility are influenced by a number of factors including, but not limited to, general economic conditions, the demand for natural gas in different parts of the country, domestic natural gas production and natural gas inventory levels.

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.

• 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 amount of interest expense recognized by this segment.

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

• Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access.

• Increased or decreased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.

Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

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Review of Financial and Operating Results

Financial and operational highlights for our nonregulated segment for the fiscal years ended September 30, 2016, 2015 and 2014 are presented below.

	For the Fiscal Year Ended September 30
	2016		2015			2014		2016 vs. 2015			2015 vs. 2014
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	46,664	$	48,930		$	39,529	$	(2,266	)	$	9,401
Storage and transportation services	13,395		13,575			14,696		(180		)	(1,121		)
Other	2,470		12,755			24,170		(10,285		)	(11,415		)
Total realized margins	62,529		75,260			78,395		(12,731		)	(3,135		)
Unrealized margins	1,261		(2,400		)	9,560		3,661			(11,960		)
Gross profit	63,790		72,860			87,955		(9,070		)	(15,095		)
Operating expenses	34,790		42,881			33,993		(8,091		)	8,888
Operating income	29,000		29,979			53,962		(979		)	(23,983		)
Miscellaneous income (expense)	1,443		(760		)	2,216		2,203			(2,976		)
Interest charges	1,778		967			1,986		811			(1,019		)
Income before income taxes	28,665		28,252			54,192		413			(25,940		)
Income tax expense	12,620		12,652			22,151		(32		)	(9,499		)
Net income	$	16,045	$	15,600		$	32,041	$	445		$	(16,441	)
Gross nonregulated delivered gas sales volumes — MMcf	387,379		410,044			439,014		(22,665		)	(28,970		)
Consolidated nonregulated delivered gas sales volumes — MMcf	341,597		351,427			377,441		(9,830		)	(26,014		)
Net physical position (Bcf)	19.2		14.6			9.3		4.6			5.3

Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our nonregulated segment increased 3 percent compared to the prior year due to both lower gross profit and lower operating expenses.

The $9.1 million period-over-period decrease in gross profit was primarily due to a $12.7 million decrease in realized margins combined with a $3.7 million increase in unrealized margins. The decrease in realized margins reflects:

• A $10.3 million decrease in other realized margins. As a result of warmer weather, we modified storage positions to meet customer needs throughout the winter and captured less favorable spread values on the related supply repurchases.  Additionally, we experienced an increase in storage demand fees related primarily to higher park and loan activity.

• A $2.3 million decrease in gas delivery and related services margins, primarily due to a three percent decrease in consolidated sales volumes due to warmer weather. However, lower net transportation costs and other variable costs driven by fewer deliveries resulted in per-unit margins of 12 cents per Mcf, which is consistent with prior year per-unit margins.

Operating expenses decreased $8.1 million, primarily due to lower administrative expenses.

Fiscal year ended September 30, 2015 compared with fiscal year ended September 30, 2014

Net income for our nonregulated segment decreased 51 percent from compared to fiscal 2014 due to lower gross profit and higher operating expenses.

The $15.1 million year-over-year decrease in gross profit was primarily due to a $12.0 million decrease in unrealized margins combined with a $3.1 million decrease in realized margins. The decrease in realized margins reflects:

• An $11.4 million decrease in other realized margins primarily due to lower natural gas price volatility. In fiscal 2014, strong market demand caused by significantly colder-than-normal weather resulted in increased market volatility. These market conditions created the opportunity to accelerate physical withdrawals that had been planned for future periods in the fiscal 2014 second quarter to capture incremental gross profit margin. Market conditions in fiscal 2015 were less volatile than fiscal 2014, which provided fewer opportunities to capture incremental gross profit.

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• A $9.4 million increase in gas delivery and related services margins, primarily due to an increase in per-unit margins from 9 cents to 12 cents per Mcf, partially offset by a seven percent decrease in consolidated sales volumes. AEH elected not to renew excess transportation capacity in certain markets in late fiscal 2014 and early fiscal 2015. As a result, AEH experienced fewer deliveries to low-margin marketing and power generation customers during fiscal 2015, which was the primary driver for the decrease in consolidated sales volumes and higher per-unit margins.

Operating expenses increased $8.9 million, primarily due to higher legal expenses as a result of the favorable settlement in fiscal 2014 of the Kentucky litigation and the resolution of the Tennessee Business License Tax matter.

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 as well as 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 and (ii) maintain a balanced capital structure with a debt-to-capitalization ratio in a target range of 45 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of committed capacity from our short-term facilities.

As we continue to invest in the safety and reliability of our distribution and transportation system, we expect our capital spending will increase. We intend to fund this additional investment through available operating cash flows, the issuance of long-term debt securities and, to a lesser extent, the issuance of equity. We believe the liquidity provided by these sources combined with our committed credit facilities will be sufficient to fund our working capital needs and capital expenditure program for fiscal year 2017 and beyond.

To support our capital market activities, we filed a registration statement with the SEC on March 28, 2016 to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. On March 28, 2016, we entered into an ATM equity distribution agreement under which we may issue and sell, shares of our common stock, up to an aggregate offering price of $200 million. The shares will be issued under our shelf registration statement. Proceeds from the ATM program will be used primarily to repay short-term debt outstanding under our $1.25 billion commercial paper program, to fund capital spending primarily to enhance the safety and reliability of our system and for general corporate purposes. During fiscal 2016, we issued 1.4 million shares of common stock and received $98.6 million in net proceeds under the ATM program. At September 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.

On September 22, 2016, we entered into a three year, $200 million multi-draw term loan agreement with a syndicate of three lenders. The term loan will be used to refinance existing indebtedness and for working capital, capital expenditures and other general corporate purposes. At September 30, 2016, there were no borrowings under the term loan. On October 5, 2016, we amended our existing five-year $1.25 billion credit facility, which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021. The amended facility also retains the $250 million accordion feature, which allows for an increase in the total committed loan amount to $1.75 billion.

Additionally, we plan to issue new unsecured senior notes to replace $250 million and $450 million of unsecured senior notes that will mature in fiscal 2017 and fiscal 2019. During fiscal 2014 and 2015, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated fiscal 2019 issuances at 3.782%. In fiscal 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated fiscal 2017 issuances at 3.367%.

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The following table presents our capitalization as of September 30, 2016 and 2015:

	September 30
	2016				2015
	(In thousands, except percentages)
Short-term debt	$	829,811	12.3	%	$	457,927	7.5	%
Long-term debt(1)	2,438,779		36.2	%	2,437,515		40.0	%
Shareholders’ equity	3,463,059		51.5	%	3,194,797		52.5	%
Total capitalization, including short-term debt	$	6,731,649	100.0	%	$	6,090,239	100.0	%

⁽¹⁾  Net of $17.0 million and $17.9 million of unamortized debt issuance costs which were reclassified from deferred charges and other assets to long-term debt on the September 30, 2016 and 2015 consolidated balance sheets, as discussed in Note 2.

Cash Flows

Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our services, the 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 years ended September 30, 2016, 2015 and 2014 are presented below.

	For the Fiscal Year Ended September 30
	2016			2015			2014			2016 vs. 2015			2015 vs. 2014
	(In thousands)
Total cash provided by (used in)
Operating activities	$	794,990		$	811,914		$	732,813		$	(16,924	)	$	79,101
Investing activities	(1,079,732		)	(956,602		)	(824,979		)	(123,130		)	(131,623		)
Financing activities	303,623			131,083			68,225			172,540			62,858
Change in cash and cash equivalents	18,881			(13,605		)	(23,941		)	32,486			10,336
Cash and cash equivalents at beginning of period	28,653			42,258			66,199			(13,605		)	(23,941		)
Cash and cash equivalents at end of period	$	47,534		$	28,653		$	42,258		$	18,881		$	(13,605	)

Cash flows from operating activities

Year-over-year changes in our operating cash flows primarily are attributable to changes in net income, 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.

Fiscal Year ended September 30, 2016 compared with fiscal year ended September 30, 2015

For the fiscal year ended September 30, 2016, we generated operating cash flows of $795.0 million compared with $811.9 million in the prior year. The year-over-year decrease primarily reflects the timing of deferred gas cost recoveries.

Fiscal Year ended September 30, 2015 compared with fiscal year ended September 30, 2014

For the fiscal year ended September 30, 2015, we generated operating cash flows of $811.9 million compared with $732.8 million in fiscal 2014. The year-over-year increase primarily reflects successful rate case outcomes in fiscal 2014, the timing of gas cost recoveries under our purchased gas cost mechanisms and lower gas prices during the fiscal 2015 storage injection season.

Cash flows from investing activities

In recent years, we have used substantial amounts of cash 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.

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

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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.

For the fiscal year ended September 30, 2016, we incurred $1,087.0 million for capital expenditures compared with $963.6 million for the fiscal year ended September 30, 2015 and $824.4 million for the fiscal year ended September 30, 2014.

Fiscal Year ended September 30, 2016 compared with fiscal year ended September 30, 2015

The $123.4 million increase in capital expenditures in fiscal 2016 compared to fiscal 2015 primarily reflects:

• A $69.5 million increase in capital spending in our regulated distribution segment, which reflects the repair and replacement of our transmission and distribution pipelines as part of a planned increase in safety and reliability investment in fiscal 2016, the installation and replacement of measurement and regulating equipment and other pipeline integrity projects.

• A $54.8 million increase in capital spending in our regulated pipeline segment, primarily related to the enhancement and fortification of two storage fields to ensure the reliability of gas service to our Mid-Tex Division.

Fiscal Year ended September 30, 2015 compared with fiscal year ended September 30, 2014

The $139.2 million increase in capital expenditures in fiscal 2015 compared to fiscal 2014 primarily reflects:

• A $96.2 million increase in capital spending in our regulated distribution segment, which primarily reflects a planned increase in safety and reliability investment in fiscal 2015.

• A $43.4 million increase in capital spending in our regulated pipeline segment, primarily related to the enhancement and fortification of two storage fields to ensure the reliability of gas service to our Mid-Tex Division.

Cash flows from financing activities

We generated a net $303.6 million, $131.1 million and $68.2 million in cash from financing activities for fiscal years 2016, 2015 and 2014. Our significant financing activities for the fiscal years ended September 30, 2016, 2015 and 2014 are summarized as follows:

2016

During the fiscal year ended September 30, 2016, our financing activities generated $303.6 million of cash compared with $131.1 million of cash generated in the prior year. The increase is primarily due to higher net short-term borrowings due to increased capital expenditures and period-over-period changes in working capital funding needs compared to the prior year, as well as proceeds received from the issuance of common stock under our ATM program in the third fiscal quarter of 2016.

2015

During the fiscal year ended September 30, 2015, our financing activities generated $131.1 million of cash compared with $68.2 million of cash generated in fiscal 2014. The increase is primarily due to timing between short-term debt borrowings and repayments during fiscal 2015, proceeds from the issuance of $500 million unsecured 4.125% senior notes in October 2014 and the settlement of the associated forward starting interest rate swaps. Partially offsetting these increases were the repayment of $500 million 4.95% senior unsecured notes at maturity on October 15, 2014, compared with short-term debt borrowings and repayments in fiscal 2014 and proceeds generated from the equity offering completed in February 2014.

2014

During the fiscal year ended September 30, 2014, our financing activities generated $68.2 million of cash compared with $85.7 million of cash generated in fiscal 2013. The decrease is primarily due to timing between short-term debt borrowings and repayments during fiscal 2014, partially offset by proceeds from the equity offering completed in February 2014 compared with proceeds generated from the issuance of long-term debt in fiscal 2013.

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The following table shows the number of shares issued for the fiscal years ended September 30, 2016, 2015 and 2014:

	For the Fiscal Year Ended September 30
	2016	2015	2014
Shares issued:
Direct Stock Purchase Plan	133,133	176,391	83,150
Retirement Savings Plan	359,414	398,047	—
1998 Long-Term Incentive Plan	598,439	664,752	653,130
Outside Directors Stock-For-Fee Plan	—	—	1,735
February 2014 Offering	—	—	9,200,000
At-the-Market (ATM) Equity Sales Program	1,360,756	—	—
Total shares issued	2,451,742	1,239,190	9,938,015

The increase in the number of shares issued in fiscal 2016 compared with the number of shares issued in fiscal 2015 primarily reflects shares issued under the ATM program. At September 30, 2016, of the 11.2 million shares authorized for issuance from the LTIP, 2,359,106 shares remained available.

The decrease in the number of shares issued in fiscal 2015 compared with the number of shares issued in fiscal 2014 primarily reflects the equity offering completed in February 2014, partially offset by the fact that we began issuing shares for use by the Direct Stock Purchase Plan and the Retirement Savings Plan and Trust rather than using shares purchased in the open market. For the year ended September 30, 2015, we canceled and retired 148,464 shares attributable to federal income tax withholdings on equity awards which are not included in the table above.

Credit Facilities

Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements.

As of September 30, 2016, we financed 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 a total availability from third-party lenders of approximately $1.3 billion of working capital funding. On October 5, 2016, we amended our existing $1.25 billion unsecured credit facility which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021. The amended facility also retains the $250 million accordion feature, which provides the opportunity to increase the total committed loan amount to $1.75 billion.We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.

Shelf Registration

On March 28, 2016, we filed a registration statement with the SEC that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. At September 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.

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 environment 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). On May 13, 2016, S&P upgraded our senior unsecured debt rating to A from A- and upgraded our short-term debt rating to A-1 from A-2, with a ratings outlook of stable, citing strong financial performance largely due to our ability to timely recover capital investments. As of September 30, 2016, all three rating agencies maintained a stable outlook.

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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
Short-term debt	A-1	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 September 30, 2016. Our debt covenants are described in Note 5 to the consolidated financial statements.

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Contractual Obligations and Commercial Commitments

The following table provides information about contractual obligations and commercial commitments at September 30, 2016.

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
					(In thousands)
Contractual Obligations
Long-term debt(1)	$	2,460,000	$	250,000	$	450,000	$	—	$	1,760,000
Short-term debt(1)	829,811		829,811		—		—		—
Interest charges(2)	2,112,610		135,518		227,809		172,134		1,577,149
Operating leases(3)	125,875		17,073		32,274		28,814		47,714
Demand fees for contracted storage(4)	6,670		4,865		1,590		215		—
Demand fees for contracted transportation(5)	6,560		4,200		1,170		512		678
Financial instrument obligations(6)	240,819		56,771		184,048		—		—
Pension and postretirement benefit plan contributions(7)	407,359		52,410		62,497		83,377		209,075
Uncertain tax positions (including interest)(8)	20,298		—		20,298		—		—
Total contractual obligations	$	6,210,002	$	1,350,648	$	979,686	$	285,052	$	3,594,616

⁽¹⁾  See Note 5 to the consolidated financial statements.

⁽²⁾  Interest charges were calculated using the effective rate for each debt issuance.

⁽³⁾  See Note 10 to the consolidated financial statements.

⁽⁴⁾  Represents third party contractual demand fees for contracted storage in our nonregulated segment. Contractual demand fees for contracted storage for our regulated distribution segment are excluded as these costs are fully recoverable through our purchase gas adjustment mechanisms.

⁽⁵⁾  Represents third party contractual demand fees for transportation in our nonregulated segment.

⁽⁶⁾  Represents liabilities for natural gas commodity and interest rate financial instruments that were valued as of September 30, 2016. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled.

⁽⁷⁾  Represents expected contributions to our pension and postretirement benefit plans, which are discussed in Note 7 to the consolidated financial statements.

⁽⁸⁾  Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax returns.

Our regulated distribution segment maintains 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 individual contracts. 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 market and fixed prices. At September 30, 2016, we were committed to purchase 28.5 Bcf within one year, 4.2 Bcf within two to three years and 0.6 Bcf after three years under indexed contracts.

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2016, AEH was committed to purchase 93.5 Bcf within one year, 9.1 Bcf within two to three years and 0.2 Bcf after three years under indexed contracts. AEH is committed to purchase 11.9 Bcf within one year and 1.3 Bcf within two to three years under fixed price contracts with prices ranging from $0.25 to $3.16 per Mcf.

Risk Management Activities

As discussed above in our Critical Accounting Policies, we use financial instruments to mitigate commodity price risk and, periodically, to manage interest rate risk. 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. In our nonregulated segments, 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

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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 marked to market through earnings.

We record our financial instruments as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. Substantially all of our financial instruments are valued using external market quotes and indices.

The following table shows the components of the change in fair value of our regulated distribution segment’s financial instruments for the fiscal year ended September 30, 2016 (in thousands):

Fair value of contracts at September 30, 2015	$	(119,361	)
Contracts realized/settled	(20,847		)
Fair value of new contracts	4,811
Other changes in value	(126,241		)
Fair value of contracts at September 30, 2016	(261,638		)
Netting of cash collateral	25,670
Cash collateral and fair value of contracts at September 30, 2016	$	(235,968	)

The fair value of our regulated distribution segment’s financial instruments at September 30, 2016, is presented below by time period and fair value source:

	Fair Value of Contracts at September 30, 2016
	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	$	(65,452	)	$	(196,186	)	$	—	$	—	$	(261,638	)
Prices based on models and other valuation methods	—			—			—		—		—
Total Fair Value	$	(65,452	)	$	(196,186	)	$	—	$	—	$	(261,638	)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the fiscal year ended September 30, 2016 (in thousands):

Fair value of contracts at September 30, 2015	$	(34,620	)
Contracts realized/settled	25,958
Fair value of new contracts	—
Other changes in value	(9,243		)
Fair value of contracts at September 30, 2016	(17,905		)
Netting of cash collateral	24,680
Cash collateral and fair value of contracts at September 30, 2016	$	6,775

The fair value of our nonregulated segment’s financial instruments at September 30, 2016, is presented below by time period and fair value source:

	Fair Value of Contracts at September 30, 2016
	Maturity in years
Source of Fair Value	Less than 1			1-3			4-5			Greater than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(15,946	)	$	(1,418	)	$	(541	)	$	—	$	(17,905	)
Prices based on models and other valuation methods	—			—			—			—		—
Total Fair Value	$	(15,946	)	$	(1,418	)	$	(541	)	$	—	$	(17,905	)

40

Employee Benefits Programs

An important element of our total compensation program, and a significant component of our operation and maintenance expense, is the offering of various benefits programs to our employees. These programs include medical and dental insurance coverage and pension and postretirement programs.

Medical and Dental Insurance

We offer medical and dental insurance programs to substantially all of our employees.We believe these programs are compliant with all current and future provisions that will be going into effect under The Patient Protection and Affordable Care Act and consistent with other programs in our industry. In recent years, we have endeavored to actively manage our health care costs through the introduction of a wellness strategy that is focused on helping employees to identify health risks and to manage these risks through improved lifestyle choices.

Over the last five fiscal years, we have experienced annual medical and prescription inflation of approximately six percent. For fiscal 2017, we anticipate the medical and prescription drug inflation rate will continue at approximately six percent, primarily due to the inflation of health care costs.

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2016, our total net periodic pension and other benefits costs was $46.0 million, compared with $58.9 million and $69.8 million for the fiscal years ended September 30, 2015 and 2014. These costs relating to our regulated distribution operations are recoverable through our distribution rates. A portion of these costs is capitalized into our distribution rate base, and 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. At that date, 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 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. As a result of the net impact of these and other assumptions, our fiscal 2016 pension and postretirement medical costs were approximately 20 percent lower than in the prior year.

Our fiscal 2015 costs were determined using a September 30, 2014 measurement date. At that date, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2013, the measurement date for our fiscal 2014 net periodic cost. Therefore, we decreased the discount rate used to measure our fiscal 2015 net periodic cost from 4.95 percent to 4.43 percent. We maintained our expected return on plan assets at 7.25 percent in the determination of our fiscal 2015 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of these and other assumptions, our fiscal 2015 pension and postretirement medical costs were lower than in the prior year.

Pension and Postretirement Plan Funding

Generally, our funding policy is to contribute annually an amount that will at least equal the minimum amount required to comply with the Employee Retirement Income Security Act of 1974 (ERISA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

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 this valuation, we contributed cash of $15.0 million, $38.0 million and $27.1 million to our pension plans during fiscal 2016, 2015 and 2014. Each contribution increased the level of our plan assets to achieve a desired PPA funding threshold.

We contributed $16.6 million, $20.0 million and $23.6 million to our postretirement benefits plans for the fiscal years ended September 30, 2016, 2015 and 2014. The contributions represent the portion of the postretirement costs we are responsible for under the terms of our plan and minimum funding required by state regulatory commissions.

Outlook for Fiscal 2017 and Beyond

As of September 30, 2016, interest and corporate bond rates were lower than the rates as of September 30, 2015. Therefore, we decreased the discount rate used to measure our fiscal 2017 net periodic cost from 4.55 percent to 3.73 percent. We maintained the expected return on plan assets of 7.00 percent in the determination of our fiscal 2017 net periodic pension cost based upon expected market returns for our targeted asset allocation. On October 20, 2016, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the

41

updated mortality table. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2017 net periodic pension cost to be consistent with fiscal 2016.

Based upon current market conditions, the current funded position of the plans and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2017. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels. With respect to our postretirement medical plans, we anticipate contributing between $10 million and $20 million during fiscal 2017.

Actual changes in the fair market value of plan assets and differences between the actual and expected return on plan assets could have a material effect on the amount of pension costs ultimately recognized. A 0.25 percent change in our discount rate would impact our pension and postretirement costs by approximately $2.9 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $1.3 million.

The projected liability, future funding requirements and the amount of expense or income recognized for each of our pension and other post-retirement benefit plans are subject to change, depending on the actuarial value of plan assets, and the determination of future benefit obligations as of each subsequent calculation date.  These amounts are impacted by actual investment returns, changes in interest rates, changes in the demographic composition of the participants in the plans and other actuarial assumptions. 

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 consolidated financial statements.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest-rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business activities.

We conduct risk management activities through both 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 protect us and our customers against unusually large winter period gas price increases. In our nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our risk management activities and related accounting treatment are described in further detail in Note 13 to the consolidated financial statements. Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper and our other short-term borrowings.

Commodity Price Risk

Regulated distribution segment

We purchase natural gas for our regulated distribution operations. Substantially all of the costs of gas purchased for regulated distribution operations are recovered from our customers through purchased gas cost adjustment mechanisms. Therefore, our regulated distribution operations have limited commodity price risk exposure.

Nonregulated segment

Our nonregulated segment is also exposed to risks associated with changes in the market price of natural gas. For our nonregulated segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open position (including existing storage and related financial contracts) at the end of each period. Based on AEH’s net open position (including existing storage and related financial contracts) at September 30, 2016 of 0.1 Bcf, a $0.50 change in the forward NYMEX price would have had an impact of less than $0.1 million on our consolidated net income.

Changes in the difference between the indices used to mark to market our physical inventory (Gas Daily) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income; but, over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges. Based upon our net physical position at September 30, 2016 and assuming our hedges would still qualify as highly effective, a $0.50 change in the difference between the Gas Daily and NYMEX indices would impact our reported net income by approximately $5.9 million.

Additionally, these changes could cause us to recognize a risk management liability, which would require us to place cash into an escrow account to collateralize this liability position. This, in turn, would reduce the amount of cash we would have on hand to fund our working capital needs.

42

Interest Rate Risk

Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings increased by an average of one percent, our interest expense would have increased by approximately $6.4 million during 2016.

43

ITEM 8. Financial Statements and Supplementary Data.

Index to financial statements and financial statement schedule:

	Page
Report of independent registered public accounting firm	45
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2016 and 2015	46
Consolidated statements of income for the years ended September 30, 2016, 2015 and 2014	47
Consolidated statements of comprehensive income for the years ended September 30, 2016, 2015 and 2014	48
Consolidated statements of shareholders' equity for the years ended September 30, 2016, 2015 and 2014	49
Consolidated statements of cash flow for the years ended September 30, 2016, 2015 and 2014	50
Notes to consolidated financial statements	51
Selected Quarterly Financial Data (Unaudited)	97
Financial statement schedule for the years ended September 30, 2016, 2015 and 2014
Schedule II. Valuation and Qualifying Accounts	105

All other financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements and accompanying notes thereto.

44

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2016. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Atmos Energy Corporation at September 30, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the financial statements taken as a whole, presents fairly, in all material respects the financial information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 14, 2016 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Dallas, Texas

November 14, 2016

45

ATMOS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	September 30
	2016			2015
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	9,987,078		$	8,959,702
Construction in progress	184,062			280,398
	10,171,140			9,240,100
Less accumulated depreciation and amortization	1,890,629			1,809,520
Net property, plant and equipment	8,280,511			7,430,580
Current assets
Cash and cash equivalents	47,534			28,653
Accounts receivable, less allowance for doubtful accounts of $13,367 in 2016 and $15,283 in 2015	300,007			295,160
Gas stored underground	233,316			236,603
Other current assets	100,829			65,890
Total current assets	681,686			626,306
Goodwill	743,407			742,702
Deferred charges and other assets	305,285			275,484
	$	10,010,889		$	9,075,072
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2016 — 103,930,560 shares, 2015 — 101,478,818 shares	$	520		$	507
Additional paid-in capital	2,388,027			2,230,591
Accumulated other comprehensive loss	(188,022		)	(109,330		)
Retained earnings	1,262,534			1,073,029
Shareholders’ equity	3,463,059			3,194,797
Long-term debt	2,188,779			2,437,515
Total capitalization	5,651,838			5,632,312
Commitments and contingencies
Current liabilities
Accounts payable and accrued liabilities	259,434			238,942
Other current liabilities	449,036			457,954
Short-term debt	829,811			457,927
Current maturities of long-term debt	250,000			—
Total current liabilities	1,788,281			1,154,823
Deferred income taxes	1,603,056			1,411,315
Regulatory cost of removal obligation	424,281			427,553
Pension and postretirement liabilities	297,743			287,373
Deferred credits and other liabilities	245,690			161,696
	$	10,010,889		$	9,075,072

See accompanying notes to consolidated financial statements.

46

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended September 30
	2016			2015			2014
	(In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	2,291,866		$	2,763,835		$	3,061,546
Regulated pipeline segment	408,833			370,112			318,459
Nonregulated segment	1,066,363			1,472,209			2,067,292
Intersegment eliminations	(417,113		)	(464,020		)	(506,381		)
	3,349,949			4,142,136			4,940,916
Purchased gas cost
Regulated distribution segment	1,019,061			1,526,258			1,885,031
Regulated pipeline segment	—			—			—
Nonregulated segment	1,002,573			1,399,349			1,979,337
Intersegment eliminations	(416,581		)	(463,488		)	(505,878		)
	1,605,053			2,462,119			3,358,490
Gross profit	1,744,896			1,680,017			1,582,426
Operating expenses
Operation and maintenance	560,766			541,868			505,154
Depreciation and amortization	293,096			274,796			253,987
Taxes, other than income	223,016			231,958			211,936
Total operating expenses	1,076,878			1,048,622			971,077
Operating income	668,018			631,395			611,349
Miscellaneous expense, net	(1,593		)	(4,389		)	(5,235		)
Interest charges	115,948			116,241			129,295
Income before income taxes	550,477			510,765			476,819
Income tax expense	200,373			195,690			187,002
Net income	$	350,104		$	315,075		$	289,817
Basic net income per share	$	3.38		$	3.09		$	2.96
Diluted net income per share	$	3.38		$	3.09		$	2.96
Weighted average shares outstanding:
Basic	103,524			101,892			97,606
Diluted	103,524			101,892			97,608

See accompanying notes to consolidated financial statements.

47

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended September 30
	2016			2015			2014
	(In thousands)
Net income	$	350,104		$	315,075		$	289,817
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(245), $(1,559) and $1,199	(465		)	(2,713		)	2,214
Cash flow hedges:
Amortization and unrealized loss on interest rate agreements, net of tax of $(56,723), $(40,501) and $(32,353)	(98,682		)	(70,461		)	(56,287		)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $13,078, $(15,193) and $1,791	20,455			(23,763		)	2,802
Total other comprehensive loss	(78,692		)	(96,937		)	(51,271		)
Total comprehensive income	$	271,412		$	218,138		$	238,546

See accompanying notes to consolidated financial statements.

48

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Common stock					Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	Number of Shares		Stated Value
	(In thousands, except share and per share data)
Balance, September 30, 2013	90,640,211		$	453		$	1,765,811		$	38,878		$	775,267		$	2,580,409
Net income	—		—			—			—			289,817			289,817
Other comprehensive loss	—		—			—			(51,271		)	—			(51,271		)
Repurchase of equity awards	(190,134	)	(1		)	(8,716		)	—			—			(8,717		)
Cash dividends ($1.48 per share)	—		—			—			—			(146,248		)	(146,248		)
Common stock issued:
Public offering	9,200,000		46			390,159			—			—			390,205
Direct stock purchase plan	83,150		1			4,066			—			—			4,067
1998 Long-term incentive plan	653,130		3			5,214			—			(864		)	4,353
Employee stock-based compensation	—		—			23,536			—			—			23,536
Outside directors stock-for-fee plan	1,735		—			81			—			—			81
Balance, September 30, 2014	100,388,092		502			2,180,151			(12,393		)	917,972			3,086,232
Net income	—		—			—			—			315,075			315,075
Other comprehensive loss	—		—			—			(96,937		)	—			(96,937		)
Repurchase of equity awards	(148,464	)	(1		)	(7,984		)	—			—			(7,985		)
Cash dividends ($1.56 per share)	—		—			—			—			(160,018		)	(160,018		)
Common stock issued:
Direct stock purchase plan	176,391		1			10,625			—			—			10,626
Retirement savings plan	398,047		2			20,324			—			—			20,326
1998 Long-term incentive plan	664,752		3			2,263			—			—			2,266
Employee stock-based compensation	—		—			25,212			—			—			25,212
Balance, September 30, 2015	101,478,818		507			2,230,591			(109,330		)	1,073,029			3,194,797
Net income	—		—			—			—			350,104			350,104
Other comprehensive loss	—		—			—			(78,692		)	—			(78,692		)
Cash dividends ($1.68 per share)	—		—			—			—			(175,126		)	(175,126		)
Cumulative effect of accounting change	—		—			—			—			14,527			14,527
Common stock issued:
Public offering	1,360,756		7			98,567			—			—			98,574
Direct stock purchase plan	133,133		1			9,228			—			—			9,229
Retirement savings plan	359,414		2			25,047			—			—			25,049
1998 Long-term incentive plan	598,439		3			3,175			—			—			3,178
Employee stock-based compensation	—		—			21,419			—			—			21,419
Balance, September 30, 2016	103,930,560		$	520		$	2,388,027		$	(188,022	)	$	1,262,534		$	3,463,059

See accompanying notes to consolidated financial statements.

49

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended September 30
	2016			2015			2014
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	350,104		$	315,075		$	289,817
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	293,096			274,796			253,987
Deferred income taxes	193,556			192,886			189,952
Stock-based compensation	14,760			15,980			14,721
Debt financing costs	5,667			5,922			9,409
Other	1,019			359			541
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(4,847		)	48,240			(41,408		)
(Increase) decrease in gas stored underground	20,577			33,234			(31,996		)
Increase in other current assets	(18,739		)	(11,951		)	(24,411		)
(Increase) decrease in deferred charges and other assets	(24,860		)	51,614			28,875
Increase (decrease) in accounts payable and accrued liabilities	(5,195		)	(59,112		)	60,465
Increase (decrease) in other current liabilities	(44,482		)	896			2,413
Increase (decrease) in deferred credits and other liabilities	14,334			(56,025		)	(19,552		)
Net cash provided by operating activities	794,990			811,914			732,813
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures	(1,086,950		)	(963,621		)	(824,441		)
Purchases of available-for-sale securities	(32,551		)	(29,527		)	(32,734		)
Proceeds from sale of available-for-sale securities	27,019			24,889			24,872
Maturities of available-for-sale securities	6,290			6,235			5,215
Other, net	6,460			5,422			2,109
Net cash used in investing activities	(1,079,732		)	(956,602		)	(824,979		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt	371,884			261,232			(171,289		)
Proceeds from issuance of long-term debt, net of discount	—			499,060			—
Net proceeds from equity offering	98,574			—			390,205
Issuance of common stock through stock purchase and employee retirement plans	34,278			30,952			4,274
Settlement of interest rate agreements	—			13,364			—
Interest rate agreements cash collateral	(25,670		)	—			—
Repayment of long-term debt	—			(500,000		)	—
Cash dividends paid	(175,126		)	(160,018		)	(146,248		)
Repurchase of equity awards	—			(7,985		)	(8,717		)
Other	(317		)	(5,522		)	—
Net cash provided by financing activities	303,623			131,083			68,225
Net increase (decrease) in cash and cash equivalents	18,881			(13,605		)	(23,941		)
Cash and cash equivalents at beginning of year	28,653			42,258			66,199
Cash and cash equivalents at end of year	$	47,534		$	28,653		$	42,258
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest	$	154,748		$	151,334		$	156,606
Income taxes	$	7,794		$	1,802		$	(610	)

See accompanying notes to consolidated financial statements.

50

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 certain other nonregulated businesses. Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated distribution divisions in the service areas described below:

Division	Service Area
Atmos Energy Colorado-Kansas Division	Colorado, Kansas
Atmos Energy Kentucky/Mid-States Division	Kentucky, Tennessee, Virginia(1)
Atmos Energy Louisiana Division	Louisiana
Atmos Energy Mid-Tex Division	Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division	Mississippi
Atmos Energy West Texas Division	West Texas

⁽¹⁾  Denotes location where we have more limited service areas.

In addition, we transport natural gas for others through our distribution system. Our distribution business is 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 corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

Our regulated pipeline business, which is also subject to federal and state regulation, consists of the regulated operations of our Atmos Pipeline–Texas Division, a division of the Company. This division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand.

Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc., (AEH). AEH is a wholly-owned subsidiary of the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, regulated distribution companies, including certain divisions of Atmos Energy and third parties.

2.    Summary of Significant Accounting Policies

Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.

Basis of comparison — As described under Recent Accounting Pronouncements below, we reclassified debt issuance costs from deferred charges and other assets to long-term debt. Additionally, we recorded immaterial corrections to the presentation of certain activities on our Consolidated Statement of Cash Flows for the years ended September 30, 2015 and 2014.

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.

Regulation — Our regulated distribution and regulated pipeline operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. 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 that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be

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recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations.

We record regulatory assets as a component of other current assets and deferred charges and other assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded either on the face of the balance sheet or as a component of current liabilities, deferred income taxes or deferred credits and other liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of September 30, 2016 and 2015 included the following:

	September 30
	2016		2015
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	132,348	$	121,183
Infrastructure Mechanisms(2)	42,719		32,813
Deferred gas costs	45,184		9,715
Recoverable loss on reacquired debt	13,761		16,319
Deferred pipeline record collection costs	7,336		3,118
APT annual adjustment mechanism	7,171		1,002
Rate case costs	1,539		1,533
Other	13,565		6,656
	$	263,623	$	192,339
Regulatory liabilities:
Regulatory cost of removal obligation	$	476,891	$	483,676
Deferred gas costs	20,180		28,100
Asset retirement obligation	13,404		9,063
Other	4,250		3,693
	$	514,725	$	524,532

⁽¹⁾ Includes $12.4 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 eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

Revenue recognition — Sales of natural gas to our regulated distribution customers are billed on a monthly basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for regulated distribution segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense.

On occasion, we are permitted to implement new rates that have not been formally approved by our state regulatory commissions, which are subject to refund. As permitted by accounting principles generally accepted in the United States, we recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.

Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no gross profit generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our regulated distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our balance sheet.

Operating revenues for our regulated pipeline and nonregulated segments are recognized in the period in which actual volumes are transported and storage services are provided.

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Operating revenues for our nonregulated segment and the associated carrying value of natural gas inventory (inclusive of storage costs) are recognized when we sell the gas and physically deliver it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial instruments used in our nonregulated activities.

Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our collection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our regulated distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for substantially all of our regulated operations. Our nonregulated segment utilizes the average cost method; however, most of this inventory is hedged and is therefore reported at fair value at the end of each month. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.

Regulated property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes when the completed projects are placed in service. Interest expense of $2.8 million, $2.3 million and $1.5 million was capitalized in 2016, 2015 and 2014.

Major renewals, including replacement pipe, and betterments that are recoverable under our regulatory rate base are capitalized while the costs of maintenance and repairs that are not recoverable through rates are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.

Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.2 percent for the fiscal year ended September 30, 2016, and 3.3 percent for each of the fiscal years ended September 30, 2015 and 2014.

Nonregulated property, plant and equipment — Nonregulated property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from three to 43 years.

Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense.

As of September 30, 2016 and 2015, we had asset retirement obligations of $13.4 million and $11.1 million. Additionally, we had $8.1 million and $4.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.

We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.

Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be

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recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

Marketable securities — As of September 30, 2016 and 2015, all of our marketable securities were classified as available for sale. In accordance with the authoritative accounting standards, 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 an individual investment by investment 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 investment is written down to its estimated fair value.

Financial instruments and hedging activities — We use financial instruments to mitigate commodity price risk in our regulated distribution and nonregulated segments and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses and are discussed in Note 13.

We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ultimately recorded in the income statement. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.

The timing of when changes in fair value of our financial instruments are recorded in the income statement depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the income statement as they occur.

Financial Instruments Associated with Commodity Price Risk

In our regulated distribution segment, the costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our regulated distribution segment as a result of the use of financial instruments.

In our nonregulated segment, we have designated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge. This inventory is marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. The financial instruments associated with this natural gas inventory have been designated as fair-value hedges and are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges. For the fiscal years ended September 30, 2016, 2015 and 2014, we included unrealized gains (losses) on open contracts of $1.3 million, $(2.4) million and $9.6 million as a component of nonregulated purchased gas cost.

Additionally, we have elected to treat fixed-price forward contracts used in our nonregulated segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries are recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts have been designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments are recorded as a component of accumulated other comprehensive income, and are recognized in earnings as a component of purchased gas cost when the hedged volumes are sold.

Gains and losses from hedge ineffectiveness are recognized in the income statement. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference between the spot price and the futures price, as well as the

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difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity is referred to as timing ineffectiveness. Hedge ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost.

Our nonregulated segment also utilizes master netting agreements with significant counterparties that allow us to offset gains and losses arising from financial instruments that may be settled in cash with gains and losses arising from financial instruments that may be settled with the physical commodity. Assets and liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under master netting agreements used to offset gains and losses arising from financial instruments. As of September 30, 2016 and 2015, the Company netted $24.7 million and $43.5 million of cash held in margin accounts into its current and noncurrent risk management assets and liabilities.

Financial Instruments Associated with Interest Rate Risk

We manage interest rate risk, primarily when we plan to issue new long-term debt or to refinance existing long-term debt. We currently manage this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest expense. As of September 30, 2016, the Company netted $25.7 million of cash held in margin accounts into its current and noncurrent risk management liabilities. As of September 30, 2015 no cash was required to be held in margin accounts.

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 primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.

Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.

Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.

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) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:

Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices), as permitted under current accounting standards. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed.

Our Level 1 measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.

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Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as common collective trusts, corporate bonds and investments in limited partnerships.

Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.

Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. Our measurement date is September 30. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds.

The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors when making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.

The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this calculation will delay the impact of current market fluctuations on the pension expense for the period.

We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.

We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon the annual review of our participant census information as of the measurement date.

Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.

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Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.

Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and reasonably estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.

Subsequent events — Except as noted in Note 5 regarding the renewal of our revolving credit facility and the AEM uncommitted 364-day bilateral credit facility and Note 15 regarding the proposed sale of AEM, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.

Recent accounting pronouncements — 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. As of September 30, 2016, we were actively evaluating all of our sources of revenue to determine the potential effect of the new standard on our financial position, results of operations and cash flows and the transition approach we will utilize. We are also actively monitoring the deliberations of the FASB's Transition Resource Group as decisions made by this group will impact the final conclusions of this evaluation.

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. The new guidance aligns the presentation of debt issuance costs with debt discounts and premiums. While the guidance would have been effective for us beginning October 1, 2016, we elected early adoption effectiveSeptember 30, 2016 and have applied the provisions of the new guidance to each prior period presented. As a result, we reclassified $17.0 million and $17.9 million of unamortized debt issuance costs from deferred charges and other assets to long-term debt on the September 30, 2016 and 2015 consolidated balance sheets.

In April 2015, the FASB issued guidance to simplify the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. The new guidance is effective for us beginning October 1, 2016 and may be applied either prospectively or retrospectively with early adoption permitted. The adoption of this standard will not impact on our financial position, results of operations and cash flows.

In May 2015, the FASB issued guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The guidance is effective for us on October 1, 2016 to be applied retrospectively. The adoption of this standard will have no impact on our results of operations, consolidated balance sheets or 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. Previously, entities were required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. As permitted under the new guidance, we elected early adoption as of March 31, 2016. The adoption of this guidance had no impact on our results of operations or cash flows. Because we adopted this new guidance prospectively, prior periods have not been adjusted.

In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning October 1, 2018; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adoption is permitted. The new leasing

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standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. We are currently evaluating the effect on our financial position, results of operations and cash flows.

In March 2016, the FASB issued guidance to simplify the accounting and reporting of share-based payment arrangements. Key modifications required under the new guidance include:

• Recognition of all excess tax benefits and tax deficiencies associated with stock-based compensation as income tax expense or benefit in the income statement in the period the awards vest. The guidance also requires these income tax inflows and outflows to be classified as an operating activity.

• Simplification of the accounting for forfeitures.

• Clarification that cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity.

As permitted under the new guidance, we elected early adoption as of March 31, 2016. In accordance with the transition requirements, we recorded a $14.5 million cumulative-effect increase to retained earnings as of October 1, 2015, with an offsetting increase to the Company’s net operating loss (NOL) deferred tax asset to recognize the effect of excess tax benefits earned prior to September 30, 2015. For the year ended September 30, 2016, we have recognized a total income tax benefit of $5.0 million. The new guidance provides for certain provisions to be accounted for prospectively and others retrospectively.

In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are currently evaluating the potential impact of this new guidance.

3.    Segment Information

Atmos Energy Corporation and its subsidiaries are engaged primarily in the regulated natural gas distribution and pipeline business as well as other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which cover service areas located in eight states. In addition, we transport natural gas for others through our distribution system.

Through our nonregulated business, we provide natural gas management and transportation services to municipalities, regulated distribution companies, including certain divisions of Atmos Energy and third parties.

We operate the Company through the following three segments:

• The regulated distribution segment, includes our regulated distribution and related sales operations.

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

• The nonregulated segment, 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 aggregated and 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. We evaluate performance based on net income or loss of the respective operating units. Interest expense is allocated pro rata to each segment based upon our net investment in each segment. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.

Summarized income statements and capital expenditures by segment are shown in the following tables.

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	Year Ended September 30, 2016
	Regulated Distribution		Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,284,185	$	104,007		$	961,757	$	—		$	3,349,949
Intersegment revenues	7,681		304,826			104,606		(417,113		)	—
	2,291,866		408,833			1,066,363		(417,113		)	3,349,949
Purchased gas cost	1,019,061		—			1,002,573		(416,581		)	1,605,053
Gross profit	1,272,805		408,833			63,790		(532		)	1,744,896
Operating expenses
Operation and maintenance	404,115		129,525			27,658		(532		)	560,766
Depreciation and amortization	233,036		55,576			4,484		—			293,096
Taxes, other than income	196,070		24,298			2,648		—			223,016
Total operating expenses	833,221		209,399			34,790		(532		)	1,076,878
Operating income	439,584		199,434			29,000		—			668,018
Miscellaneous income (expense)	455		(1,683		)	1,443		(1,808		)	(1,593		)
Interest charges	79,404		36,574			1,778		(1,808		)	115,948
Income before income taxes	360,635		161,177			28,665		—			550,477
Income tax expense	128,265		59,488			12,620		—			200,373
Net income	$	232,370	$	101,689		$	16,045	$	—		$	350,104
Capital expenditures	$	740,039	$	346,400		$	511	$	—		$	1,086,950

59

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended September 30, 2015
	Regulated Distribution			Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,757,585		$	97,662		$	1,286,889		$	—		$	4,142,136
Intersegment revenues	6,250			272,450			185,320			(464,020		)	—
	2,763,835			370,112			1,472,209			(464,020		)	4,142,136
Purchased gas cost	1,526,258			—			1,399,349			(463,488		)	2,462,119
Gross profit	1,237,577			370,112			72,860			(532		)	1,680,017
Operating expenses
Operation and maintenance	388,486			118,866			35,048			(532		)	541,868
Depreciation and amortization	223,048			47,236			4,512			—			274,796
Taxes, other than income	205,894			22,743			3,321			—			231,958
Total operating expenses	817,428			188,845			42,881			(532		)	1,048,622
Operating income	420,149			181,267			29,979			—			631,395
Miscellaneous expense	(377		)	(1,243		)	(760		)	(2,009		)	(4,389		)
Interest charges	84,132			33,151			967			(2,009		)	116,241
Income before income taxes	335,640			146,873			28,252			—			510,765
Income tax expense	130,827			52,211			12,652			—			195,690
Net income	$	204,813		$	94,662		$	15,600		$	—		$	315,075
Capital expenditures	$	670,575		$	291,603		$	1,443		$	—		$	963,621

60

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended September 30, 2014
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	3,056,212		$	92,166		$	1,792,538	$	—		$	4,940,916
Intersegment revenues	5,334			226,293			274,754		(506,381		)	—
	3,061,546			318,459			2,067,292		(506,381		)	4,940,916
Purchased gas cost	1,885,031			—			1,979,337		(505,878		)	3,358,490
Gross profit	1,176,515			318,459			87,955		(503		)	1,582,426
Operating expenses
Operation and maintenance	387,228			91,466			26,963		(503		)	505,154
Depreciation and amortization	208,376			41,031			4,580		—			253,987
Taxes, other than income	196,343			13,143			2,450		—			211,936
Total operating expenses	791,947			145,640			33,993		(503		)	971,077
Operating income	384,568			172,819			53,962		—			611,349
Miscellaneous income (expense)	(381		)	(3,181		)	2,216		(3,889		)	(5,235		)
Interest charges	94,918			36,280			1,986		(3,889		)	129,295
Income before income taxes	289,269			133,358			54,192		—			476,819
Income tax expense	117,684			47,167			22,151		—			187,002
Net income	$	171,585		$	86,191		$	32,041	$	—		$	289,817
Capital expenditures	$	574,372		$	248,230		$	1,839	$	—		$	824,441

The following table summarizes our revenues from external parties by products and services for the fiscal year ended September 30.

	2016		2015		2014
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,477,049	$	1,761,689	$	1,933,099
Commercial	619,979		772,187		876,042
Industrial	51,999		74,981		90,536
Public authority and other	41,307		53,401		64,779
Total gas sales revenues	2,190,334		2,662,258		2,964,456
Transportation revenues	70,383		67,475		64,049
Other gas revenues	23,468		27,852		27,707
Total regulated distribution revenues	2,284,185		2,757,585		3,056,212
Regulated pipeline revenues	104,007		97,662		92,166
Nonregulated revenues	961,757		1,286,889		1,792,538
Total operating revenues	$	3,349,949	$	4,142,136	$	4,940,916

61

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at September 30, 2016 and 2015 by segment is presented in the following tables.

	September 30, 2016
	Regulated Distribution		Regulated Pipeline		Nonregulated		Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	6,220,425	$	2,008,997	$	51,089	$	—		$	8,280,511
Investment in subsidiaries	1,026,859		—		—		(1,026,859		)	—
Current assets
Cash and cash equivalents	21,072		—		26,462		—			47,534
Assets from risk management activities	3,029		—		6,775		—			9,804
Other current assets	446,868		19,204		367,220		(208,944		)	624,348
Intercompany receivables	978,093		—		—		(978,093		)	—
Total current assets	1,449,062		19,204		400,457		(1,187,037		)	681,686
Goodwill	576,114		132,582		34,711		—			743,407
Noncurrent assets from risk management activities	1,822		—		—		—			1,822
Deferred charges and other assets	275,496		27,631		336		—			303,463
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,463,059	$	678,964	$	347,895	$	(1,026,859	)	$	3,463,059
Long-term debt	2,188,779		—		—		—			2,188,779
Total capitalization	5,651,838		678,964		347,895		(1,026,859		)	5,651,838
Current liabilities
Current maturities of long-term debt	250,000		—		—		—			250,000
Short-term debt	1,026,811		—		—		(197,000		)	829,811
Liabilities from risk management activities	56,771		—		—		—			56,771
Other current liabilities	549,328		22,427		91,888		(11,944		)	651,699
Intercompany payables	—		950,215		27,878		(978,093		)	—
Total current liabilities	1,882,910		972,642		119,766		(1,187,037		)	1,788,281
Deferred income taxes	1,058,895		536,732		7,429		—			1,603,056
Noncurrent liabilities from risk management activities	184,048		—		—		—			184,048
Regulatory cost of removal obligation	424,281		—		—		—			424,281
Pension and postretirement liabilities	297,743		—		—		—			297,743
Deferred credits and other liabilities	50,063		76		11,503		—			61,642
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889

62

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	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	421,591		24,628		480,503			(338,301		)	588,421
Intercompany receivables	887,713		—		—			(887,713		)	—
Total current assets	1,333,545		24,628		494,147			(1,226,014		)	626,306
Goodwill	575,449		132,542		34,711			—			742,702
Noncurrent assets from risk management activities	368		—		—			—			368
Deferred charges and other assets	252,499		17,288		5,329			—			275,116
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,194,797	$	577,275	$	461,395		$	(1,038,670	)	$	3,194,797
Long-term debt	2,437,515		—		—			—			2,437,515
Total capitalization	5,632,312		577,275		461,395			(1,038,670		)	5,632,312
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
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072

63

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4.    Earnings Per Share

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

Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:

	2016		2015		2014
	(In thousands, except per share data)
Basic Earnings Per Share
Net Income	$	350,104	$	315,075	$	289,817
Less: Income allocated to participating securities	546		626		711
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Net Income per share — Basic	$	3.38	$	3.09	$	2.96
Diluted Earnings Per Share
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Effect of dilutive stock options and other shares	—		—		—
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Additional dilutive stock options and other shares	—		—		2
Diluted weighted average shares outstanding	103,524		101,892		97,608
Net Income per share — Diluted	$	3.38	$	3.09	$	2.96

5.    Debt

Long-term debt

Long-term debt at September 30, 2016 and 2015 consisted of the following:

	2016		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 Series A notes, 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	4,270		4,612
Debt issuance cost	16,951		17,873
Current maturities	250,000		—
	$	2,188,779	$	2,437,515

64

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On September 22, 2016, we entered into a three year, $200 million multi-draw term loan agreement with a syndicate of three lenders. Borrowings under the term loan may be made in increments of $1.0 million or higher, may be repaid at any time during the loan period and will bear interest at a rate dependent upon our credit ratings at the time of such borrowing and based, at our election, on a base rate or LIBOR for the applicable interest period. The term loan will be used to refinance existing indebtedness and for working capital, capital expenditures and other general corporate purposes. At September 30, 2016, there were no borrowings under the term loan.

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 discussed in Note 13. The net proceeds of approximately $494 million were used to repay our $500 million4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt

Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply and general corporate liquidity. Our short-term borrowings typically reach their highest levels in the winter months.

As of September 30, 2016, we financed 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 a total availability from third-party lenders of approximately $1.3 billion of working capital funding. On October 5, 2016, we amended our existing $1.25 billion unsecured credit facility (the five-year unsecured credit facility) which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021. The amended facility also retains the $250 million accordion feature, which provides the opportunity to increase the total committed loan amount to $1.75 billion. After giving effect to the amended facility, we have total availability from third-party lenders of approximately $1.6 billion of working capital funding. At September 30, 2016 and 2015, there was $829.8 million and $457.9 million outstanding under our commercial paper program with weighted average interest rates of 0.81% and 0.42%, with average maturities of less than one month. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.

Regulated Operations

We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders. The first facility is the five-year unsecured credit facility described above, which bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. This credit facility serves primarily as a backup liquidity facility for our commercial paper program. At September 30, 2016, there were no borrowings under this facility, but we had $829.8 million of commercial paper outstanding leaving $420.2 million available.

The second facility is a $25 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. This facility was renewed on April 1, 2016. At September 30, 2016, there were no borrowings outstanding under this facility.

The third facility, which was renewed on September 30, 2016, is a $10 million committed revolving credit facility, used primarily to issue letters of credit and bears interest at a LIBOR-based rate plus 1.5 percent. At September 30, 2016, there were no borrowings outstanding under this credit facility; however, letters of credit totaling $5.9 million had been issued under the facility at September 30, 2016, which reduced the amount available by a corresponding amount.

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our five-year unsecured facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2016, our total-debt-to-total-capitalization ratio, as defined, was 50 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016. We intend to seek renewal of this facility during the first quarter of fiscal 2017. There was $197.0 million outstanding under this facility at September 30, 2016.

65

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility that expires in December 2016 and one committed $15 million 364-day bilateral credit facility that was renewed on September 30, 2016. On October 25, 2016, the uncommitted $25 million 364-day bilateral credit facility was renewed through July 31, 2017. 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 $32.8 million at September 30, 2016.

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. We intend to seek renewal of this facility during the first quarter of fiscal 2017. There were no borrowings outstanding under this facility at September 30, 2016.

Debt Covenants

In addition to the financial covenants described above, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.

Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.

We were in compliance with all of our debt covenants as of September 30, 2016. 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.

Maturities of long-term debt at September 30, 2016 were as follows (in thousands):

2017	$	250,000
2018	—
2019	450,000
2020	—
2021	—
Thereafter	1,760,000
	$	2,460,000

6.    Shareholders' Equity

Shelf Registration

On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. At September 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.

At-the-Market Equity Sales Program

On March 28, 2016, we entered into an at-the-market (ATM) equity distribution agreement (the Agreement) with Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC in their capacity as agents and/or as principals (Agents). Under the terms of the Agreement, we may issue and sell, through any of the Agents, shares of our common stock, up to an aggregate offering price of $200 million, through the period ended March 28, 2019. We may also sell shares from time to time to an Agent for its own account at a price to be agreed upon at the time of sale. We will pay each Agent a commission of 1.0% of the gross offering proceeds of the shares sold through it as a sales agent. We have no obligation to offer or sell any shares under the Agreement, and may at any time suspend offers and sales under the Agreement. The shares will be issued pursuant to our shelf registration statement filed with the SEC on March 28, 2016. During fiscal 2016, we sold 1,360,756 shares of common stock under the ATM program for $100.0 million and received net proceeds of $98.6 million.

66

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

1998 Long-Term Incentive Plan

In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock. 

As of September 30, 2015, we were authorized to grant awards for up to a maximum of 8.7 million shares of common stock under this plan subject to certain adjustment provisions. In February 2016, our shareholders voted to increase the number of authorized LTIP shares by 2.5 million shares and to extend the term of the plan for an additional five years, through September 2021. On March 29, 2016, we filed with the SEC a registration statement on Form S-8 to register an additional 2.5 million shares; we also listed such shares with the New York Stock Exchange. As of September 30, 2016, we were authorized to grant awards for up to a maximum of 11.2 million shares of common stock under this plan subject to certain adjustment provisions.

2014 Equity Offering

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

Share Repurchase Program

On September 28, 2011, the Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a five-year period. The program expired on September 30, 2016 and will not be renewed. We did not repurchase any shares during fiscal 2016, 2015, or 2014 under the program.

67

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accumulated Other Comprehensive Income (Loss)

We record deferred gains (losses) in accumulated other comprehensive income (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	(263		)	(99,029		)	(11,662		)	(110,954		)
Amounts reclassified from accumulated other comprehensive income	(202		)	347			32,117			32,262
Net current-period other comprehensive income (loss)	(465		)	(98,682		)	20,455			(78,692		)
September 30, 2016	$	4,484		$	(187,524	)	$	(4,982	)	$	(188,022	)

	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	(2,173		)	(71,003		)	(49,211		)	(122,387		)
Amounts reclassified from accumulated other comprehensive income	(540		)	542			25,448			25,450
Net current-period other comprehensive income (loss)	(2,713		)	(70,461		)	(23,763		)	(96,937		)
September 30, 2015	$	4,949		$	(88,842	)	$	(25,437	)	$	(109,330	)

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2016 and 2015. Amounts in parentheses below indicate decreases to net income in the statement of income.

	Fiscal Year Ended September 30, 2016
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	$	318		Operation and maintenance expense
	318			Total before tax
	(116		)	Tax expense
	$	202		Net of tax
Cash flow hedges
Interest rate agreements	$	(546	)	Interest charges
Commodity contracts	(52,651		)	Purchased gas cost
	(53,197		)	Total before tax
	20,733			Tax benefit
	$	(32,464	)	Net of tax
Total reclassifications	$	(32,262	)	Net of tax

68

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Fiscal Year Ended September 30, 2015
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	$	850		Operation and maintenance expense
	850			Total before tax
	(310		)	Tax expense
	$	540		Net of tax
Cash flow hedges
Interest rate agreements	$	(853	)	Interest charges
Commodity contracts	(41,716		)	Purchased gas cost
	(42,569		)	Total before tax
	16,579			Tax benefit
	$	(25,990	)	Net of tax
Total reclassifications	$	(25,450	)	Net of tax

7.    Retirement and Post-Retirement Employee Benefit Plans

We have both funded and unfunded noncontributory defined benefit plans that together cover most of our employees. We also maintain post-retirement plans that provide health care benefits to retired employees. Finally, we sponsor a defined contribution plan that cover substantially all employees. These plans are discussed in further detail below.

As a rate regulated entity, we generally recover our pension costs in our rates over a period of up to 15 years. The amounts that have not yet been recognized in net periodic pension cost that have been recorded as regulatory assets are as follows:

	Defined Benefits Plan			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2016
Unrecognized prior service credit	$	(1,509	)	$	—	$	(2,880	)	$	(4,389	)
Unrecognized actuarial (gain) loss	127,028			51,558		(54,298		)	124,288
	$	125,519		$	51,558	$	(57,178	)	$	119,899
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial (gain) loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537

Defined Benefit Plans

Employee Pension Plan

Prior to December 31, 2014, we maintained two defined benefit plans: the Atmos Energy Corporation Pension Account Plan (the Plan) and the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees (the Union Plan) (collectively referred to as the Plans). The assets of the Plans were held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust). In June 2014, active collectively bargained employees of Atmos Energy’s Mississippi Division voted to decertify the union. As a result of this vote, effective January 1, 2015, active participants of the Union Plan became participants in the Plan. Opening account balances were established at the time of transfer equal to the present value of their respective accrued benefits under the Union Plan at December 31, 2014. Additionally, effective January 1, 2015, current retirees in the Union Plan as well as those participants who terminated and were vested in the Union Plan were transferred to the Plan with the same provisions that were in place at the time of their retirement or termination.

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The Plan is a cash balance pension plan that was established effective January 1999 and covers most of the employees of Atmos Energy’s regulated operations that were hired before September 30, 2010. The plan was closed to new participants effective October 1, 2010.

Opening account balances were established for participants as of January 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula based on the participant’s age, service and total pay (excluding incentive pay). In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. Participants are fully vested in their account balances after three years of service and may choose to receive their account balances as a lump sum or an annuity.

Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension Protection Act of 2006 (PPA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

During fiscal 2016 and 2015 we contributed $15.0 million and $38.0 million in cash to the Plan to achieve a desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at September 30, 2016, the current funded position of the Plan and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2017. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.

We make investment decisions and evaluate performance of the assets in the Master Trust on a medium-term horizon of at least three to five years. We also consider our current financial status when making recommendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long-term asset investment policy adopted by the Board of Directors.

To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities, interests in commingled pension trust funds, other investment assets and cash and cash equivalents. Investments in equity securities are diversified among the market’s various subsectors in an effort to diversify risk and maximize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.

The following table presents asset allocation information for the Master Trust as of September 30, 2016 and 2015.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2016		2015
Domestic equities	35%-55%	40.5	%	41.3	%
International equities	10%-20%	15.5	%	14.9	%
Fixed income	5%-30%	11.2	%	11.0	%
Company stock	0%-15%	15.1	%	15.2	%
Other assets	0%-20%	17.7	%	17.6	%

At September 30, 2016 and 2015, the Plan held 956,700 and 1,169,700 shares of our common stock which represented 15.1 percent and 15.2 percent of total Plan assets. These shares generated dividend income for the Plan of approximately $1.8 million during fiscal 2016 and 2015.

Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions underlying our employee pension plans annually based upon a September 30 measurement date. The development of our assumptions is fully described in our significant accounting policies in Note 2. The actuarial assumptions used to determine the pension liability for the Plan was determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the Plan was determined as of September 30, 2015, 2014 and 2013. On October 20, 2016, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table.

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Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%	7.25	%	7.25	%

The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	516,924		$	485,921
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	508,599		$	493,594
Service cost	16,419			16,231
Interest cost	23,193			21,850
Actuarial loss	41,847			7,420
Benefits paid(1)	(44,578		)	(30,496		)
Benefit obligation at end of year	545,480			508,599
Change in plan assets:
Fair value of plan assets at beginning of year	450,932			434,767
Actual return on plan assets	52,596			8,661
Employer contributions	15,000			38,000
Benefits paid(1)	(44,578		)	(30,496		)
Fair value of plan assets at end of year	473,950			450,932
Reconciliation:
Funded status	(71,530		)	(57,667		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(71,530	)	$	(57,667	)

⁽¹⁾  Includes $12.8 million of one-time payments to eligible deferred vested participants who elected to receive a lump-sum payout of their pension benefits during fiscal 2016.

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Net periodic pension cost for the Plan for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,419		$	16,231		$	15,345
Interest cost	23,193			21,850			22,330
Expected return on assets	(27,522		)	(25,744		)	(23,601		)
Amortization of prior service credit	(226		)	(192		)	(136		)
Recognized actuarial loss	10,693			13,322			13,777
Net periodic pension cost	$	22,557		$	25,467		$	27,715

The following table sets forth by level, within the fair value hierarchy, the Plan's assets at fair value as of September 30, 2016 and 2015. As required by authoritative accounting literature, assets are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement. The methods used to determine fair value for the assets held by the Plan are fully described in Note 2. In addition to the assets shown below, the Plan had net accounts receivable of $2.6 million and $2.4 million at September 30, 2016 and 2015 which materially approximates fair value due to the short-term nature of these assets.

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	157,111	$	—	$	—	$	157,111
Money market funds	—		11,522		—		11,522
Registered investment companies	87,396		—		—		87,396
Common/collective trusts	—		105,124		—		105,124
Government securities:
Mortgage-backed securities	—		15,223		—		15,223
U.S. treasuries	4,704		863		—		5,567
Corporate bonds	—		31,929		—		31,929
Limited partnerships	—		57,438		—		57,438
Total investments at fair value	$	249,211	$	222,099	$	—	$	471,310

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	159,304	$	—	$	—	$	159,304
Money market funds	—		11,787		—		11,787
Registered investment companies	81,960		—		—		81,960
Common/collective trusts	—		93,081		—		93,081
Government securities:
Mortgage-backed securities	—		14,359		—		14,359
U.S. treasuries	5,279		805		—		6,084
Corporate bonds	—		28,973		—		28,973
Limited partnerships	—		52,996		—		52,996
Total investments at fair value	$	246,543	$	202,001	$	—	$	448,544

Supplemental Executive Retirement Plans

We have three nonqualified supplemental plans which provide additional pension, disability and death benefits to our officers, division presidents and certain other employees of the Company.

The first plan is referred to as the Supplemental Executive Benefits Plan (SEBP) and covers our officers, division presidents and certain other employees of the Company who were employed on or before August 12, 1998. The SEBP is a defined benefit arrangement which provides a benefit equal to 75 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SEBP.

In August 1998, we adopted the Supplemental Executive Retirement Plan (SERP) (formerly known as the Performance-Based Supplemental Executive Benefits Plan), which covers all officers or division presidents selected to participate in the plan between August 12, 1998 and August 5, 2009, any corporate officer who may be appointed to the Management Committee after August 5, 2009 and any other employees selected by our Board of Directors at its discretion. The SERP is a defined benefit arrangement which provides a benefit equal to 60 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SERP.

Effective August 5, 2009, we adopted a new defined benefit Supplemental Executive Retirement Plan (the 2009 SERP), for corporate officers (other than such officer who is appointed as a member of the Company’s Management Committee), division presidents or any other employees selected at the discretion of the Board. Under the 2009 SERP, a nominal account has been established for each participant, to which the Company contributes at the end of each calendar year an amount equal to ten percent of the total of each participant’s base salary and cash incentive compensation earned during each prior calendar year, beginning December 31, 2009. The benefits vest after three years of service and attainment of age 55 and earn interest credits at the same annual rate as the Company’s Pension Account Plan (currently 4.69%).

On October 2, 2013, due to the retirement of one of our executives, we recognized a settlement loss of $4.5 million associated with our SEBP and made a $16.8 million benefit payment.

Similar to our employee pension plans, we review the estimates and assumptions underlying our supplemental plans annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2015, 2014 and 2013. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	137,616		$	118,835
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	122,393		$	113,219
Service cost	2,371			3,971
Interest cost	5,185			4,943
Actuarial loss	17,229			4,811
Benefits paid	(4,604		)	(4,551		)
Benefit obligation at end of year	142,574			122,393
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,604			4,551
Benefits paid	(4,604		)	(4,551		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(142,574		)	(122,393		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(142,574	)	$	(122,393	)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2016 and 2015, assets held in the rabbi trusts consisted of available-for-sale securities of $41.3 million and $41.7 million, which are included in our fair value disclosures in Note 14.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic pension cost for the supplemental plans for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016		2015		2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	2,371	$	3,971	$	3,607
Interest cost	5,185		4,943		4,966
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,586		2,343		1,948
Settlements	—		—		4,539
Net periodic pension cost	$	10,142	$	11,257	$	15,060

Estimated Future Benefit Payments

The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years:

	Pension Plan		Supplemental Plans
	(In thousands)
2017	$	31,306	$	36,604
2018	32,047		14,289
2019	33,674		7,181
2020	35,232		4,395
2021	37,279		4,306
2022-2026	202,442		60,658

Postretirement Benefits

We sponsor the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation (the Atmos Retiree Medical Plan). This plan provides medical and prescription drug protection to all qualified participants based on their date of retirement. The Atmos Retiree Medical Plan provides different levels of benefits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however, we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remaining 20 percent of this cost. Effective January 1, 2015 for employees who had not met the participation requirements by September 30, 2009, the contribution rates for the Company will be limited to a three percent cost increase in claims and administrative costs each year, with the participant responsible for the additional costs.

Generally, our funding policy is to contribute annually an amount in accordance with the requirements of ERISA. However, additional voluntary contributions are made annually as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. We expect to contribute between $10 million and $20 million to our postretirement benefits plan during fiscal 2017.

We maintain a formal investment policy with respect to the assets in our postretirement benefits plan to ensure the assets funding the postretirement benefit plan are appropriately invested to maintain an acceptable level of risk. We also consider our current financial status when making recommendations and decisions regarding the postretirement benefits plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We currently invest the assets funding our postretirement benefit plan in diversified investment funds which consist of common stocks, preferred stocks and fixed income securities. The diversified investment funds may invest up to 75 percent of assets in common stocks and convertible securities. The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2016 and 2015.

	Actual Allocation September 30
Security Class	2016		2015
Diversified investment funds	97.2	%	97.5	%
Cash and cash equivalents	2.8	%	2.5	%

Similar to our employee pension and supplemental plans, we review the estimates and assumptions underlying our postretirement benefit plan annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2015, 2014 and 2013. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Expected return on plan assets	4.45	%	4.45	%	4.45	%	4.60	%	4.60	%
Initial trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2022		2021		2021		2020		2020

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	267,179		$	315,118
Service cost	10,823			15,583
Interest cost	12,424			14,385
Plan participants’ contributions	4,289			4,563
Actuarial gain	(1,052		)	(69,962		)
Benefits paid	(14,441		)	(12,508		)
Benefit obligation at end of year	279,222			267,179
Change in plan assets:
Fair value of plan assets at beginning of year	138,009			134,821
Actual return on plan assets	14,528			(8,851		)
Employer contributions	16,592			19,984
Plan participants’ contributions	4,289			4,563
Benefits paid	(14,441		)	(12,508		)
Fair value of plan assets at end of year	158,977			138,009
Reconciliation:
Funded status	(120,245		)	(129,170		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(120,245	)	$	(129,170	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic postretirement cost for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	10,823		$	15,583		$	16,784
Interest cost	12,424			14,385			15,951
Expected return on assets	(6,264		)	(6,431		)	(5,167		)
Amortization of transition obligation	82			272			274
Amortization of prior service credit	(1,644		)	(1,644		)	(1,450		)
Recognized actuarial (gain) loss	(2,167		)	—			631
Net periodic postretirement cost	$	13,254		$	22,165		$	27,023

Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations:

	One-Percentage Point Increase		One-Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	4,539	$	(3,596	)
Effect on postretirement benefit obligation	$	42,079	$	(34,531	)

We are currently recovering other postretirement benefits costs through our regulated rates under accrual accounting as prescribed by accounting principles generally accepted in the United States in substantially all of our service areas. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by our Kentucky/Mid-States, West Texas, Mid-Tex and Mississippi Divisions as well as our Kansas jurisdiction and Atmos Pipeline – Texas or have been included in a rate case and not disallowed. Management believes that this accounting method is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.

The following tables set forth by level, within the fair value hierarchy, the Retiree Medical Plan’s assets at fair value as of September 30, 2016 and 2015. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2.

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	4,470	$	—	$	4,470
Registered investment companies	154,507		—		—		154,507
Total investments at fair value	$	154,507	$	4,470	$	—	$	158,977

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,486	$	—	$	3,486
Registered investment companies	134,523		—		—		134,523
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Estimated Future Benefit Payments

The following benefit payments paid by us, retirees and prescription drug subsidy payments for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years. Company payments for fiscal 2016 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2017	$	15,806	$	3,679	$	—	$	19,485
2018	11,602		3,992		—		15,594
2019	12,165		4,036		—		16,201
2020	13,246		4,756		—		18,002
2021	14,210		5,420		—		19,630
2022-2026	84,642		36,837		—		121,479

Defined Contribution Plan

The Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) covers substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Effective January 1, 2007, employees automatically become participants of the Retirement Savings Plan on the date of employment. Participants may elect a salary reduction up to a maximum of 65 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. New participants are automatically enrolled in the Plan at a salary reduction amount of four percent of eligible compensation, from which they may opt out. We match 100 percent of a participant’s contributions, limited to four percent of the participant’s salary, in our common stock. However, participants have the option to immediately transfer this matching contribution into other funds held within the plan. Participants are eligible to receive matching contributions after completing one year of service. Participants are also permitted to take out loans against their accounts subject to certain restrictions. Employees hired on or after October 1, 2010 participate in the enhanced plan in which participants receive a fixed annual contribution of four percent of eligible earnings to their Retirement Savings Plan account. Participants will continue to be eligible for company matching contributions of up to four percent of their eligible earnings and will be fully vested in the fixed annual contribution after three years of service.

Prior to December 31, 2015, we also maintained the Atmos Energy Holdings, LLC 401(k) Profit-Sharing Plan (the AEH 401(k) Profit-Sharing Plan), which covered substantially all AEH employees. On November 4, 2015, the Atmos Energy Corporation Board of Directors voted to approve the merger of the assets and liabilities of the AEH 401(k) Profit-Sharing Plan with the Retirement Savings Plan, effective January 1, 2016. On December 31, 2015, the AEH 401(k) Profit Sharing Plan was merged into the Retirement Savings Plan and all assets and loans of active and inactive participants were transferred to the Retirement Savings Plan.

Prior to December 31, 2014, we maintained the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401(k) Plan). In June 2014, active collectively bargained employees of Atmos Energy’s Mississippi Division voted to decertify the Union. As a result, effective July 19, 2014, active participants of the Union 401(k) Plan were eligible to participate in the Retirement Savings Plan. Effective January 1, 2015, all remaining participants became participants in the Retirement Savings Plan and the Union 401(k) Plan was terminated.

Matching contributions to the Retirement Savings Plan (and prior to December 31, 2014, the Union 401(k) Plan) are expensed as incurred and amounted to $12.6 million, $11.5 million and $10.9 millionfor fiscal years2016,2015and2014. The Board of Directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code and applicable Treasury regulations. No discretionary contributions were made for fiscal years 2016, 2015 or 2014. At September 30, 2016 and 2015, the Retirement Savings Plan held 4.2 percent and 4.3 percent of our outstanding common stock. Discretionary contributions to the AEH 401(k) Profit-Sharing Plan were expensed as incurred and amounted to $0.3 million, $1.1 million and $1.4 million for fiscal years 2016, 2015 and 2014.

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8.    Stock and Other Compensation Plans

Stock-Based Compensation Plans

Total stock-based compensation cost was $24.6 million, $27.5 million and $25.5 million for the fiscal years ended September 30, 2016, 2015 and 2014. Of this amount, $9.8 million, $11.5 million and $10.8 million was capitalized. Tax benefits related to stock-based compensation were $5.0 million, $4.7 million and $3.1 million for the fiscal years ended September 30, 2016, 2015 and 2014.

1998 Long-Term Incentive Plan

In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.

As of September 30, 2016, we were authorized to grant awards for up to a maximum of 11.2 million shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2016, non-qualified stock options, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units had been issued under this plan, and 2.4 million shares were available for future issuance.

Restricted Stock Unit Award Grants

As noted above, the LTIP provides for discretionary awards of restricted stock units to help attract, retain and reward employees of Atmos Energy and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The fair value of the awards granted is based on the market price of our stock at the date of grant. We estimate forfeitures using our historical forfeiture rate. The associated expense is recognized ratably over the vesting period. We use authorized and unissued shares to meet share requirements for the vesting of restricted stock units.

Employees who are granted time-lapse restricted stock units under our LTIP have a nonforfeitable right to dividend equivalents that are paid at the same rate and at the same time at which they are paid on shares of stock without restrictions. Time-lapse restricted stock units contain only a service condition that the employee recipients render continuous services to the Company for a period of three years from the date of grant, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions). There are no performance conditions required to be met for employees to be vested in time-lapse restricted stock units.

Employees who are granted performance-based restricted stock units under our LTIP have a forfeitable right to dividend equivalents that accrue at the same rate at which they are paid on shares of stock without restrictions. Dividend equivalents on the performance-based restricted stock units are paid either in cash or in the form of shares upon the vesting of the award. Performance-based restricted stock units contain a service condition that the employee recipients render continuous services to the Company for a period of three years from the beginning of the applicable three-year performance period, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions) and a performance condition based on a cumulative earnings per share target amount.

The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2016, 2015 and 2014:

	2016				2015				2014
	Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value
Nonvested at beginning of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20
Granted	357,323		65.98		444,543		50.50		464,438		45.05
Vested	(448,136	)	45.88		(551,688	)	39.28		(524,532	)	32.67
Forfeited	(4,860	)	53.52		(3,388	)	48.55		(4,113	)	39.00
Nonvested at end of year	782,431		$	57.66	878,104		$	48.24	988,637		$	42.22

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As of September 30, 2016, there was $11.4 million of total unrecognized compensation cost related to nonvested time-lapse restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2016, 2015 and 2014 was $20.6 million, $21.7 million and $17.1 million.

Other Plans

Direct Stock Purchase Plan

We maintain a Direct Stock Purchase Plan, open to all investors, which allows participants to have all or part of their cash dividends paid quarterly in additional shares of our common stock. The minimum initial investment required to join the plan is $1,250. Direct Stock Purchase Plan participants may purchase additional shares of our common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000.

Outside Directors Stock-For-Fee Plan

In November 1994, the Board of Directors adopted the Outside Directors Stock-for-Fee Plan, which was approved by our shareholders in February 1995. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash. This plan was terminated by the Board of Directors, effective September 1, 2014, when the LTIP was amended to incorporate substantially all of its provisions.

Equity Incentive and Deferred Compensation Plan for Non-Employee Directors

In November 1998, the Board of Directors adopted the Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, which was approved by our shareholders in February 1999. This plan amended the Atmos Energy Corporation Deferred Compensation Plan for Outside Directors adopted by the Company in May 1990 and replaced the pension payable under our Retirement Plan for Non-Employee Directors. The plan provides non-employee directors of Atmos Energy with the opportunity to defer receipt, until retirement, of compensation for services rendered to the Company and invest deferred compensation into either a cash account or a stock account.

Other Discretionary Compensation Plans

We have an annual incentive program covering substantially all employees to give each employee an opportunity to share in our financial success based on the achievement of key performance measures considered critical to achieving business objectives for a given year with minimum and maximum thresholds. The Company must meet the minimum threshold for the plan to be funded and distributed to employees. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded. During the last several fiscal years, we have used earnings per share as our sole performance measure.

9.    Details of Selected Consolidated Balance Sheet Captions

The following tables provide additional information regarding the composition of certain of our balance sheet captions.

Accounts receivable

Accounts receivable was comprised of the following at September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Billed accounts receivable	$	206,248		$	204,585
Unbilled revenue	67,396			65,008
Other accounts receivable	39,730			40,850
Total accounts receivable	313,374			310,443
Less: allowance for doubtful accounts	(13,367		)	(15,283		)
Net accounts receivable	$	300,007		$	295,160

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Other current assets

Other current assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Assets from risk management activities	$	9,804	$	9,232
Deferred gas costs	45,184		9,715
Taxes receivable	5,456		4,479
Prepaid expenses	23,053		23,055
Materials and supplies	5,825		12,587
Other	11,507		6,822
Total	$	100,829	$	65,890

Property, plant and equipment

Property, plant and equipment was comprised of the following as of September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Production plant	$	66		$	131
Storage plant	353,523			286,011
Transmission plant	2,232,927			1,844,117
Distribution plant	6,598,990			6,019,001
General plant	761,057			769,311
Intangible plant	40,515			41,131
	9,987,078			8,959,702
Construction in progress	184,062			280,398
	10,171,140			9,240,100
Less: accumulated depreciation and amortization	(1,890,629		)	(1,809,520		)
Net property, plant and equipment(1)	$	8,280,511		$	7,430,580

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

Goodwill

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2016:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702
Deferred tax adjustments on prior acquisitions(1)	665		40		—		705
Balance as of September 30, 2016	$	576,114	$	132,582	$	34,711	$	743,407

⁽¹⁾  We annually adjust certain deferred taxes recorded in connection with acquisitions completed in fiscal 2001 and fiscal 2004, which resulted in an increase to goodwill and net deferred tax liabilities of $0.7 million for fiscal 2016.

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Deferred charges and other assets

Deferred charges and other assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Marketable securities	$	72,701	$	74,200
Regulatory assets	214,890		182,573
Assets from risk management activities	1,822		368
Other	15,872		18,343
Total	$	305,285	$	275,484

Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Trade accounts payable	$	114,533	$	78,534
Accrued gas payable	108,526		119,825
Accrued liabilities	36,375		40,583
Total	$	259,434	$	238,942

Other current liabilities

Other current liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer credit balances and deposits	$	81,890	$	100,232
Accrued employee costs	47,058		47,602
Deferred gas costs	20,180		28,100
Accrued interest	34,863		34,914
Liabilities from risk management activities	56,771		9,568
Taxes payable	104,457		93,674
Pension and postretirement obligations	36,606		21,857
Current deferred tax liability	—		55,918
Regulatory cost of removal accrual	52,610		56,123
Other	14,601		9,966
Total	$	449,036	$	457,954

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Deferred credits and other liabilities

Deferred credits and other liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer advances for construction	$	9,850	$	9,316
Regulatory liabilities	4,152		3,693
Asset retirement obligation	13,404		9,063
Liabilities from risk management activities	184,048		110,539
Other	34,236		29,085
Total	$	245,690	$	161,696

10.    Leases

We have entered into operating leases for office and warehouse space, vehicles and heavy equipment used in our operations. The remaining lease terms range from one to 18 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases.

The related future minimum lease payments at September 30, 2016 were as follows:

	Operating Leases
	(In thousands)
2017	$	17,073
2018	16,824
2019	15,450
2020	14,479
2021	14,335
Thereafter	47,714
Total minimum lease payments	$	125,875

Consolidated lease and rental expense amounted to $32.6 million, $32.5 million and $31.7 million for fiscal 2016, 2015 and 2014.

11.    Commitments and Contingencies

Litigation

We are a party to various litigation that has arisen in the ordinary course of our business. While the results of such litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental Matters

We are a party to environmental matters and claims that have arisen in the ordinary course of our business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance.

Purchase Commitments

Our regulated distribution divisions 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 trading hubs. At September 30, 2016, we were committed to purchase 28.5 Bcf within one year, 4.2 Bcf within two to three years and 0.6 Bcf

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beyond three years under indexed contracts. Purchases under these contracts totaled $85.3 million, $113.3 million and $140.9 million for 2016, 2015, 2014.

Our nonregulated segment has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2016, we were committed to purchase 93.5 Bcf within one year, 9.1 Bcf within two to three years and 0.2 Bcf after three years under indexed contracts. We are committed to purchase 11.9 Bcf within one year and 1.3 Bcf within one to three years under fixed price contracts with prices ranging from $0.25 to $3.16 per Mcf. Purchases under these contracts totaled $763.2 million , $1,141.3 million and $1,687.5 million for 2016, 2015 and 2014.

In addition, our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts as of September 30, 2016 are as follows (in thousands):

2017	$	9,065
2018	2,336
2019	424
2020	400
2021	327
Thereafter	678
	$	13,230

12.    Income Taxes

The components of income tax expense from continuing operations for 2016, 2015 and 2014 were as follows:

	2016			2015			2014
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	6,822			7,251			5,527
Deferred
Federal	181,790			175,897			169,106
State	11,766			12,548			12,375
Investment tax credits	(5		)	(6		)	(6		)
	$	200,373		$	195,690		$	187,002

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2016, 2015 and 2014 are set forth below:

	2016			2015			2014
	(In thousands)
Tax at statutory rate of 35%	$	192,667		$	178,768		$	166,887
Common stock dividends deductible for tax reporting	(2,570		)	(2,413		)	(2,307		)
State taxes (net of federal benefit)	11,504			12,869			11,636
Change in valuation allowance	1,324			4,998			6,969
Other, net	(2,552		)	1,468			3,817
Income tax expense	$	200,373		$	195,690		$	187,002

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Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that gave rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2016 and 2015 are presented below:

	2016			2015
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	122,682		$	121,619
Interest rate agreements	107,782			51,067
Net operating loss carryforwards	514,391			313,224
Charitable and other credit carryforwards	22,273			22,281
Other	23,648			36,695
Total deferred tax assets	790,776			544,886
Valuation allowance	(10,481		)	(10,872		)
Net deferred tax assets	780,295			534,014
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(2,259,278		)	(1,890,886		)
Pension funding	(30,652		)	(35,247		)
Gas cost adjustments	(54,725		)	(43,634		)
Other	(38,696		)	(31,480		)
Total deferred tax liabilities	(2,383,351		)	(2,001,247		)
Net deferred tax liabilities	$	(1,603,056	)	$	(1,467,233	)
Deferred credits for rate regulated entities	$	861		$	412

At September 30, 2016, we had $494.0 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards which do not expire. In addition, the Company has $11.0 million in charitable contribution carryforwards to offset taxable income. The Company’s charitable contribution carryforwards expire in 2017 - 2021.

For state taxable income, the Company has $20.4 million of state net operating loss carryforwards (net of $11.0 million of federal effects) and $1.1 million of state tax credits carryforwards (net of federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire between 2017 and 2031.

We believe it is more likely than not that the benefit from certain charitable contribution carryforwards, state net operating loss carryforwards and state credit carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the carryforwards, a valuation allowance of $1.1 million and $5.0 million was established for the years ended September 30, 2016 and 2015. In addition, $1.4 million of deferred tax assets expired for which a valuation allowance had previously been recorded and $0.2 million of deferred tax assets expired for which a valuation allowance had not been previously recorded during the year ended September 30, 2016.

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At September 30, 2016, we had recorded liabilities associated with unrecognized tax benefits totaling $20.3 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2016			2015
	(In thousands)
Unrecognized tax benefits - beginning balance	$	17,069		$	12,629
Increase (decrease) resulting from prior period tax positions	(290		)	1,009
Increase resulting from current period tax positions	3,519			3,431
Unrecognized tax benefits - ending balance	20,298			17,069
Less: deferred federal and state income tax benefits	(7,104		)	(5,974		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	13,194		$	11,095

The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expense. During the years ended September 30, 2016 and 2015, the Company recognized approximately $2.5 million and $0.5 million in interest and penalties. The Company had approximately $3.3 million and $0.8 million for the payment of interest and penalties accrued at September 30, 2016 and 2015.

We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2007 and concluded substantially all Texas income tax matters through fiscal year 2010.

13.    Financial Instruments

We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. Currently, we utilize financial instruments in our regulated distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated pipeline segment.

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

As discussed in Note 2, we report our financial instruments as risk management assets and liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. The following table shows the fair values of our risk management assets and liabilities by segment at September 30, 2016 and 2015:

	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2016
Assets from risk management activities, current(1)	$	3,029		$	6,775	$	9,804
Assets from risk management activities, noncurrent	1,822			—		1,822
Liabilities from risk management activities, current(1)	(56,771		)	—		(56,771		)
Liabilities from risk management activities, noncurrent(1)	(184,048		)	—		(184,048		)
Net assets (liabilities)	$	(235,968	)	$	6,775	$	(229,193	)
September 30, 2015
Assets from risk management activities, current(2)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(2)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(2)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)

⁽¹⁾  Includes $25.7 million of cash held on deposit to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. Also includes $24.7 million of cash held on

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deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

⁽²⁾  Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

Regulated Commodity Risk Management Activities

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

Our regulated distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2015-2016 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or approximately 23.0 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $3.14 per Mcf. We have not designated these financial instruments as hedges.

Nonregulated Commodity Risk Management Activities

In our nonregulated operations, we buy, sell and deliver natural gas at competitive prices by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.

As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Future contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. Specifically, these operations use financial instruments in the following ways:

•Gas delivery and related services - We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, 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 63 months.

•Transportation and storage services - Our nonregulated operations use storage and basis swaps, futures and various over-the-counter and exchange-traded options 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.

Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. A risk committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.

Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations in order to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Our operations can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be

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hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on September 30, 2016, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 Bcf.

Interest Rate Risk Management Activities

We currently manage interest rate risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the then anticipated issuance of $500 million senior notes in October 2014. These notes were issued as planned in October 2014 and we settled swaps with the receipt of $13.4 million. Because the swaps were effective, the realized gain was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes. In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with $210 million of the anticipated issuance of $250 million unsecured senior notes in fiscal 2017. Additionally, in fiscal 2014 and 2015, we entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with $450 million of the anticipated issuance of $450 million unsecured senior notes in fiscal 2019. We designated all of these swaps as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps will be recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred, will be reported as a component of interest expense.

Prior to fiscal 2012, we entered into several interest rate agreements to fix the Treasury yield component of the interest cost of financing for various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these interest rate agreements were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled interest rate agreements extend through fiscal 2045.

Quantitative Disclosures Related to Financial Instruments

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

As of September 30, 2016, 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 September 30, 2016, 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	—	(19,395	)
	Cash Flow	—	39,278
	Not designated	18,595	71,147
		18,595	91,030

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Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of September 30, 2016 and 2015. The gross amounts of recognized assets and liabilities are netted within our 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)
September 30, 2016
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	6,612		$	(21,903	)
Interest rate contracts	Other current assets / Other current liabilities	—		(68,481		)	—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			2,178			(3,779		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(198,008		)	—			—
Total		—		(266,489		)	8,790			(25,682		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	3,029		—			18,157			(18,812		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,822		—			12,343			(12,701		)
Total		4,851		—			30,500			(31,513		)
Gross Financial Instruments		4,851		(266,489		)	39,290			(57,195		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(39,290		)	39,290
Net Financial Instruments		4,851		(266,489		)	—			(17,905		)
Cash collateral		—		25,670			6,775			17,905
Net Assets/Liabilities from Risk Management Activities		$	4,851	$	(240,819	)	$	6,775		$	—

89

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		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 years ended September 30, 2016, 2015 and 2014, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $21.6 million, $0.2 million and $1.9 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 consolidated income statement for the years ended September 30, 2016, 2015 and 2014 is presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Commodity contracts	$	3,516		$	10,311		$	(792	)
Fair value adjustment for natural gas inventory designated as the hedged item	18,079			(9,768		)	2,486
Total decrease in purchased gas cost	$	21,595		$	543		$	1,694
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(1,390	)	$	811		$	(919	)
Timing ineffectiveness	22,985			(268		)	2,613
	$	21,595		$	543		$	1,694

90

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 consolidated income statements for the years ended September 30, 2016, 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.

	Fiscal Year Ended September 30, 2016
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(52,651	)	$	(52,651	)
Loss arising from ineffective portion of commodity contracts	—			(19		)	(19		)
Total impact on purchased gas cost	—			(52,670		)	(52,670		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(546		)	—			(546		)
Total impact from cash flow hedges	$	(546	)	$	(52,670	)	$	(53,216	)

	Fiscal Year Ended September 30, 2015
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(41,716	)	$	(41,716	)
Loss arising from ineffective portion of commodity contracts	—			(325		)	(325		)
Total impact on purchased gas cost	—			(42,041		)	(42,041		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(853		)	—			(853		)
Total impact from cash flow hedges	$	(853	)	$	(42,041	)	$	(42,894	)

	Fiscal Year Ended September 30, 2014
	Regulated Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	8,365	$	8,365
Gain arising from ineffective portion of commodity contracts	—			198		198
Total impact on purchased gas cost	—			8,563		8,563
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(4,230		)	—		(4,230		)
Total impact from cash flow hedges	$	(4,230	)	$	8,563	$	4,333

91

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the years ended September 30, 2016 and 2015. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.

	Fiscal Year Ended September 30
	2016			2015
	(In thousands)
Decrease in fair value:
Interest rate agreements	$	(99,029	)	$	(71,003	)
Forward commodity contracts	(11,662		)	(49,211		)
Recognition of losses in earnings due to settlements:
Interest rate agreements	347			542
Forward commodity contracts	32,117			25,448
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(78,227	)	$	(94,224	)

⁽¹⁾  Utilizing an income tax rate ranging from approximately 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, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of September 30, 2016. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2017	$	(447	)	$	(3,983	)	$	(4,430	)
2018	(649		)	(561		)	(1,210		)
2019	(673		)	(414		)	(1,087		)
2020	(698		)	(26		)	(724		)
2021	(698		)	2			(696		)
Thereafter	(15,139		)	—			(15,139		)
Total(1)	$	(18,304	)	$	(4,982	)	$	(23,286	)

⁽¹⁾  Utilizing an income tax rate ranging from approximately 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 consolidated income statements for the years ended September 30, 2016, 2015 and 2014 was an increase (decrease) in purchased gas cost of $(15.5) million, $15.5 million and $(5.0) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

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.

92

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

14.    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.

Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. The fair value of these assets is presented in Note 7.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. 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 September 30, 2016 and 2015. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(2)			September 30, 2016
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	4,851	$	—	$	—		$	4,851
Nonregulated segment	—		39,290		—		(32,515		)	6,775
Total financial instruments	—		44,141		—		(32,515		)	11,626
Hedged portion of gas stored underground	52,578		—		—		—			52,578
Available-for-sale securities
Money market funds	—		2,630		—		—			2,630
Registered investment companies	38,677		—		—		—			38,677
Bonds	—		31,394		—		—			31,394
Total available-for-sale securities	38,677		34,024		—		—			72,701
Total assets	$	91,255	$	78,165	$	—	$	(32,515	)	$	136,905
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	266,489	$	—	$	(25,670	)	$	240,819
Nonregulated segment	—		57,195		—		(57,195		)	—
Total liabilities	$	—	$	323,684	$	—	$	(82,865	)	$	240,819

93

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(3)			September 30, 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 September 30, 2016, we had $25.7 million of cash held in margin accounts to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. As of September 30, 2016 we also had $24.7 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $6.8 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 nonregulated financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $8.9 million is classified as current risk management assets.

94

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of September 30, 2016
Domestic equity mutual funds	$	26,692	$	6,419	$	(590	)	$	32,521
Foreign equity mutual funds	4,954		1,202		—			6,156
Bonds	31,296		108		(10		)	31,394
Money market funds	2,630		—		—			2,630
	$	65,572	$	7,729	$	(600	)	$	72,701
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 September 30, 2016 and 2015, our available-for-sale securities included $41.3 million and $41.7 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 7. At September 30, 2016 we maintained investments in bonds that have contractual maturity dates ranging from October 2016 through May 2020.

Other Fair Value Measures

In addition to the financial instruments above, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. The nonfinancial assets and liabilities include asset retirement obligations and pension and post-retirement plan assets. We record cash and cash equivalents, accounts receivable, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities.

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 September 30, 2016:

	September 30, 2016
	(In thousands)
Carrying Amount	$	2,460,000
Fair Value	$	2,844,990

95

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15. Subsequent Event

On October 29, 2016, AEH entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. to sell all of the equity interests of AEM for $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. We expect this transaction to close during the second quarter of fiscal 2017.

The following table summarizes the approximate value of the assets and liabilities that are part of the disposal group as of September 30, 2016:

	September 30, 2016
	(In thousands)
Assets:
Net property, plant and equipment	$	13,000
Accounts receivable	94,000
Gas stored underground	56,000
Other current assets	13,000
Goodwill	15,000
Deferred charges and other assets	300
Total assets included in disposal group	$	191,300
Liabilities:
Accounts payable and accrued liabilities	$	71,000
Other current liabilities	8,000
Deferred credits and other	200
Total liabilities included in disposal group	$	79,200

16.    Concentration of Credit Risk

Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the regulated distribution segment is mitigated by the large number of individual customers and diversity in our customer base. The credit risk for our other segments is not significant.

96

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

17.    Selected Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below. The sum of net income per share by quarter may not equal the net income per share for the fiscal year due to variations in the weighted average shares outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section herein.

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2016:
Operating revenues
Regulated distribution	$	638,602		$	849,685		$	414,226		$	389,353
Regulated pipeline	94,677			95,703			109,249			109,204
Nonregulated	272,524			287,395			214,555			291,889
Intersegment eliminations	(99,582		)	(100,490		)	(105,114		)	(111,927		)
	906,221			1,132,293			632,916			678,519
Gross profit	443,763			517,811			407,311			376,011
Operating income	196,205			250,016			137,164			84,633
Net income	102,861			141,810			71,193			34,240
Net income per share — basic	$	1.00		$	1.38		$	0.69		$	0.33
Net income per share — diluted	$	1.00		$	1.38		$	0.69		$	0.33

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2015:
Operating revenues
Regulated distribution	$	846,772		$	1,130,613		$	416,794		$	369,656
Regulated pipeline	83,567			91,730			97,008			97,807
Nonregulated	462,288			438,322			278,769			292,830
Intersegment eliminations	(133,862		)	(120,597		)	(106,170		)	(103,391		)
	1,258,765			1,540,068			686,401			656,902
Gross profit	423,285			520,738			381,673			354,321
Operating income	187,725			250,210			117,607			75,853
Net income	97,595			137,684			56,281			23,515
Net income per share — basic	$	0.96		$	1.35		$	0.55		$	0.23
Net income per share — diluted	$	0.96		$	1.35		$	0.55		$	0.23

97

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

ITEM 9A. 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 Rule 13a-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 September 30, 2016 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.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework issued by COSO and applicable Securities and Exchange Commission rules, our management concluded that our internal control over financial reporting was effective as of September 30, 2016, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Ernst & Young LLP has issued its report on the effectiveness of the Company’s internal control over financial reporting. That report appears below.

/s/    KIM R. COCKLIN	/s/    BRET J. ECKERT
Kim R. Cocklin	Bret J. Eckert
Chief Executive Officer and Director	Senior Vice President and Chief Financial Officer
November 14, 2016

98

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

We have audited Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Atmos Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Atmos Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of September 30, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of September 30, 2016 and 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2016 of Atmos Energy Corporation and our report dated November 14, 2016 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Dallas, Texas

November 14, 2016

99

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the fourth 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.

ITEM 9B. Other Information.

Not applicable.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance.

Information regarding directors and compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017. Information regarding executive officers is reported below:

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2016, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.

Name	Age	Years of Service	Office Currently Held
Kim R. Cocklin	65	10	Chief Executive Officer and Director
Michael E. Haefner	56	8	President and Chief Operating Officer and Director
Bret J. Eckert	49	4	Senior Vice President and Chief Financial Officer
Marvin L. Sweetin	53	16	Senior Vice President, Safety and Enterprise Services
Louis P. Gregory	61	16	Senior Vice President, General Counsel and Corporate Secretary

Kim R. Cocklin was named President and Chief Executive Officer effective October 1, 2010, and Chief Executive Officer of the Company on October 1, 2015. Mr. Cocklin joined the Company in June 2006 and served as President and Chief Operating Officer of the Company from October 1, 2008 through September 30, 2010, after having served as Senior Vice President, Regulated Operations from October 2006 through September 2008. Mr. Cocklin was appointed to the Board of Directors on November 10, 2009.

Michael E. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources. On January 19, 2015, Mr. Haefner was promoted to Executive Vice President and assumed oversight responsibility for Atmos Pipeline - Texas, Atmos Energy Holdings, Inc. and the gas supply and services function. On October 1, 2015, Mr. Haefner was promoted to the role of President and Chief Operating Officer in which he also assumed oversight responsibility for the operations of our six utility divisions and customer service. Mr. Haefner was appointed to the Board of Directors on November 4, 2015.

Bret J. Eckert joined the Company in June 2012 as Senior Vice President, and on October 1, 2012 he was appointed Chief Financial Officer. Prior to joining the Company, Mr. Eckert was an Assurance Partner with Ernst & Young LLP where he developed extensive accounting and financial experience in the natural gas industry over his 22-year career.

Marvin L. Sweetin was named Senior Vice President, Utility Operations in November 2011. In this role, Mr. Sweetin was responsible for the operations of our six utility divisions, as well as customer service, safety and training. On October 1, 2015, Mr. Sweetin was promoted to the position of Senior Vice President of Safety and Enterprise Services. In addition to having overall responsibility for safety and compliance for the Company, Mr. Sweetin has responsibility for business process and change management, new operations technology evaluation and deployment, supply chain and facilities management and workforce development. On November 3, 2016, Mr. Sweetin notified the Board of Directors of his retirement from the Company effective December 31, 2016.

Louis P. Gregory was named Senior Vice President and General Counsel in September 2000 as well as Corporate Secretary in June 2012.

100

David J. Park was named Senior Vice President of Utility Operations on October 28, 2016, effective January 1, 2017. In this role, Mr. Park will be responsible for the operations of Atmos Energy’s six utility divisions as well as gas supply. Prior to this promotion, Mr. Park served as the President of the West Texas Division. Mr. Park has also served as Vice President of Rates and Regulatory Affairs in the Mid-Tex Division and previously held positions in Engineering and Public Affairs.

Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors’ determination as to whether one or more audit committee financial experts are serving on the Audit Committee of the Board of Directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017.

The Company has adopted a code of ethics for its principal executive officer, principal financial officer and principal accounting officer. Such code of ethics is represented by the Company’s Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Company’s principal executive officer, principal financial officer and principal accounting officer. A copy of the Company’s Code of Conduct is posted on the Company’s website at www.atmosenergy.com under “Corporate Governance.” In addition, any amendment to or waiver granted from a provision of the Company’s Code of Conduct will be posted on the Company’s website under “Corporate Governance.”

ITEM 11. Executive Compensation.

Information on executive compensation is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Security ownership of certain beneficial owners and of management is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017. Information concerning our equity compensation plans is provided in Part II, Item 5, “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”, of this Annual Report on Form 10-K.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence.

Information on certain relationships and related transactions as well as director independence is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017.

ITEM 14. Principal Accountant Fees and Services.

Information on our principal accountant’s fees and services is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2017.

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.

(a)  1. and 2. Financial statements and financial statement schedules.

The financial statements and financial statement schedule listed in the Index to Financial Statements in Item 8 are filed as part of this Form 10-K.

3.     Exhibits

The exhibits listed in the accompanying Exhibits Index are filed as part of this Form 10-K. The exhibits numbered 10.3(a) through 10.12 are management contracts or compensatory plans or arrangements.

101

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

Date: November 14, 2016

102

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Kim R. Cocklin and Bret J. Eckert, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:

103

/s/    KIM R. COCKLIN	Chief Executive Officer and Director	November 14, 2016
Kim R. Cocklin
/s/    MICHAEL E. HAEFNER	President, Chief Operating Officer and Director	November 14, 2016
Michael E. Haefner
/s/    BRET J. ECKERT	Senior Vice President and Chief Financial Officer	November 14, 2016
Bret J. Eckert
/s/    CHRISTOPHER T. FORSYTHE	Vice President and Controller (Principal Accounting Officer)	November 14, 2016
Christopher T. Forsythe
/s/    ROBERT W. BEST	Chairman of the Board	November 14, 2016
Robert W. Best
/s/    KELLY H. COMPTON	Director	November 14, 2016
Kelly H. Compton
/s/    RICHARD W. DOUGLAS	Director	November 14, 2016
Richard W. Douglas
/s/    RUBEN E. ESQUIVEL	Director	November 14, 2016
Ruben E. Esquivel
/s/    RAFAEL G. GARZA	Director	November 14, 2016
Rafael G. Garza
/s/    RICHARD K. GORDON	Director	November 14, 2016
Richard K. Gordon
/s/    ROBERT C. GRABLE	Director	November 14, 2016
Robert C. Grable
/s/    THOMAS C. MEREDITH	Director	November 14, 2016
Thomas C. Meredith
/s/    NANCY K. QUINN	Director	November 14, 2016
Nancy K. Quinn
/s/    RICHARD A. SAMPSON	Director	November 14, 2016
Richard A. Sampson
/s/    STEPHEN R. SPRINGER	Director	November 14, 2016
Stephen R. Springer
/s/    RICHARD WARE II	Director	November 14, 2016
Richard Ware II

104

Schedule II

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2016

			Additions
	Balance at beginning of period		Charged to cost & expenses		Charged to other accounts		Deductions			Balance at end of period
			(In thousands)
2016
Allowance for doubtful accounts	$	15,283	$	10,397	$	—	$	12,313	(1)	$	13,367
2015
Allowance for doubtful accounts	$	23,992	$	15,082	$	—	$	23,791	(1)	$	15,283
2014
Allowance for doubtful accounts	$	20,624	$	19,491	$	—	$	16,123	(1)	$	23,992

⁽¹⁾  Uncollectible accounts written off.

105

EXHIBITS INDEX

Item 14.(a)(3)

Exhibit Number	Description	Page Number or Incorporation by Reference to
	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Membership Interest Purchase Agreement by and between Atmos Energy Holdings, Inc. as Seller and CenterPoint Energy Services, Inc. as Buyer, dated as of October 29 2016	Exhibit 2.1 to Form 8-K dated October 29, 2016 (File No. 1-10042)
	Articles of Incorporation and Bylaws
3.1	Restated Articles of Incorporation of Atmos Energy Corporation - Texas (As Amended Effective February 3, 2010)	Exhibit 3.1 to Form 10-Q dated March 31, 2010 (File No. 1-10042)
3.2	Restated Articles of Incorporation of Atmos Energy Corporation - Virginia (As Amended Effective February 3, 2010)	Exhibit 3.2 to Form 10-Q dated March 31, 2010 (File No. 1-10042)
3.3	Amended and Restated Bylaws of Atmos Energy Corporation (as of September 28, 2015)	Exhibit 3.1 to Form 8-K dated September 28, 2015 (File No. 1-10042)
	Instruments Defining Rights of Security Holders, Including Indentures
4.1	Specimen Common Stock Certificate (Atmos Energy Corporation)	Exhibit 4.1 to Form 10-K for fiscal year ended September 30, 2012 (File No. 1-10042)
4.2	Indenture dated as of November 15, 1995 between United Cities Gas Company and Bank of America Illinois, Trustee	Exhibit 4.11(a) to Form S-3 dated August 31, 2004 (File No. 333-118706)
4.3	Indenture dated as of July 15, 1998 between Atmos Energy Corporation and U.S. Bank Trust National Association, Trustee	Exhibit 4.8 to Form S-3 dated August 31, 2004 (File No. 333-118706)
4.4	Indenture dated as of May 22, 2001 between Atmos Energy Corporation and SunTrust Bank, Trustee	Exhibit 99.3 to Form 8-K dated May 15, 2001 (File No. 1-10042)
4.5	Indenture dated as of June 14, 2007, between Atmos Energy Corporation and U.S. Bank National Association, Trustee	Exhibit 4.1 to Form 8-K dated June 11, 2007 (File No. 1-10042)
4.6	Indenture dated as of March 23, 2009 between Atmos Energy Corporation and U.S. Bank National Corporation, Trustee	Exhibit 4.1 to Form 8-K dated March 26, 2009 (File No. 1-10042)
4.7(a)	Debenture Certificate for the 6 3/4% Debentures due 2028	Exhibit 99.2 to Form 8-K dated July 22, 1998 (File No. 1-10042)
4.7(b)	Global Security for the 5.95% Senior Notes due 2034	Exhibit 10(2)(g) to Form 10-K for fiscal year ended September 30, 2004 (File No. 1-10042)
4.7(c)	Global Security for the 6.35% Senior Notes due 2017	Exhibit 4.2 to Form 8-K dated June 11, 2007 (File No. 1-10042)
4.7(d)	Global Security for the 8.50% Senior Notes due 2019	Exhibit 4.2 to Form 8-K dated March 26, 2009 (File No. 1-10042)
4.7(e)	Global Security for the 5.5% Senior Notes due 2041	Exhibit 4.2 to Form 8-K dated June 10, 2011 (File No. 1-10042)

106

4.7(f)	Global Security for the 4.15% Senior Notes due 2043	Exhibit 4.2 to Form 8-K dated January 8, 2013 (File No. 1-10042)
4.7(g)	Global Security for the 4.125% Senior Notes due 2044	Exhibit 4.2 to Form 8-K dated October 15, 2014 (File No. 1-10042)
	Material Contracts
10.1(a)	Revolving Credit Agreement, dated as of September 25, 2015 among Atmos Energy Corporation, the Lenders from time to time parties thereto, Crédit Agricole Corporate and Investment Bank as Administrative Agent, and Mizuho Bank Ltd., as Syndication Agent	Exhibit 10.1 to Form 8-K dated October 1, 2015 (File No. 1-10042)
10.1(b)	First Amendment to Revolving Credit Agreement, dated as of October 5, 2016, by and among Atmos Energy Corporation, the lenders from time to time parties thereto (the "Lenders") and Credit Agricole Corporate and Investment Bank, in its capacity as administrative agent for the Lenders	Exhibit 10.1 to Form 8-K dated October 5, 2016 (File No. 1-10042)
10.1(c)	Term Loan Agreement, dated as of September 22, 2016, by and among Atmos Energy Corporation, the Lenders from time to time parties thereto and Branch Banking and Trust Company as Administrative Agent	Exhibit 10.1 to Form 8-K dated September 22, 2016 (File No. 1-10042)
10.2	Equity Distribution Agreement, dated as of March 28, 2016, among Atmos Energy Corporation, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC.	Exhibit 1.1 to Form 8-K dated March 28, 2016 (File No. 1-10042)
	Executive Compensation Plans and Arrangements
10.3(a)*	Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier I	Exhibit 10.7(a) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.3(b)*	Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier II	Exhibit 10.7(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.4(a)*	Atmos Energy Corporation Executive Retiree Life Plan	Exhibit 10.31 to Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)
10.4(b)*	Amendment No. 1 to the Atmos Energy Corporation Executive Retiree Life Plan	Exhibit 10.31(a) to Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)
10.5*	Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated October 1, 2016)
10.6(a)*	Atmos Energy Corporation Supplemental Executive Benefits Plan, Amended and Restated in its Entirety August 7, 2007	Exhibit 10.8(a) to Form 10-K for fiscal year ended September 30, 2008 (File No. 1-10042)
10.6(b)*	Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan	Exhibit 10.3 to Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042)
10.7(a)*	Atmos Energy Corporation Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016)
10.7(b)*	Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000	Exhibit 10.1 to Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042)

107

10.8*	Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016)
10.9(a)*	Mini-Med/Dental Benefit Extension Agreement dated October 1, 1994	Exhibit 10.28(f) to Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042)
10.9(b)*	Amendment No. 1 to Mini-Med/Dental Benefit Extension Agreement dated August 14, 2001	Exhibit 10.28(g) to Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042)
10.9(c)*	Amendment No. 2 to Mini-Med/Dental Benefit Extension Agreement dated December 31, 2002	Exhibit 10.1 to Form 10-Q for quarter ended December 31, 2002 (File No. 1-10042)
10.10*	Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2012	Exhibit 10.1 to Form 10-Q for quarter ended December 31, 2011 (File No. 1-10042)
10.11(a)*	Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated February 3, 2016)	Exhibit 99.1 to Form S-8 dated March 29, 2016 (File No. 333-210461)
10.11(b)*	Form of Award Agreement of Time-Lapse Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
10.11(c)*	Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
10.12*	Atmos Energy Corporation Outside Directors Stock-for-Fee Plan, Amended and Restated as of October 1, 2009	Exhibit 10.13 to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
12	Statement of computation of ratio of earnings to fixed charges
	Other Exhibits, as indicated
21	Subsidiaries of the registrant
23.1	Consent of independent registered public accounting firm, Ernst & Young LLP
24	Power of Attorney	Signature page of Form 10-K for fiscal year ended September 30, 2016
31	Rule 13a-14(a)/15d-14(a) Certifications
32	Section 1350 Certifications**
	Interactive Data File
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

*

This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement."

**

These certifications 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 Annual Report on Form 10-K, will not be deemed to be filed with the Securities and Exchange 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.

108

EX-10.5

Exhibit 10.5

Execution Copy

ATMOS ENERGY CORPORATION

ANNUAL INCENTIVE PLAN FOR MANAGEMENT

(as amended and restated October 1, 2016)

The Atmos Energy Corporation Annual Incentive Plan for Management (hereinafter called the “Plan”) was adopted by the Board of Directors of Atmos Energy Corporation, a Texas and Virginia corporation (hereinafter called the “Company”), on August 12, 1998 to be effective October 1, 1998 and was first approved by the Company’s shareholders on February 10, 1999. The Plan has been subsequently amended and restated, with the last amendment being approved by the shareholders on February 3, 2016.

ARTICLE 1

PURPOSE

The Plan is intended to provide the Company a means by which it can engender and sustain a sense of personal commitment on the part of its executives and senior managers in the continued growth, development, and financial success of the Company and encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company, shareholders and customers. Accordingly, the Company may award to executives and senior managers annual incentive compensation on the terms and conditions established herein.

ARTICLE 2

DEFINITIONS

For the purpose of the Plan, unless the context requires otherwise, the following terms shall have the meanings indicated:

2.1“Award” means the compensation payable under this Plan to a Participant by the Committee pursuant to such terms, conditions, restrictions, and limitations established by the Committee and the Plan.

2.2     “Board” means the Board of Directors of the Company.

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

(i)Change in Ownership. A change in ownership of the Company occurs on the date of consummation of any transaction under which any “Person” (as defined in Section 2.3(b)(i) below), other than (1) the Company or any of its subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of the Company’s stock, acquires ownership of the Company’s stock that, together with stock held by such Person, constitutes more than 50% of the total fair market value or total voting power of the Company’s stock. However, if any Person is considered to own already more than 50% of the total fair market value or total voting power of the Company’s stock, the acquisition of additional stock by the same Person is not considered to be a Change of Control. In addition, if any Person has effective control of the Company through ownership of 30% or more of the total voting power of the Company’s stock, as discussed in

paragraph (ii) below, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this paragraph (i); or

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

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

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

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

(b)For purposes of subparagraph (a) above:

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

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

(c)The provisions of this Section 2.3 shall be interpreted in accordance with the requirements of the Final Treasury Regulations under Section 409A of the Code, it

being the intent of the parties that this Section 2.3 shall be in compliance with the requirements of said Code Section and said Regulations.

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

2.5“Committee” means the committee appointed or designated by the Board to administer the Plan in accordance with Article 3 of this Plan.

2.6“Common Stock” means the common stock, with no par value (stated value of $.005 per share), which the Company currently is authorized to issue or may in the future be authorized to issue.

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

2.8     “Covered Participant” means a Participant who is a “covered employee” as defined in Section 162(m)(3) of the Code, and the regulations promulgated thereunder, or who the Committee believes will be such a covered employee for a Performance Period, as provided in Section 162(m) of the Code.

2.9    “Date of Conversion” means the date on which the Board approves the Awards which have been determined and recommended by the Committee; this is also the effective Date of Conversion for Restricted Stock Units.

2.10“Employee” means common law employee (as defined in accordance with the Regulations and Revenue Rulings then applicable under Section 3401(c) of the Code) of the Company or any Subsidiary of the Company.

2.11“Fair Market Value” of a share of Common Stock is the mean of the highest and lowest prices per share on the New York Stock Exchange Consolidated Tape, or such reporting service as the Board may select, on the appropriate date, or in the absence of reported sales on such day, the most recent previous day for which sales were reported.

2.12“Long-Term Incentive Plan” is the Atmos Energy Corporation 1998 Long-Term Incentive Plan, as amended from time to time.

2.13“Participant” means an Employee who is selected by the Committee to participate in the Plan.

2.14“Performance Criteria” or “Performance Goals” or “Performance Measures” mean the objectives established by the Committee for a Performance Period, for the purpose of determining when an Award subject to such objectives is earned.

2.15 “Performance Period” means the consecutive 12-month period that constitutes the Company’s fiscal year.

2.16      “Plan” means the Atmos Energy Corporation Annual Incentive Plan for Management, dated effective October 1, 1998, as amended from time to time.

2.17“Restricted Stock Unit” means a fixed or variable dollar denominated right to acquire Common Stock, which may or may not be subject to restrictions, contingently granted to a Participant as permitted and pursuant to the terms and provisions of the Long-Term Incentive Plan.

2.18“Subsidiary” means (i) any corporation in an unbroken chain of corporations beginning with the Company, if each of the corporations other than the last corporation in the unbroken chain owns stock possessing a majority of the total combined voting power of all classes of stock in one of the other corporations in the chain, (ii)

any limited partnership, if the Company or any corporation described in item (i) above owns a majority of the general partnership interest and a majority of the limited partnership interests entitled to vote on the removal and replacement of the general partner, and (iii) any partnership or limited liability company, if the partners or members thereof are composed only of the Company, any corporation listed in item (i) above or any limited partnership listed in item (ii) above. “Subsidiaries” means more than one of any such corporations, limited partnerships, partnerships or limited liability companies.

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

ARTICLE 3

ADMINISTRATION

The Plan shall be administered by the Human Resources Committee of the Board (the “Committee”) unless otherwise determined by the Board. If said Human Resources Committee does not so serve, the Committee shall consist of not fewer than two persons; any member of the Committee may be removed at any time, with or without cause, by resolution of the Board; and any vacancy occurring in the membership of the Committee may be filled by appointment by the Board.

All actions to be taken by the Committee under this Plan, insofar as such actions affect compliance with Section 162(m) of the Code, shall be limited to those members of the Board who are Non-employee Directors and who are “outside directors” under Section 162(m) of the Code. The Committee shall select one of its members to act as its Chairman. A majority of the Committee shall constitute a quorum, and the act of a majority of the members of the Committee present at a meeting at which a quorum is present shall be the act of the Committee.

The Committee shall determine and designate from time to time the eligible persons to whom Awards will be made. The Committee, in its discretion, shall (i) interpret the Plan, (ii) prescribe, amend, and rescind any rules and regulations necessary or appropriate for the administration of the Plan, and (iii) make such other determinations and take such other action as it deems necessary or advisable in the administration of the Plan. Any interpretation, determination, or other action made or taken by the Committee shall be final, binding, and conclusive on all interested parties.

With respect to restrictions in the Plan that are based on the requirements of Section 162(m) of the Code, Section 409A of the Code, or any other applicable law, rule or restriction (collectively, “applicable law”), to the extent that any such restrictions are no longer required by applicable law, the Committee shall have the sole discretion and authority to grant Awards hereunder that are not subject to such mandated restrictions and/or to waive any such mandated restrictions with respect to outstanding Awards.

ARTICLE 4

ELIGIBILITY

Any Employee (including an Employee who is also a director or an officer) is eligible to participate in the Plan. The Committee, upon its own action, may grant, but shall not be required to grant, an Award to any Employee. Awards may be granted by the Committee at any time and from time to time to new Participants, or to then Participants, or to a greater or lesser number of Participants, and may include or exclude previous Participants, as the Committee shall determine. The Committee’s determinations under the Plan (including without limitation determinations of which Employees, if any, are to receive Awards, the form, amount and timing of such Awards, the terms and provisions of such Awards, and the agreements evidencing same) need not be uniform and may be made by it selectively among Employees who receive, or are eligible to receive, Awards under the Plan.

ARTICLE 5

PERFORMANCE GOALS AND MEASUREMENT

5.1Performance Goals Establishment. Performance Goals shall be established by the Committee not later than 90 days after commencement of the Performance Period. The Performance Goals may be identical for all Participants or, at the discretion of the Committee, may be different to reflect more appropriate measures of individual performance.

5.2Awards. Awards shall be made annually in accordance with actual performance compared to the Performance Goals previously established by the Committee for the Performance Period.

5.3Performance Goals. Performance Goals relating to Covered Participants for a Performance Period shall be established by the Committee in writing. Performance Goals may include alternative and multiple Performance Goals and may be based on one or more business and/or financial criteria. In establishing the Performance Goals for the Performance Period, the Committee in its discretion may include one or any combination of the following criteria in either absolute or relative terms, for the Company or any Subsidiary:

(a)Total shareholder return;

(b)Return on assets, equity, capital, or investment;

(c) Pre-tax or after-tax profit levels, including: earnings per share; earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; net operating profits after tax, and net income;

(d)Cash flow and cash flow return on investment;

(e)Economic value added and economic profit;

(f)Growth in earnings per share;

(g) Levels of operating expense or other expense items as reported on the income statement, including operating and maintenance expense; and/or

(h) Measures of customer satisfaction and customer service as surveyed from time to time, including the relative improvement therein.

5.4Adjustments. The Committee is authorized to make adjustments in the method of calculating attainment of Performance Goals in recognition of: (i) items that are of an unusual nature or indicate infrequency of occurrence, (ii) changes in tax laws, (iii) changes in generally accepted accounting principles or changes in accounting principles, (iv) charges related to restructured or discontinued operations, (v) restatement of prior period financial results, and (vi) any other unusual, non-recurring gain or loss that is separately identified and quantified in the Company’s financial statements. Notwithstanding the foregoing, the Committee may, at its sole discretion, reduce the performance results upon which Awards are based under the Plan, to offset any unintended result(s) arising from events not anticipated when the Performance Goals were established, provided that such adjustment is permitted by Section 162(m) of the Code.

5.5Determination of Awards. The Award and payment of any Award under this Plan to a Covered Participant with respect to a relevant Performance Period shall be contingent upon the attainment of the Performance Goals that are applicable to such Covered Participant. The Committee shall certify in writing prior to payment of any such Award that such applicable Performance Goals relating to the Award are satisfied. Approved minutes of the Committee may be used for this purpose. The Performance Goals shall not allow for any discretion by the Committee as to an increase in any Award, but discretion to lower an Award is permissible.

ARTICLE 6

AWARDS

6.1Timing of Awards. At the first meeting of the Committee after the completion of the Performance Period, the Committee shall review the prior year’s performance in relation to the Performance Goals and shall determine and recommend to the Board the Awards for such Performance Period. Following the meeting of the Committee, the Board shall meet and approve the Awards as recommended by the Committee. The meeting of the Committee and the meeting of the Board pursuant to this Section 6.1 shall both occur within 60 days following the completion of the Performance Period.

6.2Form of Awards. Awards are paid in cash after the end of the Performance Period and as soon as administratively feasible following the Board approval as described in Section 6.1, but in no event shall such cash Awards be paid later than December 31 of the calendar year in which the Performance Period ends. However, if and as the Committee so permits, an Employee who becomes a Participant prior to the commencement of the Performance Period may voluntarily elect, prior to the commencement of the Performance Period, to convert any Award paid to him in cash in 25 percent increments, in whole or part, into Restricted Stock Units, with the value of the Restricted Stock Units (each such Unit being equal to the Fair Market Value of a share of Common Stock as of the Date of Conversion) being equal to 120% of the amount of the Award. An Employee who becomes a Participant after the commencement of the Performance Period may not voluntarily elect to convert into Restricted Stock Units any portion of any Award paid to him in cash from the date of commencement of his participation through the end of such Performance Period.

For all Restricted Stock Units received as a result of a Participant’s election to convert, on the date which is three (3) years from the Date of Conversion (the “Distribution Date”), but in no event later than December 31 of the calendar year in which the Distribution Date occurs, the Participant shall receive a distribution of shares of Common Stock equal in number to the number of Restricted Stock Units determined under this Section 6.2. These Restricted Stock Units will be granted as time-lapse restricted stock units on the Date of Conversion pursuant to the Long-Term Incentive Plan.

6.4Maximum Awards. The maximum cash Award that may be made to a Covered Participant under the Plan for any Performance Period shall be $2.0 million.

ARTICLE 7

WITHHOLDING TAXES

The Company shall have the right to deduct from any payment to be made pursuant to the Plan the amount of any taxes required by law to be withheld with respect to such payments.

ARTICLE 8

NO RIGHT TO CONTINUED EMPLOYMENT OR AWARDS

No Employee shall have any claim or right to be made an Award, and the making of an Award shall not be construed as giving a Participant the right to be retained in the employ of the Company or any of its Subsidiaries. Further, the Company and its Subsidiaries expressly reserve the right at any time to terminate the employment of any Participant free from any liability under the Plan; except that a Participant, who meets or exceeds the Performance Goals for the Performance Period and was actively employed for the full term of the Performance Period, will be eligible for an Award even though the Participant is not an active employee of the Company at the time the Committee makes Awards under the Plan.

ARTICLE 9

CHANGE IN CONTROL

Immediately upon a Change in Control, notwithstanding any other provision of this Plan, all Awards for the Performance Period in which the Change in Control occurs shall be deemed earned at the target Performance Goal level, and the Company shall make a payment in cash to each Participant within twenty (20) days after the effective date of the Change in Control in the amount of such target Award. The making of Awards under the Plan shall in no way affect the right of the Company to adjust, reclassify, reorganize, or otherwise change its capital or business structure, or to merge, consolidate, dissolve, liquidate, sell or transfer all or any portion of its businesses or assets.

ARTICLE 10

AMENDMENT, MODIFICATION, SUSPENSION, OR TERMINATION

Subject to the limitations set forth in this Article 10, the Board may at any time and from time to time, without the consent of the Participants, alter, amend, revise, suspend, or discontinue the Plan in whole or in part; provided, however, that no amendment which requires shareholder approval in order for the Plan and Awards under the Plan to continue to comply with Section 162(m) of the Code, including any successors to such Section, shall be effective unless such amendment shall be approved by the requisite vote of the shareholders of the Company entitled to vote thereon.

ARTICLE 11

GOVERNING LAW

The validity, construction and effect of the Plan and any actions taken or relating to the Plan shall be determined in accordance with the laws of the State of Texas and applicable Federal law.

ARTICLE 12

SUCCESSORS AND ASSIGNS

The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, expressly to assume and agree to perform the Company’s obligation under this Plan in the same manner and to the same extent that the Company would be required to perform them if no such succession had taken place. As used herein, the “Company” shall mean the Company as hereinbefore defined and any aforesaid successor to its business and/or assets.

ARTICLE 13

EFFECTIVE DATE AND TERM

The Plan became effective as of October 1, 1998 and will terminate as of September 30, 2021. After termination of the Plan, no future Awards may be made.

ARTICLE 14

INTERPRETATION

The Plan is designed to comply with Section 162(m) of the Code, and all provisions hereof shall be construed in a manner consistent with that intent.

ARTICLE 15

INDEMNIFICATION

No member of the Board or the Committee, nor any officer or employee of the Company acting on behalf of the Board or the Committee, shall be personally liable for any action, determination, or interpretation taken or made in good faith with respect to the Plan, and all members of the Board or the Committee and each and any officer or employee of the Company acting on their behalf shall, to the extent permitted by law, be fully indemnified and protected by the Company in respect of any such action, determination, or interpretation.

ARTICLE 16

CODE SECTION 409A COMPLIANCE

To the extent (i) any payment to which a Participant becomes entitled under this Plan in connection with the Participant’s termination of employment with the Company (for reasons other than death) constitutes a payment of deferred compensation subject to Section 409A of the Code, and (ii) the Participant is deemed at the time of such termination of employment to be a “specified employee” under Section 409A of the Code, then such payment shall not be made or commence until the earliest of (A) the expiration of the six (6) month period measured from the date of Participant’s “separation from service” (as such term is defined in final Treasury Regulations issued under Section 409A of the Code and any other guidance issued thereunder) with the Company; or (B) the date of the Participant’s death following such separation from service. Upon the expiration of the applicable deferral period, any payment which would have otherwise been made during that period in the absence of this Article 16 shall be made to the Participant or the Participant’s beneficiary.

IN WITNESS WHEREOF, the Company has caused this instrument to be executed as of September 16, 2016 by its Chief Operating Officer pursuant to prior actions taken by the Board.

ATMOS ENERGY CORPORATION

By: /s/ MICHAEL E. HAEFNER

Michael E. Haefner

President and Chief Operating Officer

Attest:

/s/ PHILLIP L. ALLBRITTEN

Phillip L. Allbritten

Associate General Counsel and

Assistant Corporate Secretary

EX-10.7(A)

Exhibit 10.7(a)

ATMOS ENERGY CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

AS AMENDED AND RESTATED

EFFECTIVE AS OF JANUARY 1, 2016

TABLE OF CONTENTS

ARTICLE I Purpose and Effective Date

Section 1.1. Purpose

Section 1.2. Effective Date

ARTICLE II Definitions and Construction

Section 2.1. Definitions

Section 2.2. Construction

Section 2.3. Governing Law

ARTICLE III Eligibility and Participation

Section 3.1. Employees Eligible to Participate

ARTICLE IV Assets Used for Benefits

Section 4.1. Amounts Provided by the Employer

Section 4.2. Funding

ARTICLE V Supplemental Pension Benefits

Section 5.1. Eligibility for Supplemental Pension

Section 5.2. Amount of Supplemental Pension

Section 5.3. Form of Payment of Supplemental Pension

Section 5.4. Commencement of Supplemental Pension

Section 5.5. Supplemental Pensions After a Change in Control

ARTICLE VI Disability Benefits

Section 6.1. Eligibility For Disability Benefit

Section 6.2. Amount of Disability Benefit

Section 6.3. Payment of Disability Benefit

Section 6.4. Payment of Supplemental Pension to Disabled Participants

ARTICLE VII Death Benefits

Section 7.1. Eligibility For Death Benefit

Section 7.2. Amount of Death Benefit

Section 7.3. Form of Payment of Death Benefits

Section 7.4. Commencement of Death Benefits

ARTICLE VIII Administration

Section 8.1. Plan Administration

Section 8.2. Powers of Plan Administrator

Section 8.3. Calculation of Funding Obligations

Section 8.4. Annual Statements

ARTICLE IX Miscellaneous Provisions

Section 9.1. Amendment or Termination of the Plan

Section 9.2. Nonguarantee of Employment

Section 9.3. Nonalienation of Benefits

Section 9.4. Liability

Section 9.5. Participation Agreement

Section 9.6. Successors to the Employer

Section 9.7. Tax Withholding

Exhibit A Summary of Actuarial Assumptions for Determining Lump Sum Distributions and Optional Annuity Forms

Exhibit B Summary of Actuarial Assumptions and Methods for Determining Supplemental Executive Retirement Plan Trust Annual Funding Liabilities

ARTICLE I

Purpose and Effective Date

Section 1.1.Purpose:The purpose of the Atmos Energy Corporation Supplemental Executive Retirement Plan (the “Plan”) is to provide supplemental retirement income, death and disability benefits to certain executive employees of Atmos Energy Corporation. The Plan is intended to be unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees so as to be exempt from the requirements of Parts 2, 3 and 4 of Title I of ERISA, and shall be so interpreted.

Section 1.2.Effective Date: The Plan, as previously amended and restated effective as of August 7, 2007, was an amendment and restatement of the Performance-Based Supplemental Executive Benefits Plan which was adopted effective August 12, 1998. The August 7, 2007 Plan was subsequently amended and restated effective as of June 4, 2012, and is being amended and restated again, effective as of January 1, 2016 (the “Effective Date”). The Plan as amended and restated shall apply generally to any participant in the Prior Plan (as defined below) who did not terminate employment prior January 1, 2016. Except as otherwise provided herein, any Eligible Employee who was a participant in the Prior Plan and who terminated employment prior to January 1, 2016, shall be entitled to those benefits, if any, provided by the Prior Plan.

ARTICLE II

Definitions and Construction

Section 2.1.Definitions: The following words and phrases used in the Plan shall have the respective meanings set forth below, unless the context in which they are used clearly indicates a contrary meaning:

(a)Beneficiary: The individual or individuals described in Section 7.3 of the Plan who are receiving any benefit payments hereunder.

(b)Board of Directors: The Board of Directors of the Employer.

(c)Cause: The termination of employment by the Employer upon the happening of either (i) or (ii) as follows:

(i)The willful and continued failure by the Participant to substantially perform his duties with the Employer (other than any such failure resulting from the Participant’s incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Participant by the Employer that specifically identifies the manner in which the Employer believes that the Participant has not substantially performed his duties.

(ii)The Participant’s willful engagement in conduct that is demonstrably and materially injurious to the Employer, monetarily or otherwise.

For purposes of this paragraph, no act, or failure to act, on the Participant’s part shall be deemed “willful” if done, or omitted to be done, by the Participant in good faith and with a reasonable belief that the action or omission was in the best interests of the Employer. Notwithstanding the foregoing, the Participant shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to the Participant a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters (3/4) of the entire membership of the Board of Directors of the Employer at a meeting of such Board of Directors called and held for such purpose (after reasonable notice to the Participant and an opportunity for the Participant, together with the Participant’s counsel, to be heard before the Board of Directors), finding that in the good faith opinion of the Board of Directors that the Participant was guilty of conduct set forth above in subparagraph (i) or (ii) and specifying the particulars thereof in detail.

(d)Change in Control:

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

(A)Change in Ownership. A change in ownership of the Employer occurs on the date that any “Person” (as defined in subparagraph (ii) below), other than (1) the Employer or any of its subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Employer or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the shareholders of the Employer in substantially the same proportions as their ownership of the Employer’s stock, acquires ownership of the Employer’s stock that, together with stock held by such Person, constitutes more than 50% of the total fair market value or total voting power of the Employer’s stock. However, if any Person is considered to own already more than 50% of the total fair market value or total voting power of the Employer’s stock, the acquisition of additional stock by the same Person is not considered to be a Change of Control. In addition, if any Person has effective control of the Employer through ownership of 30% or more of the total voting power of the Employer’s stock, as discussed in subparagraph (i)(B) below, the acquisition of additional control of the Employer by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (i)(A); or

(B)Change in Effective Control. Even though the Employer may not have undergone a change in ownership under subparagraph (i)(A) above,

a change in the effective control of the Employer occurs on either of the following dates:

(1)the date that any Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Employer’s stock possessing 30 percent or more of the total voting power of the Employer’s stock. However, if any Person owns 30% or more of the total voting power of the Employer’s stock, the acquisition of additional control of the Employer by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (i)(B)(1); or

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

(C)Change in Ownership of Substantial Portion of Assets. A change in the ownership of a substantial portion of the Employer’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Employer, that have a total gross fair market value equal to at least 40% of the total gross fair market value of all of the Employer’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the shareholders of the Employer immediately after the transfer, through a transfer to (1) a shareholder of the Employer (immediately before the asset transfer) in exchange for or with respect to the Employer’s stock; (2) an entity, at least 50% of the total value or voting power of the stock of which is owned, directly or indirectly, by the Employer; (3) a Person that owns directly or indirectly, at least 50% of the total value or voting power of the Employer’s outstanding stock; or (4) an entity, at least 50% of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least 50% of the total value or voting power of the Employer’s outstanding stock.

(ii)For purposes of subparagraph (i) above:

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

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

(iii)The provisions of this Section 2.1(d) shall be interpreted in accordance with the requirements of the Final Treasury Regulations under Code Section 409A, it being the intent of the parties that this Section 2.1(d) shall be in compliance with the requirements of said Code Section and said Regulations.

(e)Code: The Internal Revenue Code of 1986, as amended, or any successor thereto.

(f)Compensation: Except as otherwise provided in the Participant’s Participation Agreement, the sum of (i) and (ii) as follows:

(i)The greater of (A) the Participant’s annual base salary with the Employer at the date of his termination of employment, or (B) the average of the Participant’s annual base salary for the highest three (3) calendar years (whether or not consecutive) of the Participant’s employment with the Employer.

(ii)The greater of (A) the Participant’s last Performance Award, or (B) the average of the highest three (3) Performance Awards (whether or not consecutive).

(g)Covered Employment: For Eligible Employees who were Participants on November 12, 2008, the total period of employment with the Employer. For Eligible Employees who have become Participants on and after November 13, 2008, the total period of employment with the Employer while a Participant in the Plan.

(h)Death Benefit: The total benefit provided under the Plan upon the death of a Participant, which benefit is calculated in the Plan on a pre‑tax basis.

(i)Disability: Satisfaction of the following two requirements: (i) a disability as determined under the Group Long-Term Disability Plan, as in effect from time to time, and (ii) a determination that the termination of a Participant’s active employment with the Employer is on account of a medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, for which the Participant is receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Employer.

(j)Disability Benefit: The monthly benefit provided under the Plan to a Participant who suffers a Disability, which benefit is calculated in the Plan on a pre‑tax basis.

(k)Eligible Employee: An employee of the Employer who prior to January 1, 2016, was selected by the Board of Directors to participate in the Plan. From and after January 1, 2016, no employee of the Employer who was not a Participant in the Plan on January 1, 2016 may be selected by the Board of Directors to participate in the Plan.

(l)Employer: Atmos Energy Corporation.

(m)ERISA: The Employee Retirement Income Security Act of 1974, as amended.

(n)FACC Participant: A Participant who receives an allocation of Fixed Annual Company Contributions.

(o)Fixed Annual Company Contribution or FACC: The contribution provided for in Section 4.03 of the Retirement Savings Plan, or any successor provision.

(p)Group Long‑Term Disability Plan: The Atmos Energy Corporation Group Long‑Term Disability Plan, as amended from time to time.

(q)Involuntary Termination: The termination of a Participant’s participation in the Plan due to either (i) or (ii) as follows:

(i)Involuntary termination of the Participant’s employment by the Employer, provided said termination constitutes a Separation from Service and such termination is for any reason other than Cause or Disability.

(ii)Any reason other than for Cause by the Employer prior to the Participant’s Separation from Service with the Employer.

(r)Participant: An Eligible Employee of the Employer who meets the requirements to participate in the Plan in accordance with the provisions of Article III hereof.

(s)Participation Agreement: The agreement between the Employer and a Participant described in Section 9.5 of the Plan and entered into at the time such Participant became a Participant in the Plan.

(t)Plan: The Atmos Energy Corporation Supplemental Executive Retirement Plan, as set forth herein and as amended from time to time.

(u)Pension Plan: Any defined benefit pension plan adopted, established or maintained by the Employer, whichever is applicable, as amended from time to time. Any amount payable to or with respect to a Participant from any group annuity contract maintained in connection with the Pension Plan shall be deemed part of the benefit applicable to the Participant under the Pension Plan.

(v)Pension Plan Participant: A Participant who is a participant in the Pension Plan and who did not cease active participation in the Pension Plan from and after January 1, 2011.

(w)Performance Awards: Except as otherwise provided in the Participant’s Participation Agreement, any amount paid, or authorized to be paid, to a Participant while a Participant in the Plan pursuant to any annual performance bonus or incentive compensation plan adopted or established by the Employer, or, upon and after a Change in Control, any amount paid, or authorized to be paid, to a Participant as a performance related cash bonus in addition to his base cash compensation. Notwithstanding the foregoing, Performance Awards shall not include any Employer stock award granted under the 1998 Long-Term Incentive Plan or other incentive plan, other than a stock award which is elected by a participant under an incentive plan to be received in lieu of cash.

(x)Plan Administrator: The Board of Directors.

(y)Plan Year: Each twelve (12) month period beginning on January 1 and ending on December 31.

(z)Prior Plan: The Atmos Energy Corporation Supplemental Executive Retirement Plan or its predecessor, as in effect at any time prior to the Effective Date.

(aa)Retired Participant: A Participant under the Plan who receives benefits upon Retirement.

(bb)Retirement or Retire: A Participant’s voluntary termination from employment with the Employer that constitutes a Separation from Service after he (i) is vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, and (ii) has attained age 55 and completed three (3) years of Covered Employment.

(cc)Retirement Savings Plan or RSP: The defined contribution benefits plan adopted, established and maintained by the Employer, as amended from time to time.

(dd)Separation from Service: A Participant’s termination from employment with the Employer that constitutes a “separation from service” as defined in Section 1.409A-1(h) of the Final Treasury Regulations under Code Section 409A, or any successor provision thereto.

(ee)Supplemental Pension: A Participant’s benefit provided under the Plan, which benefit is calculated in the Plan on a pre‑tax basis.

(ff)The expressions listed below shall have the meanings stated in the subparagraphs hereof respectively indicated:

“Affiliate”subparagraph 2.1(d)(ii)(B)

“Dependent Death Benefit”subparagraph 7.2(a)(iii)

“Fixed Annual Company

Contribution Portion”subparagraph 5.2(a)(ii)(B)

“Lump Sum Death Benefit”subparagraph 7.2(a)(i)

“Monthly Death Benefit”subparagraph 7.2(a)(ii)

“Original Payment Date”subparagraph 5.4(c)

“Person”subparagraph 2.1(d)(ii)(A)

“SERP Monthly Pension”subparagraph 5.2(a)(i)

“Specified Employee”subparagraph 5.4(c)

Section 2.2.Construction: The masculine gender, whenever appearing in the Plan, shall be deemed to include the feminine gender; the singular may include the plural; and vice versa, unless the context clearly indicates to the contrary.

Section 2.3.Governing Law: The Plan shall be construed in accordance with and governed by the laws of the State of Texas, except to the extent otherwise preempted by ERISA or any other Federal law.

ARTICLE III

Eligibility and Participation

Section 3.1.Employees Eligible to Participate: Each participant in the Prior Plan who terminated employment prior to January 1, 2016, shall be entitled to the benefits provided in the Prior Plan as in effect at the time of such employment termination. Each Participant who is an Eligible Employee on January 1, 2016, shall remain a Participant and shall continue to participate in the Plan as otherwise provided herein. Any Participant who ceases being an Eligible Employee during his employment with the Employer shall immediately cease active participation in the Plan and shall no longer be a Participant, except as otherwise set forth herein.

ARTICLE IV

Assets Used for Benefits

Section 4.1.Amounts Provided by the Employer: Benefits payable under the Plan shall constitute general obligations of the Employer in accordance with the terms of the Plan. The Employer may, in its sole discretion, establish a trust or other funding arrangement that is subject to the claims of the Employer’s general unsecured creditors for the purpose of funding a Participant’s accrued benefit payable under the Plan. Any such trust or other funding arrangement may also provide for the distribution to the Participant of an amount equal to any federal, state, local or other taxes that are incurred by the Participant in the event the establishment of such trust or other funding arrangement constitutes the constructive receipt by the Participant of any benefits payable hereunder prior to the actual receipt of such benefits. The Employer shall make appropriate adjustments to the amount of the Participant’s Supplemental Pension in order to reflect the effect upon such Supplemental Pension of the distribution described in the foregoing sentence. The Employer also may, but shall not be obligated to, purchase one or more life insurance policies or contracts to provide for the payment of the Death Benefits. Any such policies or contracts purchased hereunder shall remain a general asset of the Employer or of any trust established hereunder.

Section 4.2.Funding: Immediately upon a Change in Control, the Employer shall contribute to a trust or other funding arrangement an amount necessary to fund 100% of the then‑present value of all Supplemental Pension benefits (vested and unvested) payable hereunder to each Participant and Retired Participant, regardless of whether any such person is then eligible to Retire or to receive an unreduced Supplemental Pension. The Employer shall review the funding status of each such trust or other funding arrangement required to be established under this Section 4.2 on an annual basis and shall make such contributions thereto as may be required to maintain the value of the assets thereof at no less than 100% of the then‑present value of all such Supplemental Pension benefits.

ARTICLE V

Supplemental Pension Benefits

Section 5.1.Eligibility for Supplemental Pension:

(a)Upon Retirement: Except as otherwise provided elsewhere in the Plan or in a Participation Agreement, an Eligible Employee who has at least three (3) years of Covered Employment and who Retires shall be entitled to receive a Supplemental Pension.

(b)Upon Involuntary Termination: A Participant who suffers an Involuntary Termination shall be entitled to receive a Supplemental Pension, subject to the provisions of Section 5.1(c) of the Plan, so long as he is vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, at the time of his Involuntary Termination and has at least three (3) years of Covered Employment prior to the Involuntary Termination.

(c)Upon Voluntary Termination Prior to Retirement or Termination For Cause: A Participant who voluntarily resigns from employment with the Employer prior to being eligible for Retirement or who is terminated from employment with the Employer for Cause shall not be entitled to receive a Supplemental Pension.

(d)Upon Disability: A Participant who suffers a Disability shall be entitled to a Supplemental Pension as provided in Section 6.4, without regard to his or her number of years of Covered Employment.

Section 5.2.Amount of Supplemental Pension:

(a)Upon Retirement: Except as otherwise provided in the Participant’s Participation Agreement, the Supplemental Pension payable to a Participant who Retires and has at least three (3) years of Covered Employment shall, unless reduced as provided in subparagraph (b) below, and based on the normal form of payment specified in Section 5.3(b)(i) or (ii), depending on the marital status of the Participant at Retirement, equal to subparagraph (i) or (ii) as follows:

(i)(A)In the case of a Pension Plan Participant, one-twelfth (1/12^th) of sixty percent (60%) of the Participant’s Compensation, reduced if the Participant has fewer than ten full (10) years of Covered Employment by one‑tenth (1/10th) for each full year of his Covered Employment less than ten (10) (no credit shall be given for any partial year of Covered Employment) (referred to in this Section 5.2 as the “SERP Monthly Pension”); minus

(B)The monthly amount of pension payable to the Pension Plan Participant under the Pension Plan as of the date that his Supplemental Pension commences, assuming payment in the automatic form applicable to him under Section 5.3(b).

(ii)(A)In the case of an FACC Participant, the actuarially equivalent lump sum value of the SERP Monthly Pension; minus

(B)The “Fixed Annual Company Contributions Portion” (as defined in section 2.01(o) of the RSP) of the FACC Participant’s Employer Contributions Account under the RSP.

The actuarially equivalent lump sum value referred to in subparagraph (ii)(A) above shall be determined as of the date that the Participant’s Supplemental Pension is paid or is scheduled to be paid pursuant to Section 5.4(a) or Section 5.4(b), as applicable, without regard to Section 5.4(c), (1) using the actuarial assumptions used for determining actuarially equivalent lump sums as set forth in Exhibit A hereto, and (2) assuming payment in the automatic form applicable to him under Section 5.3(b).

(b)Reduction for Early Commencement of Supplemental Pensions: Except as provided in subparagraph (c) below and Section 5.5(c) and Section 9.1(c), if a Participant’s Supplemental Pension is scheduled to be paid pursuant to Section 5.4(a) without regard to Section 5.4(c), before the Participant attains age 62, the amount determined under subparagraph (a)(i)(A) above shall, unless otherwise provided in a Participation Agreement, be reduced by 2% per year for the first two (2) years (or fractional years thereof, based on full months) that such scheduled date of payment precedes age 62, and by 4% per year for the next five (5) years (or fractional years thereof, based on full months) that such scheduled date of payment precedes age 60.

(c)Upon Involuntary Termination: The Supplemental Pension payable to a Participant who suffers an Involuntary Termination shall be determined in accordance with subparagraph (a) above, but, except as otherwise provided in the Participant’s Participation Agreement, for purposes of subparagraph (a)(i)(A) and as applicable under subparagraph (a)(ii)(A), shall be based upon his Compensation and full years of Covered Employment calculated as of the date of his Involuntary Termination. In addition, in the case of an Eligible Employee who becomes a Participant on or after November 12, 2009, if such Participant’s Supplemental Pension is scheduled to be paid pursuant to Section 5.4(a) without regard to Section 5.4(c), before the Participant attains age 62 pursuant to Section 5.4(b), the amount determined under subparagraph (a)(i)(A) and as applicable under subparagraph (a)(ii)(A) above shall be reduced by 2% per year for the first two (2) years (or fractional years thereof, based on full months) that such scheduled date of payment precedes age 62, by 4% per year for the next five (5) years (or fractional years thereof, based on full months) that such scheduled date of payment precedes age 60, and actuarially reduced in accordance with the actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, for each full month that such scheduled date of payment precedes age 55.

Section 5.3.Form of Payment of Supplemental Pension:

(a)Lump Sum Payments: Each Participant shall be paid his Supplemental Pension in a lump sum payment, as follows:

(i) Pension Plan Participants. Equal to the actuarially equivalent lump sum value of the normal form of Supplemental Pension payment provided for in subparagraph (b)(i) or (ii) below, based on his marital status when his Supplemental Pension is paid or is scheduled to be paid pursuant to Section 5.4(a) without regard to Section 5.4(c). The actuarial equivalents provided for in this subparagraph (i) will be determined on the basis of the actuarial assumptions used for determining actuarially equivalent lump sums as set forth in Exhibit A hereto.

(ii)FACC Participants. Equal to the actuarially equivalent lump sum value provided for in Section 5.2(a)(ii).

(b)Normal Form of Supplemental Pension: The normal form of Supplemental Pension payment shall be determined in accordance with the following provisions:

(i)Married Participants. If the Participant is married when his Supplemental Pension is paid or is scheduled to be paid pursuant to Section 5.4(a) without regard to Section 5.4(c), the normal form of payment shall be a joint and 50% survivor annuity, with the Participant’s spouse on the date payment is made or is scheduled to be made pursuant to Section 5.4(a) without regard to Section 5.4(c), as the joint annuitant. If a Participant’s spouse dies between the date the Supplemental Pension is scheduled to be paid and the date the Supplemental Pension actually is paid, such Participant shall be treated as unmarried for purposes of this subparagraph (b)(i).

(ii)Unmarried Participants. If the Participant is not married when his Supplemental Pension is paid or is scheduled to be paid pursuant to Section 5.4(a) without regard to Section 5.4(c), the normal form of payment shall be a life annuity, payable monthly, but guaranteed for a period of 120 months, payable to the Participant or the Participant’s named Beneficiary. If an unmarried Participant becomes married between the date the Supplemental Pension is scheduled to be paid and the date the Supplemental Pension actually is paid, such Participant shall be treated as married for purposes of this subparagraph (b)(ii).

Section 5.4.Commencement of Supplemental Pension:

(a)Upon Retirement: Except as otherwise provided in subparagraph (c) below, the Supplemental Pension of a Participant who Retires shall be paid on the first day of the month following the month in which such Participant Retires.

(b)Upon Involuntary Termination: The Supplemental Pension of a Participant who suffers an Involuntary Termination shall, except as otherwise provided in subparagraph (c) below, be paid (i) in the case of an Eligible Employee who was a Participant prior to November 12, 2009, at the later of (A) the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer, or (B) the first day of the month following the month in which such Participant attains age 55, and (ii) in the case of an Eligible Employee who becomes a Participant on

or after November 12, 2009, on the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer.

(c)Six Months Delay in Payment: Notwithstanding the foregoing provisions of this Section 5.4, Section 5.5(c) and Section 9.1(c), if a Participant who is entitled to payments under said applicable Section is a “Specified Employee,” as defined in § 1.409A-1(i) of the Final Regulations under Code Section 409A, and the Supplemental Pension would otherwise be paid (the “Original Payment Date”) before a date which is at least six (6) months following the date of the Participant’s Separation from Service, the Supplemental Pension shall be paid onthe date which is six (6) months following the date of the Participant’s Separation from Service (or, if earlier, the date of death of the Participant), provided the six (6) months delay requirements of Code Section 409A otherwise apply to the payments under said applicable Section. All payments which are delayed as provided in this subparagraph (c) shall accrue interest for the period from the Original Payment Date until the date such payment is actually made. Said interest shall be equal to the applicable segment rates as defined in Code Section 417(e)(3)(D), without regard to the phase-in percentages specified in Code Section 417(e)(3)(D)(iii), for the November (from and after January 1, 2010, the September) preceding the first day of the calendar year in which the participant retires or otherwise becomes entitled to payments without regard to this Section 5.4(c).

Section 5.5.Supplemental Pensions After a Change in Control:

(a)Eligibility For Supplemental Pension: Notwithstanding anything to the contrary in the Plan, a Participant shall be entitled to a Supplemental Pension, regardless of whether he has at least three (3) years of Covered Employment, and regardless of whether such Participant is vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, if following a Change in Control of the Employer which occurs at a time when he is an Eligible Employee, either (i) or (ii) occurs:

(i)The Participant incurs a Separation from Service

(A)on account of Disability; or

(B)involuntarily by the Employer for any reason other than for Cause.

(ii)The Participant’s participation in the Plan is terminated by the Employer for any reason other than for Cause prior to his Separation from Service with the Employer.

In order for the provisions of this Section 5.5 to apply, the involuntary Separation from Service referred to in subparagraph (i)(A) above or the termination of participation referred to in subparagraph (ii) above must occur within three (3) years after the Change in Control.

If a Participant incurs a Separation from Service involuntarily by the Employer for any reason other than for Cause, or his participation in the Plan is terminated by the Employer for any reason other than for Cause, prior to a Change in Control (whether or not a Change in Control ever occurs) and such Separation either (A) was at the request or direction of a person who has entered into an agreement with the Employer, the consummation of which would constitute a Change in Control, or (B) was otherwise in connection with or in anticipation of a Change in Control (whether or not a

Change in Control ever occurs), then such Participant’s Separation from Service or termination of participation shall be deemed to have followed a Change in Control of the Employer, and such Participant shall be one who is described in this subparagraph (a).

(b)Amount of Supplemental Pension: The Supplemental Pension payable to a Participant described in subparagraph (a) above shall be calculated in the same manner as set forth in Section 9.1(c) for benefits payable in the event of a termination of the Plan, but based on his Compensation as of the date of his Separation from Service or the date his participation in the Plan is terminated, whichever is applicable.

(c)Commencement of Supplemental Pension: Except as otherwise provided in Section 5.4(c), the Supplemental Pension payable to a Participant described in subparagraph (a) above shall be paid (i) in the case of an Eligible Employee who was a Participant prior to November 12, 2009, at the later of (A) the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer, or (B) the first day of the month following the month in which such Participant attains age 55, and (ii) the case of an Eligible Employee who becomes a Participant on or after November 12, 2009, on the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer. In the case of an Eligible Employee who becomes a Participant on or after November 12, 2009, if such Participant’s Supplemental Pension is paid without regard to Section 5.4(c) before the Participant attains age 55, the amount determined under subparagraph (b) above shall be actuarially reduced, in accordance with the actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, for each full month that the date of commencement precedes age 55.

ARTICLE VI

Disability Benefits

Section 6.1.Eligibility For Disability Benefit: A Participant who is an Eligible Employee and otherwise is actively participating in the Plan shall be entitled to a Disability Benefit if he suffers a Disability prior to his Retirement. A Participant’s active employment with the Employer shall be terminated at the time such Participant suffers a Disability.

Section 6.2.Amount of Disability Benefit: The Disability Benefit payable to an eligible Participant shall equal (a) minus (b) as follows:

(a)One‑twelfth (1/12th) of sixty percent (60%) of the Participant’s Compensation calculated as of the date of his Disability.

(b)The total monthly amount of disability benefit payable to the Participant under the Group Long‑Term Disability Plan (before any offsets) as of the date that his employment terminates due to Disability.

Section 6.3.Payment of Disability Benefit: A Participant’s Disability Benefit shall be paid commencing on the 181^st day following the date of his Disability and shall continue for so long as benefits are paid due to a Disability.

Section 6.4.Payment of Supplemental Pension to Disabled Participants:

(a)Upon Reaching Age 65: If a Participant who has suffered a Disability reaches age 65 while still receiving a Disability Benefit, such Participant shall be entitled to a Supplemental Pension, to be paid on the first day of the month following the month in which such Participant attains age 65, regardless of whether he has at least three (3) years of Covered Employment. The Supplemental Pension payable to such Participant shall be in the form provided in Section 5.3 and determined in accordance with Section 5.2(a). Upon payment of a Participant’s Supplemental Pension under this Section 6.4(a), such Participant’s Disability Benefit under Section 6.3 hereof shall cease.

(b)Prior to Reaching Age 65: Notwithstanding the provisions of subparagraph (a) above, a Participant receiving a Disability Benefit shall receive a Supplemental Pension to be paid on the first day of the month following the month in which occurs the later of (i) such Participant’s 62^nd birthday, or (ii) such Participant’s entitlement to an unreduced Supplemental Pension under Section 5.2(a)(i)(A) or as applicable under Section 5.2(a)(ii)(A), if such month occurs prior to such Participant’s 65^th birthday. If a Participant becomes entitled to a Supplemental Pension pursuant to this subparagraph (b), the Participant’s Disability Benefits shall cease, and such Supplemental Pension shall be in the form provided for in Section 5.3, determined in accordance with Sections 5.2(a)and(b), but without regard to whether he has at least three (3) years of Covered Employment, and shall be based on the Participant’s Compensation as of the date that such individual suffered a Disability.

ARTICLE VII

Death Benefits

Section 7.1.Eligibility For Death Benefit: A Participant’s Beneficiary shall be entitled to a Death Benefit if the Participant meets the requirements of either (a), (b) or (c) as follows:

(a)He dies before his employment with the Employer terminates or while receiving a Disability Benefit under the Plan.

(b)He Retires but dies before the payment of his Supplemental Pension.

(c)He is entitled to a Supplemental Pension pursuant to the provisions of Section 5.1(b) or Section 5.5(a) of the Plan, but dies before the payment of his Supplemental Pension.

Section 7.2.Amount of Death Benefit:

(a)In-Service Death: In the case of a Participant who dies as provided in Section 7.1(a), the Death Benefit will be the total of the following (i), (ii) and (iii):

(i)A lump sum payment equal to two times the Participant’s Compensation minus any amount payable under the Employer’s Group Basic Life Insurance Plan (the “Lump Sum Death Benefit”).

(ii)A monthly benefit equal to one-twelfth of an amount equal to fifty percent of the Participant’s Compensation at the time of his death (the “Monthly Death Benefit”).

(iii)If the Participant leaves a child or children to whom payments are to be made under Section 7.3 hereof, a monthly benefit equal to one-twelfth of an amount equal to twenty-five percent (25%) of the Participant’s Compensation at the time of his death (the “Dependent Death Benefit”).

(b)Post-Retirement Death: In the case of a Participant who dies as provided in Section 7.1(b), a Death Benefit will be paid to the Beneficiary entitled to receive the Death Benefit pursuant to Section 7.3(a) below. The amount of such Death Benefit shall be equal to the lump sum amount such Participant would have been entitled to receive had the Participant’s Supplemental Pension been paid in the month of his death, plus interest, if applicable, through the date of his death pursuant to Section 5.4(c) as if the date of his death were the end of the six months delay period.

(c)Deferred Retirement Death: In the case of a Participant who dies as provided in Section 7.1(c), a Death Benefit will be paid as provided in (i) or (ii) as follows:

(i)In the case of a Participant who dies prior to reaching age 55, a Death Benefit will be paid to the Beneficiary who would have been so entitled at the time of his death in a lump sum amount equal to (1) in the case of an Eligible Employee who was a Participant prior to November 12, 2009, the actuarially equivalent lump sum value of the survivor benefit that would have been paid under the form applicable under Section 5.3(b)(i) or (ii) had the Participant lived to age 55, commenced his Supplemental Pension in the month immediately following the month in which he reached age 55 and died immediately after his Supplemental Pension commenced, as reduced actuarially, in accordance with the actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, on the basis of the Beneficiary’s age, to reflect commencement of such Death Benefit pursuant to Section 7.4(b) prior to such Participant reaching age 55, and (2) in the case of an Eligible Employee who becomes a Participant on or after November 12, 2009, the actuarially equivalent lump sum value of the survivor benefit that would have been paid under the form applicable under Section 5.3(b)(i) or (ii) had his Supplemental Pension, determined on the basis of the actuarial assumptions attributable to such Participant, as set forth in Section 5.2(c), commenced in the month immediately following his date of death, and died immediately after his Supplemental Pension commenced, as reduced actuarially, in accordance with the actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, on the basis of the Beneficiary’s age, to reflect commencement of such Death Benefit pursuant to Section 7.4(b) prior to such Participant reaching age 55.

(ii)In the case of a Participant who dies after reaching age 55, a Death Benefit will be paid to the Beneficiary (1) in the case of an Eligible Employee who was a Participant prior to November 12, 2009, in the amount provided for in Section 7.2(b) above, or (2) in the case of an Eligible Employee who has become a Participant on or after November 12, 2009, in the amount provided for in Section 7.2(b) above, except that if such Participant dies prior to reaching age 62, such amount shall be actuarially reduced, in accordance with the actuarial assumptions for conversion of a

life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, for each full month that the date of commencement precedes age 62.

(iii)For purposes of this Section 7.2(c), the actuarially equivalent lump sum value and the actuarially equivalent alternative annuity forms of Supplemental Pension payments shall be determined in accordance with the actuarial assumptions set forth in Exhibit A hereto.

Section 7.3.Form of Payment of Death Benefits:

(a)Lump Sum and Monthly Death Benefits: The Lump Sum Death Benefit, the Monthly Death Benefit, the Death Benefit provided for in Section 7.2(b) and the Death Benefit provided for in Section 7.2(c) are payable to the Participant’s designated Beneficiary. In the event that no Beneficiary has been effectively designated as provided with respect to the Death Benefits described in the preceding sentence, the Participant’s surviving spouse shall be deemed the designated Beneficiary, or if the Participant has no surviving spouse, his children, if any, per stirpes, and if none, the estate of the Participant shall be deemed the designated Beneficiary. If a Beneficiary entitled to receive a Death Benefit that is a survivor annuity payment hereunder dies before commencement of payment of that Death Benefit, then that Death Benefit shall not be payable from the Plan. The Monthly Death Benefit shall be a single life annuity, if the Participant’s surviving spouse is the designated Beneficiary, and shall be a 120-month term certain annuity, if someone other than the surviving spouse is the Participant’s designated Beneficiary.

(b)Dependent Death Benefit: The Dependent Death Benefit is payable to the Participant’s dependent children in equal shares until there cease to be any dependent children remaining. As each child loses his or her dependent status, the child’s share of the Dependent Death Benefit shall be paid to the remaining dependent child or children in equal shares. A child of the Participant is deemed to be a dependent until the child reaches age eighteen or, if a full-time student (i.e. enrolled in twelve hours or more of courses of higher education), age 25, or until the child’s death if earlier. At the discretion of the Plan Administrator, any dependent child’s share of the Dependent Death Benefit may be paid to the Participant’s surviving spouse or other guardian of such child if applicable and shall constitute full settlement of the Plan’s obligation to such child with respect to such payment. If the Participant’s surviving spouse is the designated Beneficiary for the Monthly Death Benefit and dies while receiving the Monthly Death Benefit and while any dependent child or children of the Participant remain, then the Monthly Death Benefit being paid to the surviving spouse shall be added to the Dependent Death Benefit and shall be payable in equal shares to the dependent children in the same manner and for the same time period as the Dependent Death Benefit.

Section 7.4.Commencement of Death Benefits:

(a)The Death Benefits payable pursuant to Section 7.2(a) shall be paid, with respect to the Lump Sum Death Benefit, or shall commence, with respect to the Monthly Death Benefit and the Dependent Death Benefit, as of the first day of the month next following the Participant’s death.

(b)The Death Benefits payable pursuant to Sections 7.2(b) and (c) shall paid as of the first day of the month next following the Participant’s death.

ARTICLE VIII

Administration

Section 8.1.Plan Administration: The Plan shall be administered by the Board of Directors. The Board of Directors may, in its sole discretion, establish a committee to carry out the day-to-day administration of the Plan and may delegate any portion of its authority and responsibilities as Plan Administrator to such committee.

Section 8.2.Powers of Plan Administrator: The Plan Administrator shall have the discretionary power and authority to interpret and administer the Plan according to its terms, including the power to construe and interpret the Plan, to supply any omissions therein, to reconcile and correct any errors or inconsistencies, to decide any questions in the administration and application of the Plan, and to make equitable adjustments for any mistakes or errors in the administration and application of the Plan. The Plan Administrator shall have such additional powers as may be necessary to discharge its duties and responsibilities hereunder. It is intended that the Plan and any Participation Agreement shall comply with Code Section 409A, including, but not limited to, any future amendments to Section 409A of the Code, the Final Treasury Regulations under Code Section 409A, and any other Internal Revenue Service or other governmental rulings or interpretations issued under Code Section 409A, so as not to subject any Participant or Beneficiary to payment of interest or any additional tax under Code Section 409A. In the exercise of its discretionary power and authority, the Plan Administrator shall interpret the terms of the Plan and any Participation Agreement accordingly.

Section 8.3.Calculation of Funding Obligations: The Employer shall calculate its funding obligations hereunder solely by using the actuarial assumptions and methodology set forth in Exhibit B hereto. In its discretion, at any time prior to a Change in Control of the Employer, the Employer may amend Exhibit B to change such actuarial assumptions and methodology, provided that such changes are communicated promptly in writing to all Participants, Retired Participants, and Beneficiaries. Upon and after a Change in Control of the Employer, the actuarial assumptions and methodology set forth in Exhibit B may be changed with respect to any Participant, Retired Participant, or Beneficiary who was a Participant, Retired Participant, or

Beneficiary at the time of such Change in Control, only with the written consent of such affected Participant, Retired Participant, or Beneficiary.

Section 8.4.Annual Statements: As soon as practicable after the end of each Plan Year, the Employer shall deliver to each Participant, Retired Participant, and Beneficiary a statement containing (a) the present value of the Employer’s future benefit obligations to the Participant, Retired Participant, or Beneficiary; (b) the actuarial assumptions used to calculate the present value of the Employer’s future benefit obligations hereunder; and (c) the aggregate current value of the assets, if any, held in a trust or other funding arrangement which are sufficient to fund 100% of the then-present value of the accrued Supplemental Pension for any Participant, Retired Participant, or Beneficiary for whom benefits are paid in the form of an annuity and for whom assets are required to be held in trust.

ARTICLE IX

Miscellaneous Provisions

Section 9.1.Amendment or Termination of the Plan:

(a)In General: Subject to the remaining provisions of this Section 9.1, the Board of Directors may by resolution, in its absolute discretion, from time to time, amend, suspend, or terminate any or all of the provisions of the Plan; provided, however, that no amendment, suspension, or termination may apply so as to decrease the payment to any Participant or Beneficiary of any benefit under the Plan that he accrued prior to the effective date of such amendment, suspension, or termination, nor shall such amendment, suspension, or termination change the time and form of payment to be made under the provisions of the Plan as in effect before such amendment, suspension, or termination, except as otherwise permitted or required under Code Section 409A and the Treasury regulations issued thereunder.

(b)Amendment That Decreases Benefits: If the Board of Directors amends the Plan and such amendment results in a decrease in the Supplemental Pension, Death Benefits or Disability Benefit that otherwise would be paid under the Plan but for the amendment, except as provided in subparagraphs (iii) and (iv) below, the Participant’s Supplemental Pension, Death Benefits or Disability Benefit shall equal the sum of (i) and (ii) as follows:

(i)The amount derived by multiplying the Participant’s benefit calculated pursuant to the terms of the Plan in effect immediately prior to the amendment and based upon the Participant’s Compensation used to calculate the appropriate benefit by the following fraction: The numerator is the number of full years of Covered Employment the Participant has prior to the effective date of the amendment, and the denominator is the total number of full years of Covered Employment the Participant has; however, neither the numerator nor the denominator shall exceed 10.

(ii)The amount derived by multiplying the Participant’s benefit as calculated pursuant to the terms of the Plan as amended based upon the Participant’s Compensation used to calculate the appropriate benefit by the following fraction: The numerator is the number of full years that the Participant participated (A) in the case of a Pension Plan Participant, in the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him in the RSP, after the effective date of the amendment (but this number when added to the numerator of the fraction in subparagraph (i) above, shall not exceed 10) and the denominator is the total number of full years of Covered Employment the Participant has (but this number shall not exceed 10).

(iii)Notwithstanding the foregoing provisions of this subparagraph (b), if the Plan is so amended before a Participant is vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, the Participant’s Supplemental Pension, Death Benefit or Disability Benefit shall be calculated solely in accordance with the terms of the Plan as amended.

(iv)Notwithstanding the foregoing provisions of this subparagraph (b), if any such amendment occurs upon or after a Change in Control, the Participant’s Supplemental Pension shall at least equal the benefits which would be paid under subparagraph (c) below if there was a termination of the Plan at the time of such amendment.

Notwithstanding the foregoing provisions of this subparagraph (b), the Amendment and Restatement of the Plan effective August 7, 2007, November 12, 2009, June 4, 2012, or January 1, 2016, as applicable, shall not for any purposes be treated as resulting in a decrease in the Supplemental Pension, Death Benefit or Disability Benefit otherwise payable under the Plan.

(c)Termination of the Plan.

(i)If the Board of Directors terminates all or any portion of the Plan and such termination adversely affects a Participant’s Supplemental Pension, such Participant shall be entitled to receive a Supplemental Pension regardless of whether such Participant has at least three (3) years of Covered Employment, and regardless of whether such Participant is vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, at the time of such Plan termination.

(A)It shall be based upon the Participant’s Compensation as of the date of the termination of the Plan;

(B)If payment of the Supplemental Pension begins before the Participant has ten full years of Covered Employment, the reduction referred to in Section 5.2(a)(i)(A) shall not apply;

(C)If payment of the Supplemental Pension begins before the Participant attains age 62, the reductions referred to in Section 5.2(b) shall not apply; and

(D)If the Participant is not otherwise vested (1) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan, and (2) in the case of an FACC Participant, in the FACC allocated to him under the RSP, the calculation made under Section 5.2(a)(i)(B) or Section 5.2(a)(ii)(B) above shall be made as if he were so vested.

Except as otherwise provided in Section 5.4(c), the Supplemental Pension determined under this subparagraph (c) shall be paid (i) in the case of an Eligible Employee who was a Participant prior to November 12, 2009, at the later of (A) the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer, or (B) the first day of the month following the month in which such Participant attains age 55, or (ii) the case of an Eligible Employee who has become a Participant on or after November 12, 2009, on the first day of the month following the month in which such Participant incurs a Separation from Service with the Employer. In the case of an Eligible Employee who becomes a Participant on or after November 12, 2009, if such Participant’s Supplemental Pension commences without regard to Section 5.4(c) before the Participant attains age 55, the amount determined under this subparagraph (c) shall be actuarially reduced, in accordance with the actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum as set forth in Exhibit A, for each full month that the date of commencement precedes age 55.

(ii)If the Board of Directors terminates all or any portion of the Plan and such termination adversely affects the Disability Benefits or Death Benefits described in the Plan, a Participant shall continue to be entitled to the Disability Benefits or Death Benefits described in the Plan if he thereafter dies or suffers a Disability. Any such Death Benefit or Disability Benefit, however, shall be calculated as of the date of termination of such benefit or the Plan as if such date of termination was the date the Participant died or suffered a Disability. Payment of any such Death Benefit or Disability Benefit shall be made in accordance with the terms of the Plan as in effect immediately prior to the date of termination of such benefit or the Plan.

(d)Amendments to Comply with Internal Revenue Code Section 409A: Notwithstanding any of the foregoing provisions of this Section 9.1 or any of the terms and conditions of the Participation Agreement to the contrary, the Board of Directors reserves the right, in its sole discretion, to amend the Plan and/or any Participation Agreement in any manner it deems necessary or desirable in order to comply with or otherwise address issues resulting from Code Section 409A.

Section 9.2.Nonguarantee of Employment: Nothing contained in the Plan shall be construed as a contract of employment between the Employer and any employee, as a right of any employee to be continued in the employment of the Employer, or as a limitation of the right of the Employer to discharge any of its employees, with or without Cause.

Section 9.3.Nonalienation of Benefits: To the extent permitted by law, benefits payable under the Plan shall not, without the Plan Administrator’s consent, be subject in any manner to anticipation, alienation, sale,

transfer, assignment, pledge, encumbrance, charge, garnishment, execution, or levy of any kind, either voluntary or involuntary. Any unauthorized attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber, charge, or otherwise dispose of any right to benefits payable hereunder shall be void. No part of the assets of the Employer shall be subject to seizure by legal process resulting from any attempt by creditors of or claimants against any Participant or Beneficiary or any person claiming under or through the foregoing to attach his interest under the Plan.

Section 9.4.Liability: No director, officer, or employee of the Employer shall be liable for any act or action, whether of commission or omission, taken by any other director, officer, employee, or agent of the Employer under the terms of the Plan or, except in circumstances involving his bad faith, for anything done or omitted to be done by him under the terms of the Plan.

Section 9.5.Participation Agreement: Each Participant has entered into a Participation Agreement as a condition to his participation in the Plan. Such Participation Agreement shall constitute a separate and enforceable agreement between the Employer and the Participant regarding the Participant’s rights in the Plan.

Section 9.6.Successors to the Employer: Any successor to the Employer hereunder, which successor continues or acquires any of the business of the Employer, shall be bound by the terms of the Plan in the same manner and to the same extent as the Employer.

Section 9.7.Tax Withholding: The Employer shall have the right to deduct from all amounts paid in cash or other form under this Agreement any Federal, state, local or other taxes required by law to be withheld.

IN WITNESS WHEREOF, and as conclusive evidence of its adoption of this amendment and restatement of the Supplemental Executive Retirement Plan, the Employer has caused the Plan to be duly executed on this 16^th day of September, 2016, to be effective as of the date set forth in Section 1.2 above.

ATMOS ENERGY CORPORATION

By: /s/ MICHAEL E. HAEFNER

Michael E. Haefner

President and Chief Operating Officer

EXHIBIT A

ATMOS ENERGY CORPORATION

SUMMARY OF ACTUARIAL ASSUMPTIONS

FOR DETERMINING

LUMP SUM DISTRIBUTIONS

AND

OPTIONAL ANNUITY FORMS

Actuarial assumptions for determining lump sums:

(i) Interest:The applicable segment rates as defined in Code Section 417(e)(3)(D) for the November (from and after January 1, 2010, the September) preceding the first day of the calendar year in which the participant retires or otherwise becomes entitled to payments under the Supplemental Executive Retirement Plan without regard to Section 5.4(c) of the Plan and without regard to the phase-in percentages specified in Code Section 417(e)(3)(D)(iii).

(ii) Mortality:The applicable mortality table as defined in Code Section 417(e)(3), and amended by the Pension Protection Act.

Actuarial assumptions for conversion of a life annuity to an optional form of payment other than a lump sum:

(i) Interest:6.0% per year.

(ii) Mortality:1983 Unisex Group Annuity Mortality (50% 1983 Group Annuity Mortality for males, 50% 1983 Group Annuity Mortality for females).

EXHIBIT B

ATMOS ENERGY CORPORATION

SUMMARY OF ACTUARIAL ASSUMPTIONS AND METHODS

FOR

DETERMINING SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN TRUST

ANNUAL FUNDING LIABILITIES

Actuarial Assumptions

Discount Rate8%

Mortality

Prior to Age 62None

After Age 62Code Section 417(e)(3)

Applicable Mortality Table*

Salary Scale0%

Benefit Percentage60%

*The table prescribed in Rev. Rul. 2001-62, or such other mortality table which in the future may be specified from time to time as the applicable mortality table for purposes of Code Section 417(e)(3).

Method for Determining Liabilities

The liability determined is the present value as of the valuation date of the projected age 62 Supplemental Executive Retirement Plan benefit. The projected age 62 benefit is based on Supplemental Executive Retirement Plan compensation determined as the sum of (1) and (2) as follows:

(1) The greater of (A) Participant’s annual base salary at the date of his termination of employment, or (B) the average of the Participant’s annual base salary for the highest three (3) calendar years (whether or not consecutive) of the Participant’s employment with the Employer.

(2) The greater of (A) the Participant’s last Performance Award or (B) the average of the highest three (3) Performance Awards (whether or not consecutive).

The qualified plan offset is the projected age 62 qualified plan benefit with no salary scale or wage base projections.

EX-10.8

Exhibit 10.8

ATMOS ENERGY CORPORATION

ACCOUNT BALANCE

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

AS AMENDED AND RESTATED

EFFECTIVE AS OF JANUARY 1, 2016

TABLE OF CONTENTS

ARTICLE I Purpose and Effective Date

Section 1.1. Purpose

Section 1.2. Effective Date

ARTICLE II Definitions and Construction

Section 2.1. Definitions

Section 2.2. Construction

Section 2.3. Governing Law

ARTICLE III Eligibility and Participation

Section 3.1. Employees Eligible to Participate

ARTICLE IV Assets Used for Benefits

Section 4.1. Amounts Provided by the Employer

Section 4.2. Funding

ARTICLE V Supplemental Benefits

Section 5.1. Eligibility for Supplemental Benefit

Section 5.2. Amount of Supplemental Benefit

Section 5.3. Form of Payment of Supplemental Benefit

Section 5.4. Time of Payment of Supplemental Benefit

ARTICLE VI Administration

Section 6.1. Plan Administration

Section 6.2. Powers of Plan Administrator

Section 6.3. Annual Statements

ARTICLE VII Miscellaneous Provisions

Section 7.1. Amendment or Termination of the Plan

Section 7.2. Nonguarantee of Employment or Participation

Section 7.3. Nonalienation of Benefits

Section 7.4. Liability

Section 7.5. Participation Agreement

Section 7.6. Successors to the Employer

Section 7.7. Tax Withholding

Section 7.8. Code Section 409A

Exhibit AParticipation Agreement

ARTICLE I

Purpose and Effective Date

Section 1.1.Purpose: The purpose of the Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan (the “Plan”) is to provide a supplemental retirement income benefit to certain executive employees of Atmos Energy Corporation. The Plan is intended to be unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees so as to be exempt from the requirements of Parts 2, 3 and 4 of Title I of ERISA, and shall be so interpreted.

Section 1.2.Effective Date: The Plan was originally adopted effective as of August 5, 2009. The Plan is being amended and restated, effective as of January 1, 2016. The Plan as amended and restated shall apply generally to any participant in the Prior Plan (as defined below) who did not terminate employment prior to January 1, 2016, as well as any Eligible Employee who becomes a participant in the Plan on or after January 1, 2016. Except as otherwise provided herein, any Eligible Employee who was a participant in the Prior Plan and who terminated employment prior to January 1, 2016, shall be entitled to those benefits, if any, provided by the Prior Plan.

ARTICLE II

Definitions and Construction

Section 2.1.Definitions: The following words and phrases used in the Plan shall have the respective meanings set forth below, unless the context in which they are used clearly indicates a contrary meaning:

(a)Account: The notional account described in, and maintained for each Participant pursuant to Section 5.2(a) of the Plan.

(b)Account Balance: The notional amount in a Participant’s Account pursuant to Section 5.2(d) of the Plan.

(c)Annual Pay Credit: The notional amounts credited to a Participant’s Account pursuant to Section 5.2(b) of the Plan.

(d)Beneficiary: The Participant’s designated Beneficiary. In the event that no Beneficiary has been effectively designated, the Participant’s surviving spouse shall be deemed the designated

Beneficiary, or if the Participant has no surviving spouse, his children, if any, per stirpes, shall be deemed the designated Beneficiary, and if none, the estate of the Participant shall be deemed the designated Beneficiary.

(e)Board of Directors: The Board of Directors of the Employer.

(f)Cause: The termination of employment by the Employer upon the happening of either (i) or (ii) as follows:

(i)The willful and continued failure by the Participant to substantially perform his duties with the Employer (other than any such failure resulting from the Participant’s incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Participant by the Employer that specifically identifies the manner in which the Employer believes that the Participant has not substantially performed his duties.

(ii)The Participant’s willful engagement in conduct that is demonstrably and materially injurious to the Employer, monetarily or otherwise.

For purposes of this paragraph, no act, or failure to act, on the Participant’s part shall be deemed “willful” if done, or omitted to be done, by the Participant in good faith and with a reasonable belief that the action or omission was in the best interests of the Employer. Notwithstanding the foregoing, the Participant shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to the Participant a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters (3/4) of the entire membership of the Board of Directors of the Employer at a meeting of such Board of Directors called and held for such purpose (after reasonable notice to the Participant and an opportunity for the Participant, together with the Participant’s counsel, to be heard before the Board of Directors), finding that in the good faith opinion of the Board of Directors that the Participant was guilty of conduct set forth above in subparagraph (i) or (ii) and specifying the particulars thereof in detail.

(g)Change in Control:

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

(A)Change in Ownership. A change in ownership of the Employer occurs on the date that any “Person” (as defined in subparagraph (ii) below), other than (1) the Employer or any of its subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Employer or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the shareholders of the Employer in substantially the same proportions as their ownership of the Employer’s stock, acquires ownership of the Employer’s stock that, together with stock held by such Person, constitutes more than 50% of the total fair market value or total voting power of the Employer’s stock. However, if any Person is considered to own already more than 50% of the total fair market value or total voting power of the Employer’s stock, the acquisition of additional stock by the same Person is not considered to be a

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

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

(1)the date that any Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Employer’s stock possessing 30 percent or more of the total voting power of the Employer’s stock. However, if any Person owns 30% or more of the total voting power of the Employer’s stock, the acquisition of additional control of the Employer by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (i)(B)(1); or

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

(C)Change in Ownership of Substantial Portion of Assets. A change in the ownership of a substantial portion of the Employer’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Employer, that have a total gross fair market value equal to at least 40% of the total gross fair market value of all of the Employer’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the shareholders of the Employer immediately after the transfer, through a transfer to (1) a shareholder of the Employer (immediately before the asset transfer) in exchange for or with respect to the Employer’s stock; (2) an entity, at least 50% of the total value or voting power of the stock of which is owned, directly or indirectly, by the Employer; (3) a Person that owns directly or indirectly, at least 50% of the total value or voting power of the Employer’s outstanding stock; or (4) an entity, at least 50% of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least 50% of the total value or voting power of the Employer’s outstanding stock.

(ii)For purposes of subparagraph (i) above and, in the case of subparagraph (ii)(B) below, Exhibit A,

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

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

(iii)The provisions of this Section 2.1(g) shall be interpreted in accordance with the requirements of the Final Treasury Regulations under Code Section 409A, it being the intent of the parties that this Section 2.1(g) shall be in compliance with the requirements of said Code Section and said Regulations.

(h)Code: The Internal Revenue Code of 1986, as amended, or any successor thereto.

(i)Compensation: The total of all amounts paid to a Participant by an Employer for personal services as reported on the Participant's Federal Income Tax Withholding Statement (Form W-2) plus any amounts excluded from such reporting pursuant to Code Sections 125, 401(k) and 132(f)(4), but excluding (A) expense reimbursements, (B) any contributions made under any plan of deferred compensation or any welfare benefit plan (other than amounts contributed pursuant to such Sections 125 and 401(k)), (C) other special payments of any kind that are unrelated to the Participant's activities associated with or in lieu of his performance of services for the Employer, and (D) any bonus payments or awards which are not Performance Awards.

(j)Covered Employment: The total period of employment with the Employer, beginning on the date specified in the Participation Agreement, while a Participant in the Plan.

(k)Disability: A disability (i) as determined under The Atmos Energy Corporation Group Long-Term Disability Plan, as in effect from time to time, or (ii) a determination of total disability for purposes of eligibility for Social Security disability benefits, if such Group Long-Term Disability Plan is not then in existence. If a Participant’s Disability is based on his eligibility for Social Security disability benefits, such Participant shall not be treated as having suffered a Disability unless he shall provide the Plan Administrator, or a committee which may be established pursuant to Section 6.1, with written proof, in a form and within the time determined by the Plan Administrator, or a committee which may be established pursuant to Section 6.1, to be satisfactory, that such Participant is receiving Social Security disability benefits.

(l)Disability Termination: A Separation from Service due to a Disability.

(m)Eligible Employee: An employee of the Employer who is either a (i) corporate officer of the Employer selected by the Board of Directors, in its discretion, to participate in the Plan, or (ii) the president of an operating division of the Employer or any other employee of the Employer selected by the Board of Directors in its discretion to participate in the Plan.

(n)Employer: Atmos Energy Corporation.

(o)ERISA: The Employee Retirement Income Security Act of 1974, as amended.

(p)Interest Credit(s): The interest amounts credited to a Participant’s Account pursuant to Section 5.2(c) of the Plan.

(q)Involuntary Employment Termination: The termination of a Participant’s participation in the Plan due to the involuntary termination of the Participant’s employment by the Employer, provided said termination constitutes a Separation from Service and such termination is for any reason other than Cause.

(r)Involuntary Participation Termination: The termination of a Participant’s participation in the Plan by the Employer for any reason other than Cause prior to the Participant’s Separation from Service with the Employer as provided for in Section 5.1 of the Plan.

(s)Participant: An Eligible Employee of the Employer who meets the requirements to participate in the Plan in accordance with the provisions of Article III hereof.

(t)Participation Agreement: The agreement between the Employer and a Participant described in Section 7.5 of the Plan, executed in the form attached hereto as Exhibit A, or in such other form as the Board of Directors, in its sole discretion, may establish from time to time.

(u)Performance Award: Any amount paid, or authorized to be paid, to a Participant while a Participant in the Plan pursuant to any annual performance bonus or incentive compensation plan adopted or established by the Employer, or, upon and after a Change in Control, any amount paid, or authorized to be paid, to a Participant as a performance related cash bonus in addition to his base cash compensation. Notwithstanding the foregoing, Performance Awards shall not include any Employer stock award granted under the 1998 Long-Term Incentive Plan or other incentive plan, other than a stock award which is elected by a participant under an incentive plan to be received in lieu of cash.

(v)Plan: The Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan, as set forth herein and as amended from time to time.

(w)Plan Administrator: The Board of Directors.

(x)Plan Year: Each twelve (12) month period beginning on January 1 and ending on December 31.

(y)Retirement or Retire: Participant’s voluntary termination from employment with the Employer that constitutes a Separation from Service after he has completed at least three (3) years of Covered Employment and has attained age 55.

(z)Separation from Service: A Participant’s termination from employment with the Employer that constitutes a “separation from service” as defined in Section 1.409A-1(h) of the Final Treasury Regulations under Code Section 409A, or any successor provision thereto.

(aa)Supplemental Benefit: A Participant’s benefit provided under the Plan in accordance with Section 5.2.

(bb)The expressions listed below shall have the meanings stated in the Sections or subparagraphs hereof respectively indicated:

“Affiliate”Subparagraph 2.1(g)(ii)(B)

“Original Payment Date”Section 5.4(c)

“Person”Subparagraph 2.1(g)(ii)(A)

“Specified Employee”Section 5.4(c)

Section 2.2.Construction: The masculine gender, whenever appearing in the Plan, shall be deemed to include the feminine gender; the singular may include the plural; and vice versa, unless the context clearly indicates to the contrary.

Section 2.3.Governing Law: The Plan shall be construed in accordance with and governed by the laws of the State of Texas, except to the extent otherwise preempted by ERISA or any other Federal law.

ARTICLE III

Eligibility and Participation

Section 3.1.Employees Eligible to Participate: Each Eligible Employee who becomes a Participant shall participate in the Plan, provided he complies with the provisions of Section 7.5 hereof. Any Participant who ceases being an Eligible Employee during his employment with the Employer shall immediately cease active participation in the Plan and shall no longer be a Participant, except as otherwise set forth herein.

ARTICLE IV

Assets Used for Benefits

Section 4.1.Amounts Provided by the Employer: Benefits payable under the Plan shall constitute general obligations of the Employer in accordance with the terms of the Plan.

Section 4.2.Funding: Immediately upon a Change in Control, the Employer shall contribute to a trust or other funding arrangement that is subject to the claims of the Employer’s general unsecured creditors an amount necessary to fund 100% of the then‑value of the Account Balance for each Participant, regardless of whether any such Participant is then eligible to Retire or to receive a Supplemental Benefit. The Employer shall review the funding status of such trust or other funding arrangement required to be established under

this Section 4.2 on an annual basis and shall make such contributions thereto as may be required to maintain the value of the assets thereof at no less than 100% of the then-value of all such Account Balances.

ARTICLE V

Supplemental Benefits

Section 5.1.Eligibility for Supplemental Benefit:

(a)Upon Retirement: An Eligible Employee who becomes a Participant and who Retires shall be entitled to receive a Supplemental Benefit.

(b)Upon Involuntary Employment Termination, Disability Termination or Death: A Participant who suffers an Involuntary Employment Termination, a Disability Termination or dies shall be entitled to receive a Supplemental Benefit.

(c)Upon Involuntary Participation Termination with Three (3) or More Years of Covered Employment: An Eligible Employee who suffers an Involuntary Participation Termination after such Participant has at least three (3) years of Covered Employment and who remains an Employee after such Involuntary Participation Termination shall be entitled to receive a Supplemental Benefit equal to his or her Account Balance as of the date such Involuntary Participation Termination, as increased by any Annual Pay Credits pursuant to Section 5.2(b) of the Plan and any Interest Credits pursuant to Section 5.2(c) of the Plan.

(d)Upon Voluntary Termination, Termination For Cause or Involuntary Participation Termination with Less Than Three (3) Years of Covered Employment: A Participant who (i) voluntarily resigns from employment with the Employer prior to being eligible for Retirement, (ii) is terminated from employment with the Employer for Cause or from participation in the Plan for Cause or (iii) suffers an Involuntary Participation Termination before such Participant has at least three (3) years of Covered Employment shall not be entitled to receive a Supplemental Benefit.

Section 5.2.Amount of Supplemental Benefit: A Participant’s Supplemental Benefit shall be equal to his Account Balance determined as follows:

(a)Establishment of Account: An Account shall be established and maintained for each Participant. A Participant’s Account shall be credited with Annual Pay Credits in accordance with Section 5.2(b) of the Plan and Interest Credits in accordance with Section 5.2(c) of the Plan.

(b)Annual Pay Credits: As of the last day of each Plan Year, an Annual Pay Credit shall be credited to the Account of each Participant who received Compensation during such Plan Year, provided, such Participant (i) has not voluntarily resigned from employment with the Employer prior to being eligible for Retirement, (ii) has not been terminated from employment with the Employer for Cause or from participation in the Plan for Cause prior to the end of such Plan Year or (iii) has not suffered an Involuntary Participation Termination prior to the end of such Plan Year. The Annual Pay Credit shall be equal to (i) and/or (ii) below, as applicable:

(i)Except as provided in subparagraph (ii) below, the Annual Pay Credit for a Participant shall be ten percent (10%) of the Participant’s Compensation for such Plan Year. In the case of a Participant who suffered an Involuntary Participation Termination after such

Participant has at least three (3) years of Covered Employment and who remains an Employee after such Involuntary Participation Termination, such Participant shall have credited to his or her Account for the year of such Involuntary Participation Termination, an Annual Pay Credit equal to ten percent (10%) of such Participant’s Compensation for the portion of the Plan Year prior to such Involuntary Participation Termination and shall thereafter receive no Annual Pay Credits.

(ii)Notwithstanding subparagraph (i) above, the Annual Pay Credit for a Participant who becomes a member of the Management Committee on or after January 1, 2016, for each Plan Year during which such Participant is a member of the Management Committee, shall be equal to such percentage of the Participant’s Compensation for such Plan Year as determined by the Board of Directors prior to the beginning of such Plan Year. In the case of a Participant for whom this subparagraph (ii) applies who suffered an Involuntary Participation Termination while a member of the Management Committee and after such Participant has at least three (3) years of Covered Employment and who remains an Employee after such Involuntary Participation Termination, such Participant shall have credited to his or her Account for the year of such Involuntary Participation Termination, an Annual Pay Credit equal to the percentage of such Participant’s Compensation in effect for such Plan Year for the portion of the Plan Year prior to such Involuntary Participation Termination and shall thereafter receive no Annual Pay Credits.

(c)Interest Credits:

(i)Timing of Interest Credits: Interest Credits based on the Participant’s Account Balance as of the first day of each Plan Year shall be added to each Participant’s Account as of the last day of the Plan Year, prior to the crediting of any Annual Pay Credit for such Plan Year. Interest Credits shall be added to a Participant’s Account for each Plan Year in which such Participant’s Account has an Account Balance. However, for any Plan Year in which a Plan distribution is made to a Participant, interest shall be credited on the Participant’s Account Balance as of the first day of the Plan Year for the period from the first day of such Plan Year to the date of such Participant’s Separation from Service.

(ii)Rate of Interest Credits: The rate of interest used to determine the Interest Credit shall be the same rate utilized for “interest credits” under the Employer’s Pension Account Plan; currently that rate is the 30-year Treasury securities rate in effect for the November preceding the first day of the Plan Year (as published by the Commissioner of Internal Revenue)subject to a minimum interest rate of 4.69% and a maximum interest rate of 7% for any 12-month Plan Year.

(d)Account Balance: A Participant’s Account Balance shall be equal to the sum of the Annual Pay Credits and the Interest Credits.

Section 5.3.Form of Payment of Supplemental Benefit: Each Participant shall be paid his Supplemental Benefit in a lump sum payment equal to his Account Balance at the time of payment.

Section 5.4.Time of Payment of Supplemental Benefit:

(a)Upon Retirement: Except as otherwise provided in Section 5.4(c) below, the Supplemental Benefit of a Participant who Retires at any time shall be paid as soon as administratively possible, but in no event later than ninety (90) days following such Participant’s date of Retirement.

(b)Upon Involuntary Employment Termination, Involuntary Participation Termination, Disability Termination or Death: The Supplemental Benefit of a Participant who suffers an Involuntary Employment Termination, an Involuntary Participation Termination pursuant to Section 5.1(c) of the Plan, or a Disability Termination shall, except as otherwise provided in Section 5.4(c) of the Plan, be paid as soon as administratively possible following such Participant’s Separation from Service, but in no event later than ninety (90) days following the date on which such Participant incurs a Separation from Service with the Employer. The Supplemental Benefit of a Participant who dies shall be paid to such Participant’s Beneficiary as soon as administratively possible, but in no event later than ninety (90) days following the date on which such Participant dies.

(c)Six Months Delay in Payment: Notwithstanding the foregoing provisions of this Section 5.4 and Section 7.1(b), if a Participant who is entitled to payments under said applicable Section is a “specified employee,” as defined in § 1.409A-1(i) of the Final Regulations under Code Section 409A, and the Supplemental Benefit would otherwise be paid to the Participant (the “Original Payment Date”) before a date which is at least six (6) months following the date of the Participant’s Separation from Service, the Supplemental Benefit shall be paid onthe date which is six (6) months following the date of the Participant’s Separation from Service (or, if earlier, the date of death of the Participant, in which case payment shall be made to such Participant’s Beneficiary as soon as administratively possible, but in no event date later than ninety (90) days following the date on which such Participant dies), provided the six (6) months delay requirements of Code Section 409A otherwise apply to the payments under said applicable Section. The lump sum payments which are delayed as provided in this Section 5.4(c) shall accrue interest for the period from the Original Payment Date until the date such payment is actually made. Said interest shall be based upon the rate of interest used to determine the Interest Credits pursuant to Section 5.2 (c)(ii) as in effect for the Plan Year in which occurs the date of such Participant’s Separation from Service.

ARTICLE VI

Administration

Section 6.1.Plan Administration: The Plan shall be administered by the Board of Directors. The Board of Directors may, in its sole discretion, establish a committee to carry out the day-to-day administration of the Plan and may delegate any portion of its authority and responsibilities as Plan Administrator to such committee.

Section 6.2.Powers of Plan Administrator: The Plan Administrator shall have the discretionary power and authority to interpret and administer the Plan according to its terms, including the power to construe and interpret the Plan, to supply any omissions therein, to reconcile and correct any errors or inconsistencies,

to decide any questions in the administration and application of the Plan, and to make equitable adjustments for any mistakes or errors in the administration and application of the Plan. The Plan Administrator shall have such additional powers as may be necessary to discharge its duties and responsibilities hereunder.

Section 6.3.Annual Statements: As soon as practicable after the end of each Plan Year, the Employer shall deliver to each Participant a statement containing the Participant’s Account Balance as of the end of such Plan Year, and the aggregate current value of the assets, if any, held in a trust or other funding arrangement for any Participant for whom assets are required to be held in trust.

ARTICLE VII

Miscellaneous Provisions

Section 7.1.Amendment or Termination of the Plan:

(a)In General: Subject to the remaining provisions of this Section 7.1, the Board of Directors may by resolution, in its absolute discretion, from time to time, amend, suspend, or terminate any or all of the provisions of the Plan; provided, however, that no amendment, suspension, or termination may apply so as to decrease the payment to any Participant or Beneficiary of any benefit under the Plan that he accrued prior to the effective date of such amendment, suspension, or termination, nor shall such amendment, suspension, or termination change the time and form of payment to be made under the provisions of the Plan as in effect before such amendment, suspension, or termination, except as otherwise permitted or required under Code Section 409A and the Treasury regulations issued thereunder.

(b)Termination of the Plan: If the Board of Directors terminates all or any portion of the Plan and such termination adversely affects a Participant’s Supplemental Benefit, such Participant shall be entitled to receive a Supplemental Benefit, whether or not such Participant has at least three (3) years of Covered Employment, whether or not such Participant’s Separation from Service is involuntary (other than a Separation from Service for Cause) or voluntary and, if voluntary, whether or not such Participant has attained age 55. The Supplemental Benefit payable to a Participant upon termination of the Plan shall be a lump sum payment equal to the Account Balance determined at the time of payment as provided in this Section 7.1(b). Except as otherwise provided in Section 5.4(c), the Supplemental Benefit determined under this Section 7.1(b) shall be paid as soon as administratively possible following a Participant’s Separation from Service, but in no event later than ninety (90) days following the date on which such Participant incurs a Separation from Service.

(c)Amendments to Comply with Internal Revenue Code Section 409A: Notwithstanding any of the foregoing provisions of this Section 7.1 or any of the terms and conditions of the Participation Agreement to the contrary, the Board of Directors reserves the right, in its sole discretion, to amend the Plan and/or any Participation Agreement in any manner it deems necessary or desirable in order to comply with or otherwise address issues resulting from Code Section 409A.

Section 7.2.Nonguarantee of Employment or Participation: Nothing contained in the Plan shall be construed as a contract of employment between the Employer and any employee, as a right of any employee to be continued either in the employment of the Employer or as a Participant in the Plan, or as a limitation of the right of the Employer either to discharge any of its employees, with or without Cause, or to terminate any Participant’s participation in the Plan.

Section 7.3.Nonalienation of Benefits: To the extent permitted by law, benefits payable under the Plan shall not, without the Plan Administrator’s consent, be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, charge, garnishment, execution, or levy of any kind, either voluntary or involuntary. Any unauthorized attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber, charge, or otherwise dispose of any right to benefits payable hereunder shall be void. No part of the assets of the Employer shall be subject to seizure by legal process resulting from any attempt by creditors of or claimants against any Participant or Beneficiary or any person claiming under or through the foregoing to attach his interest under the Plan.

Section 7.4.Liability: No director, officer, or employee of the Employer shall be liable for any act or action, whether of commission or omission, taken by any other director, officer, employee, or agent of the Employer under the terms of the Plan or, except in circumstances involving his bad faith, for anything done or omitted to be done by him under the terms of the Plan.

Section 7.5.Participation Agreement: Each Participant shall enter into a Participation Agreement as a condition to his participation in the Plan. In the event of a conflict between the Plan and the Participation Agreement, the Plan shall control.

Section 7.6.Successors to the Employer: Any successor to the Employer hereunder, which successor continues or acquires any of the business of the Employer, shall be bound by the terms of the Plan in the same manner and to the same extent as the Employer.

Section 7.7.Tax Withholding: The Employer shall have the right to deduct from all amounts paid in cash or other form under the Plan any Federal, state, local or other taxes required by law to be withheld.

Section 7.8.Code Section 409A: The Plan shall be interpreted in accordance with the requirements of the Final Treasury Regulations under Section 409A of Code, it being the intent of the parties that the Plan shall be in compliance with the requirements of said Code Section and said Regulations.

IN WITNESS WHEREOF, and as conclusive evidence of its adoption of this Account Balance Supplemental Executive Retirement Plan, the Employer has caused the Amended and Restated Plan to be duly executed on this 5^th day of November, 2015, to be effective as of the date set forth in Section 1.2 above.

ATMOS ENERGY CORPORATION

By: /s/ MICHAEL E. HAEFNER

Michael E. Haefner

President and Chief Operating Officer

EXHIBIT A

PARTICIPATION AGREEMENT

THIS PARTICIPATION AGREEMENT (“Agreement”) is entered into as of the ____day of _________, 20___ by and between ATMOS ENERGY CORPORATION, a Texas and Virginia corporation (the “Employer”), and __________________________(“Participant”).

W I T N E S S E T H:

WHEREAS, the Employer has adopted the Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan (the “Plan”), pursuant to which certain executive or management employees of the Employer may receive supplemental benefits; and

WHEREAS, in accordance with Section 7.5 of the Plan, the Employer and Participant have agreed to execute and enter into this Agreement;

NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.Agreement. The Employer hereby agrees to provide to Participant the benefits described in the Plan, pursuant to the terms and conditions set forth in the Plan, a copy of which has been provided to Participant and is incorporated by reference into this Agreement. Participant acknowledges he or she has received a copy of the Plan. In the event of a conflict between the Plan and the Participation Agreement, the Plan shall control.

2.Calculation of Supplemental Benefit. For purposes of all applicable provisions of the Plan, Covered Employment for the Participant commenced ___________.

3.Delay in Payment of Supplemental Benefit For Certain Participants. If a Participant’s Supplemental Benefit is payable on or before a date which is at least six (6) months following the date of Participant’s Separation from Service, the Supplemental Benefit shall be paid to such Participant as provided for in the Plan onthe date which is six (6) months following the date of Participant’s Separation from Service,provided such six (6) month delay is required by Code Section 409A.

4.Confidential Information.

(a)Participant shall not disclose or use at any time, either during employment or thereafter, any Confidential Information (as defined below) of which Participant is or becomes aware, whether or not such information is developed by him, except to the extent that such disclosure or use is directly related to and required by Participant’s performance in good faith of duties assigned to Participant by the Employer. Participant will take all appropriate steps to safeguard Confidential Information and to protect it against disclosure, misuse, espionage, loss and theft. Participant shall deliver to the Employer at the termination of employment or at any time the Employer may request all memoranda, notes, plans, records, reports, computer tapes and software and other documents and data (and copies thereof, including electronic copies) relating to the Confidential Information, work product or the business of the Employer or any of its Affiliates which he may then possess or have under his control.

(b)As used in this Agreement, the term “Confidential Information” means information that is not generally known to the public and that is used, developed or obtained by the Employer in connection with its business, including but not limited to (i) information, observations and data obtained by Participant while employed by the Employer and its predecessors (including information, observations and data obtained prior to the date of this Agreement), concerning the business or affairs of the Employer, (ii) products or services, (iii) fees, costs and pricing structures, (iv) designs, (v) analyses, (vi) drawings, photographs and reports, (vii) computer software, including operating systems, applications and program listings, (viii) flow charts, manuals and documentation, (ix) data bases, (x) accounting and business methods, (xi) inventions, devices, new developments, methods and processes, whether patentable or unpatentable and whether or not reduced to practice, (xii) customers and clients and customer or client lists (including names of contact persons, purchasing patterns or preferences, past purchase and sale history and other information), (xiii) other copyrightable works, (xiv) all production methods, processes, technology and trade secrets, (xv) business strategies, acquisition plans and candidates, financial or other performance data and personnel lists and data, and (xvi) all similar and related information in whatever form. Confidential Information will not include any information that has been published in a form generally available to the public, or has become otherwise generally known by the public (in each case, through no fault of Participant) prior to the date Participant proposes to disclose or use such information. Participant shall not disclose Confidential Information unless it is required to be disclosed by law, regulation or an order of a court or other governmental entity. In the event that an action is initiated pursuant to which Participant may become legally compelled to disclose all or any portion of the Confidential Information, he shall provide the Employer with prompt notice thereof, so that the Employer may seek a protective order or other appropriate remedy. In the event that such protective order or other remedy is not obtained, Participant shall furnish only that portion of the Confidential Information which is legally required and shall exercise his best efforts to obtain reliable assurances that confidential treatment will be afforded such portion of the Confidential Information. Confidential Information will not be deemed to have been published merely because individual portions of the information have been separately published, but only if all material features comprising such information have been published in combination.

5.No Guarantee of Employment or Participation. Nothing contained in this Agreement or the Plan shall be construed as a contract of employment between the Employer and Participant, or as a right of Participant to be continued either in the employment of the Employer or as a Participant in the Plan, or as a limitation of the right of the Employer either to discharge Participant with or without cause or to terminate the Participant’s participation in the Plan.

6.Capitalized Terms. Each capitalized term used in this Agreement that is not otherwise defined herein shall have the same meaning attributed to it in the Plan.

7.Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Texas to the extent not otherwise preempted by ERISA.

8.Code Section 409A: The Plan is intended to comply with Code Section 409A and the Plan shall be interpreted in a manner intended to comply with Code Section 409A.

IN WITNESS WHEREOF, the parties hereto have executed this Participation Agreement as of the date first written above.

PARTICIPANT:ATMOS ENERGY CORPORATION:

By:

EX-10.11(B)

Exhibit 10.11(b)

AWARD AGREEMENT OF TIME-LAPSE

RESTRICTED STOCK UNITS

UNDER THE ATMOS ENERGY CORPORATION

1998 LONG-TERM INCENTIVE PLAN

This Award Agreement of Time-Lapse Restricted Stock Units (“Award Agreement”) is dated as of May 4, 2016, by and between Atmos Energy Corporation, a Texas and Virginia corporation (the "Company"), and you ("Grantee"), pursuant to the Company's 1998 Long-Term Incentive Plan (the "Plan"). Capitalized terms that are used, but not defined, in this Award Agreement shall have the meaning set forth in the Plan.

1.Grant and Description of Units.

Pursuant to authorization by the Human Resources Committee of the Board (the "Committee”), which has been designated by the Board to administer the Plan, the Company hereby grants to the Grantee time-lapse restricted stock units (“Units”) under the Plan, for no consideration from the Grantee, with the restrictions set forth below. Each such Unit shall be a notional share of common stock of the Company (“Common Stock”), with the value of each Unit being equal to the Fair Market Value of a share of Common Stock at any time. No physical certificates representing the number of Units awarded shall be issued to the Grantee, but an account shall be established and maintained for the Grantee, in which each grant of Units to the Grantee shall be recorded. During the time of the restriction period provided for in Section 2 below, the Grantee shall not have any of the rights of a shareholder of the Company with respect to the Units, except with respect to the payment of cash dividend equivalents during such period, as provided for in Section 6 below.

2. Restrictions on Alienation of Units.

Units awarded hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated in any manner, whether voluntarily, by operation of law, or otherwise, until the restrictions on the Units are removed and the Units are delivered to the Grantee in the form of shares of Common Stock in the manner described below in Section 8.

3.Vesting of Units.

If the Grantee has attained the age of 55 and completed three (3) consecutive years of service with the Company (referred to as “Retirement Eligible”) on the date of the grant of the Units, he or she shall be vested in the Units on the later of June 1 of the year in which the grant is made or the date of the grant. If the Grantee becomes Retirement Eligible after the date of grant and prior to the date for distribution of shares of Common Stock represented by the Units, the Grantee shall be vested in the Units at the later of June 1 of the year in which he or she becomes Retirement Eligible or the actual date during such year that he or she becomes

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Retirement Eligible. However, the Grantee shall not be entitled to the removal of the restrictions on such Units provided for in Section 2 above or to a distribution of shares of Common Stock represented by the number of Units until the time provided for in Section 8 below. In addition, the Grantee’s portion of applicable payroll (FICA) taxes shall be withheld from the first scheduled bi-weekly paycheck in December of the year in which such vesting occurs. The amount of payroll taxes due shall be based on the Fair Market Value of the shares of Common Stock represented by the number of Units as of the last business day of the pay period to which the first scheduled payroll check in December applies.

4. Forfeiture of Units.

If the Grantee is not otherwise vested as provided in Section 3 above, all Units granted shall be forfeited if the Grantee has a voluntary or involuntary Termination of Service for any reason other than as described below in Section 5. Each Grantee, by his or her acceptance of the Units, agrees to execute any documents requested by the Company in connection with such forfeiture. Such provisions with respect to forfeited Units shall be specifically performable by the Company in a court of equity or law. Upon any forfeiture, all rights of the Grantee with respect to the forfeited Units shall cease and terminate, without any further obligation on the part of the Company.

5. Removal of Restrictions.

(a) Death, Disability, Certain Involuntary Terminations and Terminations following a Change in Control.

At the time and on the date of the Grantee's death, Termination of Service due to Total and Permanent Disability, involuntary Termination of Service due to a general reduction in force or specific elimination of the Grantee's job, or Termination of Service for any reason following a Change in Control, while employed by the Company or a Subsidiary, all Units shall be vested and all other restrictions placed on the Units shall be removed. The Grantee, or his or her legal representatives, beneficiaries or heirs shall then be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to the number of Units set forth in Section 1 above.

(b) Retirement.

At the time and on the date of the Grantee's Retirement on or after becoming Retirement Eligible, no distribution of Units shall occur and the restrictions provided for in Section 2 above shall remain in place until such time as the Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to the number of Units set forth in Section 1 above.

6. Payment of Cash Dividend Equivalents.

Cash dividend equivalents shall be paid on the Units to the Grantee through the Company payroll system in an amount equal to the cash dividends actually paid each calendar

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quarter on the Company’s issued and outstanding shares of Common Stock. Such cash dividend equivalents shall be paid at the end of the payroll period in which such cash dividends are actually paid to the Company’s shareholders and shall cease as of the Distribution Date (as defined in Section 8 below). However, the payment of cash dividend equivalents shall not be considered to be “eligible compensation,” as such term is defined under either the Company’s Retirement Savings Plan or Pension Account Plan.

7. Adjustment Upon Changes in Stock.

If there shall be any change in the number of shares of Common Stock outstanding resulting from subdivision, combination, or reclassification of shares, or through merger, consolidation, reorganization, recapitalization, stock dividend, stock split or other change in the corporate structure, an appropriate adjustment in the number of Units with respect to which restrictions have not lapsed shall be made by the Committee. Depending upon the change in corporate structure, the Committee shall issue additional Units or substitute Units to the Grantee for his or her account, which shall have the same restrictions, terms and conditions as the original Units. Any such adjustment shall be in accordance with the applicable provisions of Section 14 and/or Section 15 of the Plan.

8. Distribution of Common Stock or Cash.

As soon as administratively possible, as determined solely by the Company, following the earlier of the date of the occurrence of a termination event described in Section 5(a) above or the date which is three (3) years from the date of grant of the Units (such date being referred to as the “Distribution Date”), but in no event later than 90 days following the Distribution Date, the Grantee shall receive a distribution, as provided herein, of shares of Common Stock equal in number to the number of Units set forth in Section 1 above (subject to the withholding requirements set forth in Section 9 below), provided the Grantee has been an employee of the Company or a Subsidiary with continuous service from the date of grant to the Distribution Date, except in the event of the Grantee’s Termination of Service or Retirement as discussed in Section 5 above. Notwithstanding the immediately preceding sentence, in the case of a distribution of shares of Common Stock on account of any Termination of Service as provided for above in Section 5 above, other than death, a distribution of the number of such shares, determined after application of the withholding requirements set forth in Section 9 below, plus any dividends payable with respect to such number of shares, on behalf of the Grantee, if the Grantee is a "specified employee" as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A, to the extent otherwise required under Section 409A, shall not occur until the date which is six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee). Upon a distribution of shares of Common Stock as provided herein, the Company shall cause the Common Stock then being distributed to be registered in the Grantee’s name, but shall not issue certificates for the Common Stock unless the Grantee requests delivery of the certificates for the Common Stock, in writing in accordance with the procedures established by the Company. The Company shall deliver certificates to the Grantee as soon as administratively practicable following the Company’s receipt of a written request from the Grantee for delivery of the certificates. From and after the date of receipt of such

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distribution, the Grantee or the Grantee's legal representatives, beneficiaries or heirs, as the case may be, shall have full rights of transfer or resale with respect to such shares subject to applicable state and federal regulations. Notwithstanding any provisions of this Award Agreement to the contrary, in lieu of a distribution of shares of Common Stock, the Company shall have the option to settle the payment of some or all of the Units in an economically equivalent amount of cash.

9. Withholding Requirements.

Upon the removal or lapse of the restrictions on the Units, the number of shares of Common Stock to be distributed by the Company to the Grantee, which are equal to the number of Units set forth in Section 1 above, or an economically equivalent amount of cash, as discussed in Section 8 above, shall be subject to applicable withholding requirements for income and employment taxes (unless withheld earlier at the time of vesting, as described in Section 3 above) arising from the removal or lapse of the restrictions on the Units. However, if the Grantee is a "specified employee" as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A who is subject to the six (6) months delay provided for in Section 8 above, the Company shall, on the date of the Grantee’s Termination of Service, based on the value of a share of Common Stock on such date, withhold the number of shares attributable to any employment taxes not withheld earlier and shall, on the date which occurs six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee), basedon the value of a share of Common Stock on such date, withhold the number of shares attributable to income taxes. Dividends will also be payable on such date to the Grantee for such delay period based on the net number of shares.

10. Modification.

This Award Agreement may be changed or modified without the Grantee's consent or signature, if the Company determines, in its sole discretion, that such change or modification is necessary for purposes of compliance with or exemption from the requirements of Section 409A of the Code and any regulations or other guidance issued thereunder, or otherwise to comply with any law.

Grantee acknowledges that as of the grant date, this Award Agreement and the Plan set forth the entire understanding between Grantee and the Company regarding the acquisition of the Units granted under the Plan and supersede all prior oral and written agreements on this subject. By Grantee’s electronic acceptance and the signature of the Company’s representative below, Grantee and the Company agree that the Units are granted under and governed by this Award Agreement and the Plan. Grantee has reviewed and fully understands all provisions of this Award Agreement and the Plan in their entirety.

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ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN

Kim R. Cocklin

Chief Executive Officer

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EX-10.11(C)

Exhibit 10.11(c)

AWARD AGREEMENT OF PERFORMANCE-BASED

RESTRICTED STOCK UNITS

UNDER THE ATMOS ENERGY CORPORATION

1998 LONG-TERM INCENTIVE PLAN

This Award Agreement of Performance-Based Restricted Stock Units (“Award Agreement”) is dated as of May 4, 2016, by and between Atmos Energy Corporation, a Texas and Virginia corporation (the "Company"), and you ("Grantee"), pursuant to the Company's 1998 Long-Term Incentive Plan (the "Plan"). Capitalized terms that are used, but not defined, in this Award Agreement shall have the meaning set forth in the Plan.

1.Grant and Description of Units.

Pursuant to authorization by the Human Resources Committee of the Board (the “Committee”), which has been designated by the Board to administer the Plan, the Company hereby grants to the Grantee performance-based restricted stock units (“Units”) under the Plan, for no consideration from the Grantee, with the restrictions set forth below. Each such Unit shall be a notional share of common stock of the Company (“Common Stock”), with the value of each Unit being equal to the Fair Market Value of a share of Common Stock at any time. No physical certificates representing the number of Units awarded shall be issued to the Grantee, but an account shall be established and maintained for the Grantee, in which each grant of Units to the Grantee shall be recorded, with the final number of Units as determined in accordance with Section 3 or Section 5 below. Until the final number of Units is determined, the Grantee shall not have any of the rights of a shareholder of the Company with respect to the Units, except for the crediting of dividend equivalents as provided for in Section 6 below.

2. Restrictions on Alienation of Units.

Units awarded hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated in any manner, whether voluntarily, by operation of law, or otherwise, until the restrictions on the Units are removed and the Units are delivered to the Grantee in the form of shares of Common Stock in the manner described below in Section 8.

3.Number of Units Awarded.

Except as provided in Section 5(a) below, the number of Units ultimately to be awarded to the Grantee upon vesting is contingent upon the cumulative amount of earnings per share achieved by the Company for the three year measurement cycle, Fiscal Years 2016 through 2018 (October 1, 2015 through September 30, 2018). The percentage of Units earned for each level of the cumulative amount of earnings per share is illustrated in the performance schedule below. In addition, should the performance levels achieved be between the stated criteria below, straight-

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line interpolation shall be used. For example, should the cumulative amount of earnings per share for the three-year period be $____, the percentage of Units earned would be _______% of the number of Units originally granted. In addition, the performance targets and actual performance attainment for such Units will exclude any mark-to-market gains or losses recognized by the Company’s nonregulated operations.

Performance-Based Restricted Stock Units Performance Schedule for Grant of Performance Period FY 2016-2018
Performance Level	Cumulative 3-Yr. EPS	Restricted Stock Units Earned
Below Threshold	Less than $_____	0%
Threshold	$_____	50%
Target	$_____	100%
Maximum	$_____	200%

4. Forfeiture of Units.

All Units granted shall be forfeited if, prior to the removal of restrictions on the Units awarded hereunder as provided below in Section 8, the Grantee has a voluntary or involuntary Termination of Service for any reason other than as described below in Section 5. Each Grantee, by his or her acceptance of the Units, agrees to execute any documents requested by the Company in connection with such forfeiture. Such provisions with respect to forfeited Units shall be specifically performable by the Company in a court of equity or law. Upon any forfeiture, all rights of the Grantee with respect to the forfeited Units shall cease and terminate, without any further obligation on the part of the Company.

5. Removal of Restrictions.

(a) Death, Disability, Certain Involuntary Terminations and Terminations following a Change in Control.

At the time and on the date of the Grantee's death, Termination of Service due to Total and Permanent Disability, involuntary Termination of Service due to a general reduction in force or specific elimination of the Grantee's job, or Termination of Service for any reason following a Change in Control, while employed by the Company or a Subsidiary, all restrictions placed on each Unit awarded shall be removed, and the measurement cycle for purposes of Section 6 and Section 8 below shall be deemed to have ended. The prorated number of Units awarded shall be determined by multiplying the percentage of Units awarded at the “Target” performance level discussed above in Section 3, by the ratio of actual months of service to 36 months of the original measurement cycle, with the resulting product being increased, if appropriate, as provided below in Section 6. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to such prorated number of Units.

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(b) Retirement.

At the time and on the date of the Grantee's Retirement on or after attaining the age of 55 and completing at least three (3) consecutive years of service with the Company at the time of such Retirement, the restrictions placed on the Units under Section 2 above shall not be removed and the percentage of Units earned shall not be determined until the end of the measurement cycle. The number of Units awarded shall be determined by multiplying the ratio of actual months of service to 36 months of the original measurement cycle by the percentage of Units earned, based on the actual performance achieved over the original measurement cycle, as discussed above in Section 3, with the resulting product being increased, if appropriate, as provided below in Section 6. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to such prorated number of Units.

6. Credit of Dividend Equivalents.

Immediately prior to distribution of Units as described above in Section 5 or below in Section 8, the Grantee’s account shall be credited with a number of Units which are based on the amount of dividends that are declared and paid on shares of Common Stock during each fiscal quarter of the measurement cycle, determined in accordance with Section 3 or Section 5 above (“dividend equivalents”). The number of Units upon which dividend equivalents shall be credited for the benefit of the Grantee is the total number of Units finally determined to have been earned by the Grantee at the end of the measurement cycle in accordance with Section 3 or Section 5 above, as appropriate. The total amount of each quarterly dividend equivalent shall be converted to the number of Units attributable to that quarterly dividend equivalent, by dividing such dividend equivalent amount by the average of the high and low prices of the Common Stock on the last trading day of the month during each quarter that such dividends are paid during the appropriate measurement cycle.

7. Adjustment Upon Changes in Stock.

If there shall be any change in the number of shares of Common Stock outstanding resulting from subdivision, combination, or reclassification of shares, or through merger, consolidation, reorganization, recapitalization, stock dividend, stock split or other change in the corporate structure, an appropriate adjustment in the number of Units with respect to which restrictions have not lapsed shall be made by the Committee. Depending upon the change in corporate structure, the Committee shall issue additional Units or substitute Units to the Grantee for his or her account, which shall have the same restrictions, terms and conditions as the original Units. Any such adjustment shall be in accordance with the applicable provisions of Section 14 and/or Section 15 of the Plan.

8. Distribution of Common Stock or Cash.

The Grantee shall receive a distribution of whole shares of Common Stock equal in number to the number of Units finally determined to be earned as set forth in Section 3 or

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Section 5(a) above, as the case may be, increased, if appropriate, as provided in Section 6 above (subject to the withholding requirements set forth in Section 9 below), provided the Grantee has been an employee of the Company or a Subsidiary with continuous service during the entire term of the measurement cycle, except in the event of the Grantee’s Termination of Service or Retirement as discussed above in Section 5. Distribution of shares of Common Stock shall occur as soon as administratively possible, as determined solely by the Company, following the last trading day of the quarter in which the measurement cycle ends as provided for in either Section 3 or Section 5(a) above, as the case may be (such day being referred to as the “Distribution Date”), but in no event later than 90 days following the Distribution Date. Notwithstanding the immediately preceding sentence, in the case of a distribution of shares of Common Stock on account of any Termination of Service as provided for in Section 5 above, other than death, a distribution of the number of such shares, determined after application of the withholding requirements set forth in Section 9 below, plus any dividends payable with respect to such number of shares, on behalf of the Grantee, if the Grantee is a "specified employee" as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A, to the extent otherwise required under Section 409A, shall not occur until the date which is six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee). Upon a distribution of shares of Common Stock as provided herein, the Company shall cause the Common Stock then being distributed to be registered in the Grantee’s name, but shall not issue certificates for the Common Stock unless the Grantee requests delivery of the certificates for the Common Stock, in writing in accordance with the procedures established by the Company. The Company shall deliver certificates to the Grantee as soon as administratively practicable following the Company’s receipt of a written request from the Grantee for delivery of the certificates. From and after the date of receipt of such distribution, the Grantee or the Grantee's legal representatives, beneficiaries or heirs, as the case may be, shall have full rights of transfer or resale with respect to such shares subject to applicable state and federal regulations. Notwithstanding any provisions of this Award Agreement to the contrary, in lieu of a distribution of shares of Common Stock, the Company shall have the option to settle the payment of some or all of the Units in an economically equivalent amount of cash.

9. Withholding Requirements.

Upon the removal or lapse of the restrictions on the Units, the number of shares of Common Stock to be distributed by the Company to the Grantee, which are equal to the number of Units finally determined to be earned by the Grantee as set forth in Sections 3 or Section 5(a) and Section 6 above, or an economically equivalent amount of cash, as discussed in Section 8 above, shall be subject to applicable withholding requirements for income and employment taxes arising from the removal or lapse of the restrictions on the Units. However, if the Grantee is a "specified employee" as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A who is subject to the six (6) months delay provided for in Section 8 above, the Company shall, on the date of the Grantee’s Termination of Service, based on the value of a share of Common Stock on such date, withhold the number of shares attributable to any employment taxes and shall, on the date which occurs six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee), basedon the value of a

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share of Common Stock on such date, withhold the number of shares attributable to income taxes. Dividends for such delay period will also be payable to the Grantee on such date based on the final net number of shares.  

10. Modification.

This Award Agreement may be changed or modified without the Grantee's consent or signature, if the Company determines, in its sole discretion, that such change or modification is necessary for purposes of compliance with or exemption from the requirements of Section 409A of the Code and any regulations or other guidance issued thereunder, or otherwise to comply with any law.

Grantee acknowledges that as of the grant date, this Award Agreement and the Plan set forth the entire understanding between Grantee and the Company regarding the acquisition of the Units granted under the Plan and supersede all prior oral and written agreements on this subject. By Grantee’s electronic acceptance and the signature of the Company’s representative below, Grantee and the Company agree that the Units are granted under and governed by this Award Agreement and the Plan. Grantee has reviewed and fully understands all provisions of this Award Agreement and the Plan in their entirety.

ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN

Kim R. Cocklin

Chief Executive Officer

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EX-12

Exhibit 12

Atmos Energy Corporation

Computation of Earnings to Fixed Charges

	Year Ended September 30
	2016		2015		2014		2013		2012
	(Dollars in thousands)
Income from continuing operations before provision for income taxes per statement of income	$	550,477	$	510,765	$	476,819	$	373,297	$	290,422
Add:
Portion of rents representative of the interest factor	12,525		12,383		12,231		12,442		12,623
Interest on debt & amortization of debt expense	115,948		116,241		129,295		128,385		141,174
Income as adjusted	$	678,950	$	639,389	$	618,345	$	514,124	$	444,219
Fixed charges:
Interest on debt & amortization of debt expense (1)	$	115,948	$	116,241	$	129,295	$	128,385	$	141,174
Capitalized interest (2)	2,790		2,260		1,522		1,895		2,642
Rents	37,575		37,150		36,693		37,326		37,868
Portion of rents representative of the interest factor (3)	12,525		12,383		12,231		12,442		12,623
Fixed charges (1)+(2)+(3)	$	131,263	$	130,884	$	143,048	$	142,722	$	156,439
Ratio of earnings to fixed charges	5.17		4.89		4.32		3.60		2.84

EX-21

Exhibit 21

SUBSIDIARIES OF ATMOS ENERGY CORPORATION

Name	State of Incorporation	Percent of Ownership
ATMOS ENERGY HOLDINGS, INC. (wholly owned by Atmos Energy Corporation)	Delaware	100%
BLUE FLAME INSURANCE SERVICES, LTD (wholly owned by Atmos Energy Corporation)	Bermuda	100%
ATMOS ENERGY SERVICES, LLC (a limited liability company) (wholly owned by Atmos Energy Holdings, Inc.)	Delaware	100%
EGASCO, LLC (a limited liability company) (wholly owned by Atmos Energy Holdings, Inc.)	Texas	100%
ATMOS ENERGY MARKETING, LLC (a limited liability company) (wholly owned by Atmos Energy Holdings, Inc.)	Delaware	100%
ATMOS POWER SYSTEMS, INC. (a wholly owned by Atmos Energy Holdings, Inc.)	Georgia	100%
ATMOS PIPELINE AND STORAGE, LLC (a limited liability company) (wholly owned by Atmos Energy Holdings, Inc.)	Delaware	100%
UCG STORAGE, INC. (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%
WKG STORAGE, INC. (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%
ATMOS EXPLORATION AND PRODUCTION, INC. (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%

Name	State of Incorporation	Percent of Ownership
TRANS LOUISIANA GAS PIPELINE, INC. (wholly owned by Atmos Pipeline and Storage, LLC)	Louisiana	100%
TRANS LOUISIANA GAS STORAGE, INC. (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%
ATMOS GATHERING COMPANY, LLC (a limited liability company) (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%
PHOENIX GAS GATHERING COMPANY (wholly owned by Atmos Gathering Company, LLC)	Delaware	100%
FORT NECESSITY GAS STORAGE, LLC (a limited liability company) (wholly owned by Atmos Pipeline and Storage, LLC)	Delaware	100%

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements (Form S-3, No. 33-37869; Form S-3, No. 33-58220; Form S-3D/A, No. 33-70212; Form S-3, No. 33-56915; Form S-3/A, No. 333-03339; Form S-3/A, No. 333-32475; Form S-3/A, No. 333-50477; Form S-3, No. 333-95525; Form S-3/A, No. 333-93705; Form S-3, No. 333-75576; Form S-3D, No. 333-113603; Form S-3, No. 333-118706; Form S-3D, No. 333-155666; Form S-3D, No. 333-208317; Form S-3ASR, No. 333-210424; Form S-4, No. 333-13429; Form S-8, No. 33-57687; Form S-8, No. 33-57695; Form S-8, No. 333-32343; Form S-8, No. 333-46337; Form S-8, No. 333-73143; Form S-8, No. 333-73145; Form S-8, No. 333-63738; Form S-8, No. 333-88832; Form S-8, No. 333-116367; Form S-8, No. 333-138209; Form S-8, No. 333-145817; Form S-8, No. 333-155570; Form S-8, No. 333-166639; Form S-8, No. 333-177593; Form S-8, No. 333-199301; and Form S-8, No. 333-210461) of Atmos Energy Corporation and in the related Prospectuses of our reports dated November 14, 2016, with respect to the consolidated financial statements and schedule of Atmos Energy Corporation and the effectiveness of internal control over financial reporting of Atmos Energy Corporation, included in this Annual Report (Form 10-K) for the year ended September 30, 2016.

/s/ ERNST & YOUNG LLP

Dallas, Texas

November 14, 2016

EX-31

EXHIBIT 31

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

I, Kim R. Cocklin, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 14, 2016

/s/ KIM R. COCKLIN

Kim R. Cocklin

Chief Executive Officer

I, Bret J. Eckert, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 14, 2016

/s/ BRET J. ECKERT

Bret J. Eckert

Senior Vice President and

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

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

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the fiscal year ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Kim R. Cocklin, Chief Executive Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

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

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

November 14, 2016

/s/ KIM R. COCKLIN

Kim R. Cocklin

Chief Executive Officer

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

CERTIFICATION OF CHIEF FINANCIAL OFFICER

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

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the fiscal year ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Bret J. Eckert, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

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

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

November 14, 2016

/s/ BRET J. ECKERT

Bret J. Eckert

Senior Vice President and

Chief Financial Officer

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

XML

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2016	Nov. 09, 2016	Mar. 31, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	Atmos Energy Corporation
Entity Central Index Key	0000731802
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock Shares Outstanding		103,964,735
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 7,463,087,078

XML

CONSOLIDATED BALANCE SHEETS - USD ($)		Sep. 30, 2016	Sep. 30, 2015
ASSETS
Property, plant and equipment		$ 9,987,078,000	$ 8,959,702,000
Construction in progress		184,062,000	280,398,000
Total property, plant and equipment and construction in progress		10,171,140,000	9,240,100,000
Less accumulated depreciation and amortization		1,890,629,000	1,809,520,000
Net property, plant and equipment	[1]	8,280,511,000	7,430,580,000
Current assets
Cash and cash equivalents		47,534,000	28,653,000
Accounts receivable, less allowance for doubtful accounts of $13,367 in 2016 and $15,283 in 2015		300,007,000	295,160,000
Gas stored underground		233,316,000	236,603,000
Other current assets		100,829,000	65,890,000
Total current assets		681,686,000	626,306,000
Goodwill		743,407,000	742,702,000
Deferred charges and other assets		305,285,000	275,484,000
Total assets		10,010,889,000	9,075,072,000
Shareholders' equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2016 — 103,930,560 shares, 2015 — 101,478,818 shares		520,000	507,000
Additional paid-in capital		2,388,027,000	2,230,591,000
Accumulated other comprehensive loss		(188,022,000)	(109,330,000)
Retained earnings		1,262,534,000	1,073,029,000
Shareholders' equity		3,463,059,000	3,194,797,000
Long-term debt		2,188,779,000	2,437,515,000
Total capitalization		5,651,838,000	5,632,312,000
Current liabilities
Accounts payable and accrued liabilities		259,434,000	238,942,000
Other current liabilities		449,036,000	457,954,000
Short-term debt		829,811,000	457,927,000
Current maturities of long-term debt		250,000,000	0
Total current liabilities		1,788,281,000	1,154,823,000
Deferred income taxes		1,603,056,000	1,411,315,000
Regulatory cost of removal obligation		424,281,000	427,553,000
Pension and postretirement liabilities		297,743,000	287,373,000
Deferred credits and other liabilities		245,690,000	161,696,000
Total shareholders' equity and liabilities		$ 10,010,889,000	$ 9,075,072,000

[1] Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

XML

CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Thousands	Sep. 30, 2016	Sep. 30, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 13,367	$ 15,283
Common Stock, Stated Value Per Share	$ 0.005	$ 0.005
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	103,930,560	101,478,818

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Operating revenues
Operating revenues	$ 678,519	$ 632,916	$ 1,132,293	$ 906,221	$ 656,902	$ 686,401	$ 1,540,068	$ 1,258,765	$ 3,349,949	$ 4,142,136	$ 4,940,916
Purchased gas cost
Purchased gas cost									1,605,053	2,462,119	3,358,490
Gross profit	376,011	407,311	517,811	443,763	354,321	381,673	520,738	423,285	1,744,896	1,680,017	1,582,426
Operating expenses
Operation and maintenance									560,766	541,868	505,154
Depreciation and amortization									293,096	274,796	253,987
Taxes, other than income									223,016	231,958	211,936
Total operating expenses									1,076,878	1,048,622	971,077
Operating income	84,633	137,164	250,016	196,205	75,853	117,607	250,210	187,725	668,018	631,395	611,349
Miscellaneous income (expense), net									(1,593)	(4,389)	(5,235)
Interest charges									115,948	116,241	129,295
Income before income taxes									550,477	510,765	476,819
Income tax expense									200,373	195,690	187,002
Net income	$ 34,240	$ 71,193	$ 141,810	$ 102,861	$ 23,515	$ 56,281	$ 137,684	$ 97,595	$ 350,104	$ 315,075	$ 289,817
Basic net income per share	$ 0.33	$ 0.69	$ 1.38	$ 1.00	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 3.38	$ 3.09	$ 2.96
Diluted net income per share	$ 0.33	$ 0.69	$ 1.38	$ 1.00	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 3.38	$ 3.09	$ 2.96
Weighted average shares outstanding:
Basic (shares)									103,524	101,892	97,606
Diluted (shares)									103,524	101,892	97,608
Regulated Distribution Segment [Member]
Operating revenues
Operating revenues	$ 389,353	$ 414,226	$ 849,685	$ 638,602	$ 369,656	$ 416,794	$ 1,130,613	$ 846,772	$ 2,291,866	$ 2,763,835	$ 3,061,546
Purchased gas cost
Purchased gas cost									1,019,061	1,526,258	1,885,031
Gross profit									1,272,805	1,237,577	1,176,515
Operating expenses
Operation and maintenance									404,115	388,486	387,228
Depreciation and amortization									233,036	223,048	208,376
Taxes, other than income									196,070	205,894	196,343
Total operating expenses									833,221	817,428	791,947
Operating income									439,584	420,149	384,568
Miscellaneous income (expense), net									455	(377)	(381)
Interest charges									79,404	84,132	94,918
Income before income taxes									360,635	335,640	289,269
Income tax expense									128,265	130,827	117,684
Net income									232,370	204,813	171,585
Regulated Pipeline Segment [Member]
Operating revenues
Operating revenues	109,204	109,249	95,703	94,677	97,807	97,008	91,730	83,567	408,833	370,112	318,459
Purchased gas cost
Purchased gas cost									0	0	0
Gross profit									408,833	370,112	318,459
Operating expenses
Operation and maintenance									129,525	118,866	91,466
Depreciation and amortization									55,576	47,236	41,031
Taxes, other than income									24,298	22,743	13,143
Total operating expenses									209,399	188,845	145,640
Operating income									199,434	181,267	172,819
Miscellaneous income (expense), net									(1,683)	(1,243)	(3,181)
Interest charges									36,574	33,151	36,280
Income before income taxes									161,177	146,873	133,358
Income tax expense									59,488	52,211	47,167
Net income									101,689	94,662	86,191
Nonregulated Segment [Member]
Operating revenues
Operating revenues	291,889	214,555	287,395	272,524	292,830	278,769	438,322	462,288	1,066,363	1,472,209	2,067,292
Purchased gas cost
Purchased gas cost									1,002,573	1,399,349	1,979,337
Gross profit									63,790	72,860	87,955
Operating expenses
Operation and maintenance									27,658	35,048	26,963
Depreciation and amortization									4,484	4,512	4,580
Taxes, other than income									2,648	3,321	2,450
Total operating expenses									34,790	42,881	33,993
Operating income									29,000	29,979	53,962
Miscellaneous income (expense), net									1,443	(760)	2,216
Interest charges									1,778	967	1,986
Income before income taxes									28,665	28,252	54,192
Income tax expense									12,620	12,652	22,151
Net income									16,045	15,600	32,041
Intersegment Elimination [Member]
Operating revenues
Operating revenues	$ (111,927)	$ (105,114)	$ (100,490)	$ (99,582)	$ (103,391)	$ (106,170)	$ (120,597)	$ (133,862)	(417,113)	(464,020)	(506,381)
Purchased gas cost
Purchased gas cost									(416,581)	(463,488)	(505,878)
Gross profit									(532)	(532)	(503)
Operating expenses
Operation and maintenance									(532)	(532)	(503)
Depreciation and amortization									0	0	0
Taxes, other than income									0	0	0
Total operating expenses									(532)	(532)	(503)
Operating income									0	0	0
Miscellaneous income (expense), net									(1,808)	(2,009)	(3,889)
Interest charges									(1,808)	(2,009)	(3,889)
Income before income taxes									0	0	0
Income tax expense									0	0	0
Net income									$ 0	$ 0	$ 0

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income		$ 350,104	$ 315,075	$ 289,817
Other comprehensive income (loss), net of tax [Abstract]
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(245), $(1,559) and $1,199		(465)	(2,713)	2,214
Schedule of Other Comprehensive Income (Loss), Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	[1]	(78,227)	(94,224)
Total other comprehensive income (loss)		(78,692)	(96,937)	(51,271)
Total comprehensive income		271,412	218,138	238,546
Interest Rate Contract [Member]
Schedule of Other Comprehensive Income (Loss), Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax		(98,682)	(70,461)	(56,287)
Commodity Contract [Member]
Schedule of Other Comprehensive Income (Loss), Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax		$ 20,455	$ (23,763)	$ 2,802

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (PARENTHETICAL) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent, Parenthetical Disclosures [Abstract]
Unrealized holding gains (losses) on available-for-sale securities, tax	$ (245)	$ (1,559)	$ 1,199
Interest Rate Contract [Member]
Schedule of Other Comprehensive Income (Loss), Tax, Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	(56,723)	(40,501)	(32,353)
Commodity Contract [Member]
Schedule of Other Comprehensive Income (Loss), Tax, Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	$ 13,078	$ (15,193)	$ 1,791

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CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid In Capital [Member]	Accumulated Other Comprehensive Income [Member]	Retained Earnings [Member]
Common stock shares outstanding, balance at Sep. 30, 2013		90,640,211
Shareholders' equity, beginning balance at Sep. 30, 2013	$ 2,580,409	$ 453	$ 1,765,811	$ 38,878	$ 775,267
Net income	289,817				289,817
Other comprehensive income (loss)	(51,271)			(51,271)
Repurchase of equity awards, shares		(190,134)
Repurchase of equity awards, amount	(8,717)	$ (1)	(8,716)
Cash dividends	(146,248)				(146,248)
Common stock issued:
Public offering, shares		9,200,000
Public offering, amount	390,205	$ 46	390,159
Direct stock purchase plan, shares		83,150
Direct stock purchase plan, amount	4,067	$ 1	4,066
Retirement savings plan, shares		398,047
Retirement savings plan, amount	20,326	$ 2	20,324
1998 Long-term incentive plan, shares		653,130
1998 Long-term incentive plan, amount	4,353	$ 3	5,214		(864)
Employee stock-based compensation	23,536		23,536
Outside directors stock-for-fee plan, shares		1,735
Outside directors stock-for-fee-plan, amount	81		81
Common stock shares outstanding, ending balance at Sep. 30, 2014		100,388,092
Shareholders' equity, ending balance at Sep. 30, 2014	3,086,232	$ 502	2,180,151	(12,393)	917,972
Net income	315,075				315,075
Other comprehensive income (loss)	(96,937)			(96,937)
Repurchase of equity awards, shares		(148,464)
Repurchase of equity awards, amount	(7,985)	$ (1)	(7,984)
Cash dividends	(160,018)				(160,018)
Common stock issued:
Direct stock purchase plan, shares		176,391
Direct stock purchase plan, amount	10,626	$ 1	10,625
1998 Long-term incentive plan, shares		664,752
1998 Long-term incentive plan, amount	2,266	$ 3	2,263		0
Employee stock-based compensation	25,212		25,212
Common stock shares outstanding, ending balance at Sep. 30, 2015		101,478,818
Shareholders' equity, ending balance at Sep. 30, 2015	3,194,797	$ 507	2,230,591	(109,330)	1,073,029
Net income	350,104				350,104
Other comprehensive income (loss)	(78,692)			(78,692)
Cash dividends	(175,126)				(175,126)
Common stock issued:
Public offering, shares		1,360,756
Public offering, amount	98,574	$ 7	98,567
Direct stock purchase plan, shares		133,133
Direct stock purchase plan, amount	9,229	$ 1	9,228
Retirement savings plan, shares		359,414
Retirement savings plan, amount	25,049	$ 2	25,047
1998 Long-term incentive plan, shares		598,439
1998 Long-term incentive plan, amount	3,178	$ 3	3,175		0
Employee stock-based compensation	21,419		21,419
Common stock shares outstanding, ending balance at Sep. 30, 2016		103,930,560
Shareholders' equity, ending balance at Sep. 30, 2016	3,463,059	$ 520	$ 2,388,027	$ (188,022)	1,262,534
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 14,527				$ 14,527

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CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (PARENTHETICALS) - $ / shares	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Statement of Stockholders' Equity [Abstract]
Cash dividends per share	$ 1.68	$ 1.56	$ 1.48

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 350,104	$ 315,075	$ 289,817
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	293,096	274,796	253,987
Deferred income taxes	193,556	192,886	189,952
Stock-based compensation	14,760	15,980	14,721
Debt financing costs	5,667	5,922	9,409
Other	1,019	359	541
Changes in assets and liabilities:
(Increase) decreased in accounts receivable	(4,847)	48,240	(41,408)
Decrease in gas stored underground	20,577	33,234	(31,996)
(Increase) decrease in other current assets	(18,739)	(11,951)	(24,411)
(Increase) decrease in deferred charges and other assets	(24,860)	51,614	28,875
Increase (decrease) in account payable and accrued liabilities	(5,195)	(59,112)	60,465
Increase (decrease) in other current liabilities	(44,482)	896	2,413
Increase (decrease) in deferred credits and other liabilities	14,334	(56,025)	(19,552)
Net cash provided by operating activities	794,990	811,914	732,813
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures	(1,086,950)	(963,621)	(824,441)
Payments to Acquire Available-for-sale Securities	(32,551)	(29,527)	(32,734)
Proceeds from Sale of Available-for-sale Securities	27,019	24,889	24,872
Proceeds from Maturities, Prepayments and Calls of Available-for-sale Securities	6,290	6,235	5,215
Other, net	6,460	5,422	2,109
Net cash used in investing activities	(1,079,732)	(956,602)	(824,979)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt	371,884	261,232	(171,289)
Proceeds from issuance of long-term debt	0	499,060	0
Net proceeds from equity offering	98,574	0	390,205
Issuance of common stock through stock purchase and employee retirement plans	34,278	30,952	4,274
Settlement of interest rate agreement	0	13,364	0
Interest rate agreements cash collateral	(25,670)	0	0
Repayment of long-term debt	0	(500,000)	0
Cash dividends paid	(175,126)	(160,018)	(146,248)
Repurchase of equity awards	0	(7,985)	(8,717)
Other	(317)	(5,522)	0
Net cash provided by (used in) financing activities	303,623	131,083	68,225
Net increase (decrease) in cash and cash equivalents	18,881	(13,605)	(23,941)
Cash and cash equivalents at beginning of period	28,653	42,258	66,199
Cash and cash equivalents at end of period	47,534	28,653	42,258
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest	154,748	151,334	156,606
Income taxes	$ 7,794	$ 1,802	$ (610)

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Nature of Business

12 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

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 certain other nonregulated businesses. Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated distribution divisions in the service areas described below:

Division	Service Area
Atmos Energy Colorado-Kansas Division	Colorado, Kansas
Atmos Energy Kentucky/Mid-States Division	Kentucky, Tennessee, Virginia(1)
Atmos Energy Louisiana Division	Louisiana
Atmos Energy Mid-Tex Division	Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division	Mississippi
Atmos Energy West Texas Division	West Texas

⁽¹⁾  Denotes location where we have more limited service areas.

In addition, we transport natural gas for others through our distribution system. Our distribution business is 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 corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

Our regulated pipeline business, which is also subject to federal and state regulation, consists of the regulated operations of our Atmos Pipeline–Texas Division, a division of the Company. This division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand.

Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc., (AEH). AEH is a wholly-owned subsidiary of the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, regulated distribution companies, including certain divisions of Atmos Energy and third parties.

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Significant Accounting Policies

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.

Basis of comparison — As described under Recent Accounting Pronouncements below, we reclassified debt issuance costs from deferred charges and other assets to long-term debt. Additionally, we recorded immaterial corrections to the presentation of certain activities on our Consolidated Statement of Cash Flows for the years ended September 30, 2015 and 2014.

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.

Regulation — Our regulated distribution and regulated pipeline operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. 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 that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations.

We record regulatory assets as a component of other current assets and deferred charges and other assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded either on the face of the balance sheet or as a component of current liabilities, deferred income taxes or deferred credits and other liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of September 30, 2016 and 2015 included the following:

	September 30
	2016		2015
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	132,348	$	121,183
Infrastructure Mechanisms(2)	42,719		32,813
Deferred gas costs	45,184		9,715
Recoverable loss on reacquired debt	13,761		16,319
Deferred pipeline record collection costs	7,336		3,118
APT annual adjustment mechanism	7,171		1,002
Rate case costs	1,539		1,533
Other	13,565		6,656
	$	263,623	$	192,339
Regulatory liabilities:
Regulatory cost of removal obligation	$	476,891	$	483,676
Deferred gas costs	20,180		28,100
Asset retirement obligation	13,404		9,063
Other	4,250		3,693
	$	514,725	$	524,532

⁽¹⁾ Includes $12.4 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 eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

Revenue recognition — Sales of natural gas to our regulated distribution customers are billed on a monthly basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for regulated distribution segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense.

On occasion, we are permitted to implement new rates that have not been formally approved by our state regulatory commissions, which are subject to refund. As permitted by accounting principles generally accepted in the United States, we recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.

Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no gross profit generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our regulated distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our balance sheet.

Operating revenues for our regulated pipeline and nonregulated segments are recognized in the period in which actual volumes are transported and storage services are provided.

Operating revenues for our nonregulated segment and the associated carrying value of natural gas inventory (inclusive of storage costs) are recognized when we sell the gas and physically deliver it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial instruments used in our nonregulated activities.

Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our collection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our regulated distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for substantially all of our regulated operations. Our nonregulated segment utilizes the average cost method; however, most of this inventory is hedged and is therefore reported at fair value at the end of each month. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.

Regulated property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes when the completed projects are placed in service. Interest expense of $2.8 million, $2.3 million and $1.5 million was capitalized in 2016, 2015 and 2014.

Major renewals, including replacement pipe, and betterments that are recoverable under our regulatory rate base are capitalized while the costs of maintenance and repairs that are not recoverable through rates are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.

Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.2 percent for the fiscal year ended September 30, 2016, and 3.3 percent for each of the fiscal years ended September 30, 2015 and 2014.

Nonregulated property, plant and equipment — Nonregulated property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from three to 43 years.

Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense.

As of September 30, 2016 and 2015, we had asset retirement obligations of $13.4 million and $11.1 million. Additionally, we had $8.1 million and $4.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.

We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.

Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

Marketable securities — As of September 30, 2016 and 2015, all of our marketable securities were classified as available for sale. In accordance with the authoritative accounting standards, 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 an individual investment by investment 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 investment is written down to its estimated fair value.

Financial instruments and hedging activities — We use financial instruments to mitigate commodity price risk in our regulated distribution and nonregulated segments and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses and are discussed in Note 13.

We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ultimately recorded in the income statement. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.

The timing of when changes in fair value of our financial instruments are recorded in the income statement depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the income statement as they occur.

Financial Instruments Associated with Commodity Price Risk

In our regulated distribution segment, the costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our regulated distribution segment as a result of the use of financial instruments.

In our nonregulated segment, we have designated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge. This inventory is marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. The financial instruments associated with this natural gas inventory have been designated as fair-value hedges and are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges. For the fiscal years ended September 30, 2016, 2015 and 2014, we included unrealized gains (losses) on open contracts of $1.3 million, $(2.4) million and $9.6 million as a component of nonregulated purchased gas cost.

Additionally, we have elected to treat fixed-price forward contracts used in our nonregulated segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries are recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts have been designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments are recorded as a component of accumulated other comprehensive income, and are recognized in earnings as a component of purchased gas cost when the hedged volumes are sold.

Gains and losses from hedge ineffectiveness are recognized in the income statement. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges 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 is referred to as timing ineffectiveness. Hedge ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost.

Our nonregulated segment also utilizes master netting agreements with significant counterparties that allow us to offset gains and losses arising from financial instruments that may be settled in cash with gains and losses arising from financial instruments that may be settled with the physical commodity. Assets and liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under master netting agreements used to offset gains and losses arising from financial instruments. As of September 30, 2016 and 2015, the Company netted $24.7 million and $43.5 million of cash held in margin accounts into its current and noncurrent risk management assets and liabilities.

Financial Instruments Associated with Interest Rate Risk

We manage interest rate risk, primarily when we plan to issue new long-term debt or to refinance existing long-term debt. We currently manage this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest expense. As of September 30, 2016, the Company netted $25.7 million of cash held in margin accounts into its current and noncurrent risk management liabilities. As of September 30, 2015 no cash was required to be held in margin accounts.

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 primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.

Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.

Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.

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) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:

Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices), as permitted under current accounting standards. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed.

Our Level 1 measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.

Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as common collective trusts, corporate bonds and investments in limited partnerships.

Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.

Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. Our measurement date is September 30. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds.

The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors when making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.

The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this calculation will delay the impact of current market fluctuations on the pension expense for the period.

We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.

We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon the annual review of our participant census information as of the measurement date.

Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.

Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.

Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and reasonably estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.

Subsequent events — Except as noted in Note 5 regarding the renewal of our revolving credit facility and the AEM uncommitted 364-day bilateral credit facility and Note 15 regarding the proposed sale of AEM, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.

Recent accounting pronouncements — 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. As of September 30, 2016, we were actively evaluating all of our sources of revenue to determine the potential effect of the new standard on our financial position, results of operations and cash flows and the transition approach we will utilize. We are also actively monitoring the deliberations of the FASB's Transition Resource Group as decisions made by this group will impact the final conclusions of this evaluation.

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. The new guidance aligns the presentation of debt issuance costs with debt discounts and premiums. While the guidance would have been effective for us beginning October 1, 2016, we elected early adoption effectiveSeptember 30, 2016 and have applied the provisions of the new guidance to each prior period presented. As a result, we reclassified $17.0 million and $17.9 million of unamortized debt issuance costs from deferred charges and other assets to long-term debt on the September 30, 2016 and 2015 consolidated balance sheets.

In April 2015, the FASB issued guidance to simplify the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. The new guidance is effective for us beginning October 1, 2016 and may be applied either prospectively or retrospectively with early adoption permitted. The adoption of this standard will not impact on our financial position, results of operations and cash flows.

In May 2015, the FASB issued guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The guidance is effective for us on October 1, 2016 to be applied retrospectively. The adoption of this standard will have no impact on our results of operations, consolidated balance sheets or 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. Previously, entities were required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. As permitted under the new guidance, we elected early adoption as of March 31, 2016. The adoption of this guidance had no impact on our results of operations or cash flows. Because we adopted this new guidance prospectively, prior periods have not been adjusted.

In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning October 1, 2018; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance.

In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adoption is permitted. The new leasing standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. We are currently evaluating the effect on our financial position, results of operations and cash flows.

In March 2016, the FASB issued guidance to simplify the accounting and reporting of share-based payment arrangements. Key modifications required under the new guidance include:

• Recognition of all excess tax benefits and tax deficiencies associated with stock-based compensation as income tax expense or benefit in the income statement in the period the awards vest. The guidance also requires these income tax inflows and outflows to be classified as an operating activity.

• Simplification of the accounting for forfeitures.

• Clarification that cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity.

As permitted under the new guidance, we elected early adoption as of March 31, 2016. In accordance with the transition requirements, we recorded a $14.5 million cumulative-effect increase to retained earnings as of October 1, 2015, with an offsetting increase to the Company’s net operating loss (NOL) deferred tax asset to recognize the effect of excess tax benefits earned prior to September 30, 2015. For the year ended September 30, 2016, we have recognized a total income tax benefit of $5.0 million. The new guidance provides for certain provisions to be accounted for prospectively and others retrospectively.

In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are currently evaluating the potential impact of this new guidance.

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Segment Information

12 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Information

Segment Information

Atmos Energy Corporation and its subsidiaries are engaged primarily in the regulated natural gas distribution and pipeline business as well as other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which cover service areas located in eight states. In addition, we transport natural gas for others through our distribution system.

Through our nonregulated business, we provide natural gas management and transportation services to municipalities, regulated distribution companies, including certain divisions of Atmos Energy and third parties.

We operate the Company through the following three segments:

• The regulated distribution segment, includes our regulated distribution and related sales operations.

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

• The nonregulated segment, 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 aggregated and 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. We evaluate performance based on net income or loss of the respective operating units. Interest expense is allocated pro rata to each segment based upon our net investment in each segment. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.

Summarized income statements and capital expenditures by segment are shown in the following tables.

	Year Ended September 30, 2016
	Regulated Distribution		Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,284,185	$	104,007		$	961,757	$	—		$	3,349,949
Intersegment revenues	7,681		304,826			104,606		(417,113		)	—
	2,291,866		408,833			1,066,363		(417,113		)	3,349,949
Purchased gas cost	1,019,061		—			1,002,573		(416,581		)	1,605,053
Gross profit	1,272,805		408,833			63,790		(532		)	1,744,896
Operating expenses
Operation and maintenance	404,115		129,525			27,658		(532		)	560,766
Depreciation and amortization	233,036		55,576			4,484		—			293,096
Taxes, other than income	196,070		24,298			2,648		—			223,016
Total operating expenses	833,221		209,399			34,790		(532		)	1,076,878
Operating income	439,584		199,434			29,000		—			668,018
Miscellaneous income (expense)	455		(1,683		)	1,443		(1,808		)	(1,593		)
Interest charges	79,404		36,574			1,778		(1,808		)	115,948
Income before income taxes	360,635		161,177			28,665		—			550,477
Income tax expense	128,265		59,488			12,620		—			200,373
Net income	$	232,370	$	101,689		$	16,045	$	—		$	350,104
Capital expenditures	$	740,039	$	346,400		$	511	$	—		$	1,086,950

	Year Ended September 30, 2015
	Regulated Distribution			Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,757,585		$	97,662		$	1,286,889		$	—		$	4,142,136
Intersegment revenues	6,250			272,450			185,320			(464,020		)	—
	2,763,835			370,112			1,472,209			(464,020		)	4,142,136
Purchased gas cost	1,526,258			—			1,399,349			(463,488		)	2,462,119
Gross profit	1,237,577			370,112			72,860			(532		)	1,680,017
Operating expenses
Operation and maintenance	388,486			118,866			35,048			(532		)	541,868
Depreciation and amortization	223,048			47,236			4,512			—			274,796
Taxes, other than income	205,894			22,743			3,321			—			231,958
Total operating expenses	817,428			188,845			42,881			(532		)	1,048,622
Operating income	420,149			181,267			29,979			—			631,395
Miscellaneous expense	(377		)	(1,243		)	(760		)	(2,009		)	(4,389		)
Interest charges	84,132			33,151			967			(2,009		)	116,241
Income before income taxes	335,640			146,873			28,252			—			510,765
Income tax expense	130,827			52,211			12,652			—			195,690
Net income	$	204,813		$	94,662		$	15,600		$	—		$	315,075
Capital expenditures	$	670,575		$	291,603		$	1,443		$	—		$	963,621

	Year Ended September 30, 2014
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	3,056,212		$	92,166		$	1,792,538	$	—		$	4,940,916
Intersegment revenues	5,334			226,293			274,754		(506,381		)	—
	3,061,546			318,459			2,067,292		(506,381		)	4,940,916
Purchased gas cost	1,885,031			—			1,979,337		(505,878		)	3,358,490
Gross profit	1,176,515			318,459			87,955		(503		)	1,582,426
Operating expenses
Operation and maintenance	387,228			91,466			26,963		(503		)	505,154
Depreciation and amortization	208,376			41,031			4,580		—			253,987
Taxes, other than income	196,343			13,143			2,450		—			211,936
Total operating expenses	791,947			145,640			33,993		(503		)	971,077
Operating income	384,568			172,819			53,962		—			611,349
Miscellaneous income (expense)	(381		)	(3,181		)	2,216		(3,889		)	(5,235		)
Interest charges	94,918			36,280			1,986		(3,889		)	129,295
Income before income taxes	289,269			133,358			54,192		—			476,819
Income tax expense	117,684			47,167			22,151		—			187,002
Net income	$	171,585		$	86,191		$	32,041	$	—		$	289,817
Capital expenditures	$	574,372		$	248,230		$	1,839	$	—		$	824,441

The following table summarizes our revenues from external parties by products and services for the fiscal year ended September 30.

	2016		2015		2014
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,477,049	$	1,761,689	$	1,933,099
Commercial	619,979		772,187		876,042
Industrial	51,999		74,981		90,536
Public authority and other	41,307		53,401		64,779
Total gas sales revenues	2,190,334		2,662,258		2,964,456
Transportation revenues	70,383		67,475		64,049
Other gas revenues	23,468		27,852		27,707
Total regulated distribution revenues	2,284,185		2,757,585		3,056,212
Regulated pipeline revenues	104,007		97,662		92,166
Nonregulated revenues	961,757		1,286,889		1,792,538
Total operating revenues	$	3,349,949	$	4,142,136	$	4,940,916

Balance sheet information at September 30, 2016 and 2015 by segment is presented in the following tables.

	September 30, 2016
	Regulated Distribution		Regulated Pipeline		Nonregulated		Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	6,220,425	$	2,008,997	$	51,089	$	—		$	8,280,511
Investment in subsidiaries	1,026,859		—		—		(1,026,859		)	—
Current assets
Cash and cash equivalents	21,072		—		26,462		—			47,534
Assets from risk management activities	3,029		—		6,775		—			9,804
Other current assets	446,868		19,204		367,220		(208,944		)	624,348
Intercompany receivables	978,093		—		—		(978,093		)	—
Total current assets	1,449,062		19,204		400,457		(1,187,037		)	681,686
Goodwill	576,114		132,582		34,711		—			743,407
Noncurrent assets from risk management activities	1,822		—		—		—			1,822
Deferred charges and other assets	275,496		27,631		336		—			303,463
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,463,059	$	678,964	$	347,895	$	(1,026,859	)	$	3,463,059
Long-term debt	2,188,779		—		—		—			2,188,779
Total capitalization	5,651,838		678,964		347,895		(1,026,859		)	5,651,838
Current liabilities
Current maturities of long-term debt	250,000		—		—		—			250,000
Short-term debt	1,026,811		—		—		(197,000		)	829,811
Liabilities from risk management activities	56,771		—		—		—			56,771
Other current liabilities	549,328		22,427		91,888		(11,944		)	651,699
Intercompany payables	—		950,215		27,878		(978,093		)	—
Total current liabilities	1,882,910		972,642		119,766		(1,187,037		)	1,788,281
Deferred income taxes	1,058,895		536,732		7,429		—			1,603,056
Noncurrent liabilities from risk management activities	184,048		—		—		—			184,048
Regulatory cost of removal obligation	424,281		—		—		—			424,281
Pension and postretirement liabilities	297,743		—		—		—			297,743
Deferred credits and other liabilities	50,063		76		11,503		—			61,642
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889

	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	421,591		24,628		480,503			(338,301		)	588,421
Intercompany receivables	887,713		—		—			(887,713		)	—
Total current assets	1,333,545		24,628		494,147			(1,226,014		)	626,306
Goodwill	575,449		132,542		34,711			—			742,702
Noncurrent assets from risk management activities	368		—		—			—			368
Deferred charges and other assets	252,499		17,288		5,329			—			275,116
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,194,797	$	577,275	$	461,395		$	(1,038,670	)	$	3,194,797
Long-term debt	2,437,515		—		—			—			2,437,515
Total capitalization	5,632,312		577,275		461,395			(1,038,670		)	5,632,312
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
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072

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Earnings Per Share

12 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:

	2016		2015		2014
	(In thousands, except per share data)
Basic Earnings Per Share
Net Income	$	350,104	$	315,075	$	289,817
Less: Income allocated to participating securities	546		626		711
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Net Income per share — Basic	$	3.38	$	3.09	$	2.96
Diluted Earnings Per Share
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Effect of dilutive stock options and other shares	—		—		—
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Additional dilutive stock options and other shares	—		—		2
Diluted weighted average shares outstanding	103,524		101,892		97,608
Net Income per share — Diluted	$	3.38	$	3.09	$	2.96

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Debt

12 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt

Debt

Long-term debt

Long-term debt at September 30, 2016 and 2015 consisted of the following:

	2016		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 Series A notes, 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	4,270		4,612
Debt issuance cost	16,951		17,873
Current maturities	250,000		—
	$	2,188,779	$	2,437,515

On September 22, 2016, we entered into a three year, $200 million multi-draw term loan agreement with a syndicate of three lenders. Borrowings under the term loan may be made in increments of $1.0 million or higher, may be repaid at any time during the loan period and will bear interest at a rate dependent upon our credit ratings at the time of such borrowing and based, at our election, on a base rate or LIBOR for the applicable interest period. The term loan will be used to refinance existing indebtedness and for working capital, capital expenditures and other general corporate purposes. At September 30, 2016, there were no borrowings under the term loan.

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 discussed in Note 13. The net proceeds of approximately $494 million were used to repay our $500 million4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt

Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply and general corporate liquidity. Our short-term borrowings typically reach their highest levels in the winter months.

As of September 30, 2016, we financed 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 a total availability from third-party lenders of approximately $1.3 billion of working capital funding. On October 5, 2016, we amended our existing $1.25 billion unsecured credit facility (the five-year unsecured credit facility) which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021. The amended facility also retains the $250 million accordion feature, which provides the opportunity to increase the total committed loan amount to $1.75 billion. After giving effect to the amended facility, we have total availability from third-party lenders of approximately $1.6 billion of working capital funding. At September 30, 2016 and 2015, there was $829.8 million and $457.9 million outstanding under our commercial paper program with weighted average interest rates of 0.81% and 0.42%, with average maturities of less than one month. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.

Regulated Operations

We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders. The first facility is the five-year unsecured credit facility described above, which bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. This credit facility serves primarily as a backup liquidity facility for our commercial paper program. At September 30, 2016, there were no borrowings under this facility, but we had $829.8 million of commercial paper outstanding leaving $420.2 million available.

The second facility is a $25 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. This facility was renewed on April 1, 2016. At September 30, 2016, there were no borrowings outstanding under this facility.

The third facility, which was renewed on September 30, 2016, is a $10 million committed revolving credit facility, used primarily to issue letters of credit and bears interest at a LIBOR-based rate plus 1.5 percent. At September 30, 2016, there were no borrowings outstanding under this credit facility; however, letters of credit totaling $5.9 million had been issued under the facility at September 30, 2016, which reduced the amount available by a corresponding amount.

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our five-year unsecured facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2016, our total-debt-to-total-capitalization ratio, as defined, was 50 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH. This facility bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016. We intend to seek renewal of this facility during the first quarter of fiscal 2017. There was $197.0 million outstanding under this facility at September 30, 2016.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility that expires in December 2016 and one committed $15 million 364-day bilateral credit facility that was renewed on September 30, 2016. On October 25, 2016, the uncommitted $25 million 364-day bilateral credit facility was renewed through July 31, 2017. 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 $32.8 million at September 30, 2016.

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. We intend to seek renewal of this facility during the first quarter of fiscal 2017. There were no borrowings outstanding under this facility at September 30, 2016.

Debt Covenants

In addition to the financial covenants described above, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.

Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.

We were in compliance with all of our debt covenants as of September 30, 2016. 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.

Maturities of long-term debt at September 30, 2016 were as follows (in thousands):

2017	$	250,000
2018	—
2019	450,000
2020	—
2021	—
Thereafter	1,760,000
	$	2,460,000

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Shareholders' Equity

12 Months Ended

Sep. 30, 2016

Equity [Abstract]

Shareholders' Equity

Shelf Registration

On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. At September 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.

At-the-Market Equity Sales Program

On March 28, 2016, we entered into an at-the-market (ATM) equity distribution agreement (the Agreement) with Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC in their capacity as agents and/or as principals (Agents). Under the terms of the Agreement, we may issue and sell, through any of the Agents, shares of our common stock, up to an aggregate offering price of $200 million, through the period ended March 28, 2019. We may also sell shares from time to time to an Agent for its own account at a price to be agreed upon at the time of sale. We will pay each Agent a commission of 1.0% of the gross offering proceeds of the shares sold through it as a sales agent. We have no obligation to offer or sell any shares under the Agreement, and may at any time suspend offers and sales under the Agreement. The shares will be issued pursuant to our shelf registration statement filed with the SEC on March 28, 2016. During fiscal 2016, we sold 1,360,756 shares of common stock under the ATM program for $100.0 million and received net proceeds of $98.6 million.

1998 Long-Term Incentive Plan

In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock. 

As of September 30, 2015, we were authorized to grant awards for up to a maximum of 8.7 million shares of common stock under this plan subject to certain adjustment provisions. In February 2016, our shareholders voted to increase the number of authorized LTIP shares by 2.5 million shares and to extend the term of the plan for an additional five years, through September 2021. On March 29, 2016, we filed with the SEC a registration statement on Form S-8 to register an additional 2.5 million shares; we also listed such shares with the New York Stock Exchange. As of September 30, 2016, we were authorized to grant awards for up to a maximum of 11.2 million shares of common stock under this plan subject to certain adjustment provisions.

2014 Equity Offering

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

Share Repurchase Program

On September 28, 2011, the Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a five-year period. The program expired on September 30, 2016 and will not be renewed. We did not repurchase any shares during fiscal 2016, 2015, or 2014 under the program.

Accumulated Other Comprehensive Income (Loss)

We record deferred gains (losses) in accumulated other comprehensive income (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	(263		)	(99,029		)	(11,662		)	(110,954		)
Amounts reclassified from accumulated other comprehensive income	(202		)	347			32,117			32,262
Net current-period other comprehensive income (loss)	(465		)	(98,682		)	20,455			(78,692		)
September 30, 2016	$	4,484		$	(187,524	)	$	(4,982	)	$	(188,022	)

	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	(2,173		)	(71,003		)	(49,211		)	(122,387		)
Amounts reclassified from accumulated other comprehensive income	(540		)	542			25,448			25,450
Net current-period other comprehensive income (loss)	(2,713		)	(70,461		)	(23,763		)	(96,937		)
September 30, 2015	$	4,949		$	(88,842	)	$	(25,437	)	$	(109,330	)

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2016 and 2015. Amounts in parentheses below indicate decreases to net income in the statement of income.

	Fiscal Year Ended September 30, 2016
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	$	318		Operation and maintenance expense
	318			Total before tax
	(116		)	Tax expense
	$	202		Net of tax
Cash flow hedges
Interest rate agreements	$	(546	)	Interest charges
Commodity contracts	(52,651		)	Purchased gas cost
	(53,197		)	Total before tax
	20,733			Tax benefit
	$	(32,464	)	Net of tax
Total reclassifications	$	(32,262	)	Net of tax

	Fiscal Year Ended September 30, 2015
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	$	850		Operation and maintenance expense
	850			Total before tax
	(310		)	Tax expense
	$	540		Net of tax
Cash flow hedges
Interest rate agreements	$	(853	)	Interest charges
Commodity contracts	(41,716		)	Purchased gas cost
	(42,569		)	Total before tax
	16,579			Tax benefit
	$	(25,990	)	Net of tax
Total reclassifications	$	(25,450	)	Net of tax

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Retirement and Post-retirement Employee Benefit Plans

12 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Retirement and Post-Retirement Employee Benefit Plans

Retirement and Post-Retirement Employee Benefit Plans

We have both funded and unfunded noncontributory defined benefit plans that together cover most of our employees. We also maintain post-retirement plans that provide health care benefits to retired employees. Finally, we sponsor a defined contribution plan that cover substantially all employees. These plans are discussed in further detail below.

As a rate regulated entity, we generally recover our pension costs in our rates over a period of up to 15 years. The amounts that have not yet been recognized in net periodic pension cost that have been recorded as regulatory assets are as follows:

	Defined Benefits Plan			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2016
Unrecognized prior service credit	$	(1,509	)	$	—	$	(2,880	)	$	(4,389	)
Unrecognized actuarial (gain) loss	127,028			51,558		(54,298		)	124,288
	$	125,519		$	51,558	$	(57,178	)	$	119,899
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial (gain) loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537

Defined Benefit Plans

Employee Pension Plan

Prior to December 31, 2014, we maintained two defined benefit plans: the Atmos Energy Corporation Pension Account Plan (the Plan) and the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees (the Union Plan) (collectively referred to as the Plans). The assets of the Plans were held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust). In June 2014, active collectively bargained employees of Atmos Energy’s Mississippi Division voted to decertify the union. As a result of this vote, effective January 1, 2015, active participants of the Union Plan became participants in the Plan. Opening account balances were established at the time of transfer equal to the present value of their respective accrued benefits under the Union Plan at December 31, 2014. Additionally, effective January 1, 2015, current retirees in the Union Plan as well as those participants who terminated and were vested in the Union Plan were transferred to the Plan with the same provisions that were in place at the time of their retirement or termination.

The Plan is a cash balance pension plan that was established effective January 1999 and covers most of the employees of Atmos Energy’s regulated operations that were hired before September 30, 2010. The plan was closed to new participants effective October 1, 2010.

Opening account balances were established for participants as of January 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula based on the participant’s age, service and total pay (excluding incentive pay). In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. Participants are fully vested in their account balances after three years of service and may choose to receive their account balances as a lump sum or an annuity.

Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension Protection Act of 2006 (PPA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

During fiscal 2016 and 2015 we contributed $15.0 million and $38.0 million in cash to the Plan to achieve a desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at September 30, 2016, the current funded position of the Plan and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2017. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.

We make investment decisions and evaluate performance of the assets in the Master Trust on a medium-term horizon of at least three to five years. We also consider our current financial status when making recommendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long-term asset investment policy adopted by the Board of Directors.

To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities, interests in commingled pension trust funds, other investment assets and cash and cash equivalents. Investments in equity securities are diversified among the market’s various subsectors in an effort to diversify risk and maximize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.

The following table presents asset allocation information for the Master Trust as of September 30, 2016 and 2015.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2016		2015
Domestic equities	35%-55%	40.5	%	41.3	%
International equities	10%-20%	15.5	%	14.9	%
Fixed income	5%-30%	11.2	%	11.0	%
Company stock	0%-15%	15.1	%	15.2	%
Other assets	0%-20%	17.7	%	17.6	%

At September 30, 2016 and 2015, the Plan held 956,700 and 1,169,700 shares of our common stock which represented 15.1 percent and 15.2 percent of total Plan assets. These shares generated dividend income for the Plan of approximately $1.8 million during fiscal 2016 and 2015.

Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions underlying our employee pension plans annually based upon a September 30 measurement date. The development of our assumptions is fully described in our significant accounting policies in Note 2. The actuarial assumptions used to determine the pension liability for the Plan was determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the Plan was determined as of September 30, 2015, 2014 and 2013. On October 20, 2016, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table.

Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%	7.25	%	7.25	%

The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	516,924		$	485,921
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	508,599		$	493,594
Service cost	16,419			16,231
Interest cost	23,193			21,850
Actuarial loss	41,847			7,420
Benefits paid(1)	(44,578		)	(30,496		)
Benefit obligation at end of year	545,480			508,599
Change in plan assets:
Fair value of plan assets at beginning of year	450,932			434,767
Actual return on plan assets	52,596			8,661
Employer contributions	15,000			38,000
Benefits paid(1)	(44,578		)	(30,496		)
Fair value of plan assets at end of year	473,950			450,932
Reconciliation:
Funded status	(71,530		)	(57,667		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(71,530	)	$	(57,667	)

⁽¹⁾  Includes $12.8 million of one-time payments to eligible deferred vested participants who elected to receive a lump-sum payout of their pension benefits during fiscal 2016.

Net periodic pension cost for the Plan for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,419		$	16,231		$	15,345
Interest cost	23,193			21,850			22,330
Expected return on assets	(27,522		)	(25,744		)	(23,601		)
Amortization of prior service credit	(226		)	(192		)	(136		)
Recognized actuarial loss	10,693			13,322			13,777
Net periodic pension cost	$	22,557		$	25,467		$	27,715

The following table sets forth by level, within the fair value hierarchy, the Plan's assets at fair value as of September 30, 2016 and 2015. As required by authoritative accounting literature, assets are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement. The methods used to determine fair value for the assets held by the Plan are fully described in Note 2. In addition to the assets shown below, the Plan had net accounts receivable of $2.6 million and $2.4 million at September 30, 2016 and 2015 which materially approximates fair value due to the short-term nature of these assets.

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	157,111	$	—	$	—	$	157,111
Money market funds	—		11,522		—		11,522
Registered investment companies	87,396		—		—		87,396
Common/collective trusts	—		105,124		—		105,124
Government securities:
Mortgage-backed securities	—		15,223		—		15,223
U.S. treasuries	4,704		863		—		5,567
Corporate bonds	—		31,929		—		31,929
Limited partnerships	—		57,438		—		57,438
Total investments at fair value	$	249,211	$	222,099	$	—	$	471,310

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	159,304	$	—	$	—	$	159,304
Money market funds	—		11,787		—		11,787
Registered investment companies	81,960		—		—		81,960
Common/collective trusts	—		93,081		—		93,081
Government securities:
Mortgage-backed securities	—		14,359		—		14,359
U.S. treasuries	5,279		805		—		6,084
Corporate bonds	—		28,973		—		28,973
Limited partnerships	—		52,996		—		52,996
Total investments at fair value	$	246,543	$	202,001	$	—	$	448,544

Supplemental Executive Retirement Plans

We have three nonqualified supplemental plans which provide additional pension, disability and death benefits to our officers, division presidents and certain other employees of the Company.

The first plan is referred to as the Supplemental Executive Benefits Plan (SEBP) and covers our officers, division presidents and certain other employees of the Company who were employed on or before August 12, 1998. The SEBP is a defined benefit arrangement which provides a benefit equal to 75 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SEBP.

In August 1998, we adopted the Supplemental Executive Retirement Plan (SERP) (formerly known as the Performance-Based Supplemental Executive Benefits Plan), which covers all officers or division presidents selected to participate in the plan between August 12, 1998 and August 5, 2009, any corporate officer who may be appointed to the Management Committee after August 5, 2009 and any other employees selected by our Board of Directors at its discretion. The SERP is a defined benefit arrangement which provides a benefit equal to 60 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SERP.

Effective August 5, 2009, we adopted a new defined benefit Supplemental Executive Retirement Plan (the 2009 SERP), for corporate officers (other than such officer who is appointed as a member of the Company’s Management Committee), division presidents or any other employees selected at the discretion of the Board. Under the 2009 SERP, a nominal account has been established for each participant, to which the Company contributes at the end of each calendar year an amount equal to ten percent of the total of each participant’s base salary and cash incentive compensation earned during each prior calendar year, beginning December 31, 2009. The benefits vest after three years of service and attainment of age 55 and earn interest credits at the same annual rate as the Company’s Pension Account Plan (currently 4.69%).

On October 2, 2013, due to the retirement of one of our executives, we recognized a settlement loss of $4.5 million associated with our SEBP and made a $16.8 million benefit payment.

Similar to our employee pension plans, we review the estimates and assumptions underlying our supplemental plans annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2015, 2014 and 2013. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	137,616		$	118,835
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	122,393		$	113,219
Service cost	2,371			3,971
Interest cost	5,185			4,943
Actuarial loss	17,229			4,811
Benefits paid	(4,604		)	(4,551		)
Benefit obligation at end of year	142,574			122,393
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,604			4,551
Benefits paid	(4,604		)	(4,551		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(142,574		)	(122,393		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(142,574	)	$	(122,393	)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2016 and 2015, assets held in the rabbi trusts consisted of available-for-sale securities of $41.3 million and $41.7 million, which are included in our fair value disclosures in Note 14.

Net periodic pension cost for the supplemental plans for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016		2015		2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	2,371	$	3,971	$	3,607
Interest cost	5,185		4,943		4,966
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,586		2,343		1,948
Settlements	—		—		4,539
Net periodic pension cost	$	10,142	$	11,257	$	15,060

Estimated Future Benefit Payments

The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years:

	Pension Plan		Supplemental Plans
	(In thousands)
2017	$	31,306	$	36,604
2018	32,047		14,289
2019	33,674		7,181
2020	35,232		4,395
2021	37,279		4,306
2022-2026	202,442		60,658

Postretirement Benefits

We sponsor the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation (the Atmos Retiree Medical Plan). This plan provides medical and prescription drug protection to all qualified participants based on their date of retirement. The Atmos Retiree Medical Plan provides different levels of benefits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however, we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remaining 20 percent of this cost. Effective January 1, 2015 for employees who had not met the participation requirements by September 30, 2009, the contribution rates for the Company will be limited to a three percent cost increase in claims and administrative costs each year, with the participant responsible for the additional costs.

Generally, our funding policy is to contribute annually an amount in accordance with the requirements of ERISA. However, additional voluntary contributions are made annually as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future. We expect to contribute between $10 million and $20 million to our postretirement benefits plan during fiscal 2017.

We maintain a formal investment policy with respect to the assets in our postretirement benefits plan to ensure the assets funding the postretirement benefit plan are appropriately invested to maintain an acceptable level of risk. We also consider our current financial status when making recommendations and decisions regarding the postretirement benefits plan.

We currently invest the assets funding our postretirement benefit plan in diversified investment funds which consist of common stocks, preferred stocks and fixed income securities. The diversified investment funds may invest up to 75 percent of assets in common stocks and convertible securities. The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2016 and 2015.

	Actual Allocation September 30
Security Class	2016		2015
Diversified investment funds	97.2	%	97.5	%
Cash and cash equivalents	2.8	%	2.5	%

Similar to our employee pension and supplemental plans, we review the estimates and assumptions underlying our postretirement benefit plan annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2015, 2014 and 2013. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Expected return on plan assets	4.45	%	4.45	%	4.45	%	4.60	%	4.60	%
Initial trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2022		2021		2021		2020		2020

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	267,179		$	315,118
Service cost	10,823			15,583
Interest cost	12,424			14,385
Plan participants’ contributions	4,289			4,563
Actuarial gain	(1,052		)	(69,962		)
Benefits paid	(14,441		)	(12,508		)
Benefit obligation at end of year	279,222			267,179
Change in plan assets:
Fair value of plan assets at beginning of year	138,009			134,821
Actual return on plan assets	14,528			(8,851		)
Employer contributions	16,592			19,984
Plan participants’ contributions	4,289			4,563
Benefits paid	(14,441		)	(12,508		)
Fair value of plan assets at end of year	158,977			138,009
Reconciliation:
Funded status	(120,245		)	(129,170		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(120,245	)	$	(129,170	)

Net periodic postretirement cost for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	10,823		$	15,583		$	16,784
Interest cost	12,424			14,385			15,951
Expected return on assets	(6,264		)	(6,431		)	(5,167		)
Amortization of transition obligation	82			272			274
Amortization of prior service credit	(1,644		)	(1,644		)	(1,450		)
Recognized actuarial (gain) loss	(2,167		)	—			631
Net periodic postretirement cost	$	13,254		$	22,165		$	27,023

Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations:

	One-Percentage Point Increase		One-Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	4,539	$	(3,596	)
Effect on postretirement benefit obligation	$	42,079	$	(34,531	)

We are currently recovering other postretirement benefits costs through our regulated rates under accrual accounting as prescribed by accounting principles generally accepted in the United States in substantially all of our service areas. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by our Kentucky/Mid-States, West Texas, Mid-Tex and Mississippi Divisions as well as our Kansas jurisdiction and Atmos Pipeline – Texas or have been included in a rate case and not disallowed. Management believes that this accounting method is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.

The following tables set forth by level, within the fair value hierarchy, the Retiree Medical Plan’s assets at fair value as of September 30, 2016 and 2015. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2.

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	4,470	$	—	$	4,470
Registered investment companies	154,507		—		—		154,507
Total investments at fair value	$	154,507	$	4,470	$	—	$	158,977

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,486	$	—	$	3,486
Registered investment companies	134,523		—		—		134,523
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

Estimated Future Benefit Payments

The following benefit payments paid by us, retirees and prescription drug subsidy payments for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years. Company payments for fiscal 2016 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2017	$	15,806	$	3,679	$	—	$	19,485
2018	11,602		3,992		—		15,594
2019	12,165		4,036		—		16,201
2020	13,246		4,756		—		18,002
2021	14,210		5,420		—		19,630
2022-2026	84,642		36,837		—		121,479

Defined Contribution Plan

The Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) covers substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Effective January 1, 2007, employees automatically become participants of the Retirement Savings Plan on the date of employment. Participants may elect a salary reduction up to a maximum of 65 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. New participants are automatically enrolled in the Plan at a salary reduction amount of four percent of eligible compensation, from which they may opt out. We match 100 percent of a participant’s contributions, limited to four percent of the participant’s salary, in our common stock. However, participants have the option to immediately transfer this matching contribution into other funds held within the plan. Participants are eligible to receive matching contributions after completing one year of service. Participants are also permitted to take out loans against their accounts subject to certain restrictions. Employees hired on or after October 1, 2010 participate in the enhanced plan in which participants receive a fixed annual contribution of four percent of eligible earnings to their Retirement Savings Plan account. Participants will continue to be eligible for company matching contributions of up to four percent of their eligible earnings and will be fully vested in the fixed annual contribution after three years of service.

Prior to December 31, 2015, we also maintained the Atmos Energy Holdings, LLC 401(k) Profit-Sharing Plan (the AEH 401(k) Profit-Sharing Plan), which covered substantially all AEH employees. On November 4, 2015, the Atmos Energy Corporation Board of Directors voted to approve the merger of the assets and liabilities of the AEH 401(k) Profit-Sharing Plan with the Retirement Savings Plan, effective January 1, 2016. On December 31, 2015, the AEH 401(k) Profit Sharing Plan was merged into the Retirement Savings Plan and all assets and loans of active and inactive participants were transferred to the Retirement Savings Plan.

Prior to December 31, 2014, we maintained the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401(k) Plan). In June 2014, active collectively bargained employees of Atmos Energy’s Mississippi Division voted to decertify the Union. As a result, effective July 19, 2014, active participants of the Union 401(k) Plan were eligible to participate in the Retirement Savings Plan. Effective January 1, 2015, all remaining participants became participants in the Retirement Savings Plan and the Union 401(k) Plan was terminated.

Matching contributions to the Retirement Savings Plan (and prior to December 31, 2014, the Union 401(k) Plan) are expensed as incurred and amounted to $12.6 million, $11.5 million and $10.9 millionfor fiscal years2016,2015and2014. The Board of Directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code and applicable Treasury regulations. No discretionary contributions were made for fiscal years 2016, 2015 or 2014. At September 30, 2016 and 2015, the Retirement Savings Plan held 4.2 percent and 4.3 percent of our outstanding common stock. Discretionary contributions to the AEH 401(k) Profit-Sharing Plan were expensed as incurred and amounted to $0.3 million, $1.1 million and $1.4 million for fiscal years 2016, 2015 and 2014.

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Stock and Other Compensation Plans

12 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock and Other Compensation Plans

Stock and Other Compensation Plans

Stock-Based Compensation Plans

Total stock-based compensation cost was $24.6 million, $27.5 million and $25.5 million for the fiscal years ended September 30, 2016, 2015 and 2014. Of this amount, $9.8 million, $11.5 million and $10.8 million was capitalized. Tax benefits related to stock-based compensation were $5.0 million, $4.7 million and $3.1 million for the fiscal years ended September 30, 2016, 2015 and 2014.

1998 Long-Term Incentive Plan

In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.

As of September 30, 2016, we were authorized to grant awards for up to a maximum of 11.2 million shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2016, non-qualified stock options, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units had been issued under this plan, and 2.4 million shares were available for future issuance.

Restricted Stock Unit Award Grants

As noted above, the LTIP provides for discretionary awards of restricted stock units to help attract, retain and reward employees of Atmos Energy and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The fair value of the awards granted is based on the market price of our stock at the date of grant. We estimate forfeitures using our historical forfeiture rate. The associated expense is recognized ratably over the vesting period. We use authorized and unissued shares to meet share requirements for the vesting of restricted stock units.

Employees who are granted time-lapse restricted stock units under our LTIP have a nonforfeitable right to dividend equivalents that are paid at the same rate and at the same time at which they are paid on shares of stock without restrictions. Time-lapse restricted stock units contain only a service condition that the employee recipients render continuous services to the Company for a period of three years from the date of grant, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions). There are no performance conditions required to be met for employees to be vested in time-lapse restricted stock units.

Employees who are granted performance-based restricted stock units under our LTIP have a forfeitable right to dividend equivalents that accrue at the same rate at which they are paid on shares of stock without restrictions. Dividend equivalents on the performance-based restricted stock units are paid either in cash or in the form of shares upon the vesting of the award. Performance-based restricted stock units contain a service condition that the employee recipients render continuous services to the Company for a period of three years from the beginning of the applicable three-year performance period, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions) and a performance condition based on a cumulative earnings per share target amount.

The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2016, 2015 and 2014:

	2016				2015				2014
	Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value
Nonvested at beginning of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20
Granted	357,323		65.98		444,543		50.50		464,438		45.05
Vested	(448,136	)	45.88		(551,688	)	39.28		(524,532	)	32.67
Forfeited	(4,860	)	53.52		(3,388	)	48.55		(4,113	)	39.00
Nonvested at end of year	782,431		$	57.66	878,104		$	48.24	988,637		$	42.22

As of September 30, 2016, there was $11.4 million of total unrecognized compensation cost related to nonvested time-lapse restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2016, 2015 and 2014 was $20.6 million, $21.7 million and $17.1 million.

Other Plans

Direct Stock Purchase Plan

We maintain a Direct Stock Purchase Plan, open to all investors, which allows participants to have all or part of their cash dividends paid quarterly in additional shares of our common stock. The minimum initial investment required to join the plan is $1,250. Direct Stock Purchase Plan participants may purchase additional shares of our common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000.

Outside Directors Stock-For-Fee Plan

In November 1994, the Board of Directors adopted the Outside Directors Stock-for-Fee Plan, which was approved by our shareholders in February 1995. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash. This plan was terminated by the Board of Directors, effective September 1, 2014, when the LTIP was amended to incorporate substantially all of its provisions.

Equity Incentive and Deferred Compensation Plan for Non-Employee Directors

In November 1998, the Board of Directors adopted the Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, which was approved by our shareholders in February 1999. This plan amended the Atmos Energy Corporation Deferred Compensation Plan for Outside Directors adopted by the Company in May 1990 and replaced the pension payable under our Retirement Plan for Non-Employee Directors. The plan provides non-employee directors of Atmos Energy with the opportunity to defer receipt, until retirement, of compensation for services rendered to the Company and invest deferred compensation into either a cash account or a stock account.

Other Discretionary Compensation Plans

We have an annual incentive program covering substantially all employees to give each employee an opportunity to share in our financial success based on the achievement of key performance measures considered critical to achieving business objectives for a given year with minimum and maximum thresholds. The Company must meet the minimum threshold for the plan to be funded and distributed to employees. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded. During the last several fiscal years, we have used earnings per share as our sole performance measure.

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Details of Selected Consolidated Balance Sheet Captions

12 Months Ended

Sep. 30, 2016

Details Of Selected Consolidated Balance Sheet Captions Disclosure [Abstract]

Details of Selected Consolidated Balance Sheet Captions

Details of Selected Consolidated Balance Sheet Captions

The following tables provide additional information regarding the composition of certain of our balance sheet captions.

Accounts receivable

Accounts receivable was comprised of the following at September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Billed accounts receivable	$	206,248		$	204,585
Unbilled revenue	67,396			65,008
Other accounts receivable	39,730			40,850
Total accounts receivable	313,374			310,443
Less: allowance for doubtful accounts	(13,367		)	(15,283		)
Net accounts receivable	$	300,007		$	295,160

Other current assets

Other current assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Assets from risk management activities	$	9,804	$	9,232
Deferred gas costs	45,184		9,715
Taxes receivable	5,456		4,479
Prepaid expenses	23,053		23,055
Materials and supplies	5,825		12,587
Other	11,507		6,822
Total	$	100,829	$	65,890

Property, plant and equipment

Property, plant and equipment was comprised of the following as of September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Production plant	$	66		$	131
Storage plant	353,523			286,011
Transmission plant	2,232,927			1,844,117
Distribution plant	6,598,990			6,019,001
General plant	761,057			769,311
Intangible plant	40,515			41,131
	9,987,078			8,959,702
Construction in progress	184,062			280,398
	10,171,140			9,240,100
Less: accumulated depreciation and amortization	(1,890,629		)	(1,809,520		)
Net property, plant and equipment(1)	$	8,280,511		$	7,430,580

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

Goodwill

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2016:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702
Deferred tax adjustments on prior acquisitions(1)	665		40		—		705
Balance as of September 30, 2016	$	576,114	$	132,582	$	34,711	$	743,407

⁽¹⁾  We annually adjust certain deferred taxes recorded in connection with acquisitions completed in fiscal 2001 and fiscal 2004, which resulted in an increase to goodwill and net deferred tax liabilities of $0.7 million for fiscal 2016.

Deferred charges and other assets

Deferred charges and other assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Marketable securities	$	72,701	$	74,200
Regulatory assets	214,890		182,573
Assets from risk management activities	1,822		368
Other	15,872		18,343
Total	$	305,285	$	275,484

Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Trade accounts payable	$	114,533	$	78,534
Accrued gas payable	108,526		119,825
Accrued liabilities	36,375		40,583
Total	$	259,434	$	238,942

Other current liabilities

Other current liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer credit balances and deposits	$	81,890	$	100,232
Accrued employee costs	47,058		47,602
Deferred gas costs	20,180		28,100
Accrued interest	34,863		34,914
Liabilities from risk management activities	56,771		9,568
Taxes payable	104,457		93,674
Pension and postretirement obligations	36,606		21,857
Current deferred tax liability	—		55,918
Regulatory cost of removal accrual	52,610		56,123
Other	14,601		9,966
Total	$	449,036	$	457,954

Deferred credits and other liabilities

Deferred credits and other liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer advances for construction	$	9,850	$	9,316
Regulatory liabilities	4,152		3,693
Asset retirement obligation	13,404		9,063
Liabilities from risk management activities	184,048		110,539
Other	34,236		29,085
Total	$	245,690	$	161,696

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Leases

12 Months Ended

Sep. 30, 2016

Leases [Abstract]

Leases

Leases

We have entered into operating leases for office and warehouse space, vehicles and heavy equipment used in our operations. The remaining lease terms range from one to 18 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases.

The related future minimum lease payments at September 30, 2016 were as follows:

	Operating Leases
	(In thousands)
2017	$	17,073
2018	16,824
2019	15,450
2020	14,479
2021	14,335
Thereafter	47,714
Total minimum lease payments	$	125,875

Consolidated lease and rental expense amounted to $32.6 million, $32.5 million and $31.7 million for fiscal 2016, 2015 and 2014.

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Commitments and Contingencies

12 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Litigation

We are a party to various litigation that has arisen in the ordinary course of our business. While the results of such litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental Matters

We are a party to environmental matters and claims that have arisen in the ordinary course of our business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance.

Purchase Commitments

Our regulated distribution divisions 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 trading hubs. At September 30, 2016, we were committed to purchase 28.5 Bcf within one year, 4.2 Bcf within two to three years and 0.6 Bcf beyond three years under indexed contracts. Purchases under these contracts totaled $85.3 million, $113.3 million and $140.9 million for 2016, 2015, 2014.

Our nonregulated segment has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2016, we were committed to purchase 93.5 Bcf within one year, 9.1 Bcf within two to three years and 0.2 Bcf after three years under indexed contracts. We are committed to purchase 11.9 Bcf within one year and 1.3 Bcf within one to three years under fixed price contracts with prices ranging from $0.25 to $3.16 per Mcf. Purchases under these contracts totaled $763.2 million , $1,141.3 million and $1,687.5 million for 2016, 2015 and 2014.

In addition, our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts as of September 30, 2016 are as follows (in thousands):

2017	$	9,065
2018	2,336
2019	424
2020	400
2021	327
Thereafter	678
	$	13,230

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Income Taxes

12 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The components of income tax expense from continuing operations for 2016, 2015 and 2014 were as follows:

	2016			2015			2014
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	6,822			7,251			5,527
Deferred
Federal	181,790			175,897			169,106
State	11,766			12,548			12,375
Investment tax credits	(5		)	(6		)	(6		)
	$	200,373		$	195,690		$	187,002

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2016, 2015 and 2014 are set forth below:

	2016			2015			2014
	(In thousands)
Tax at statutory rate of 35%	$	192,667		$	178,768		$	166,887
Common stock dividends deductible for tax reporting	(2,570		)	(2,413		)	(2,307		)
State taxes (net of federal benefit)	11,504			12,869			11,636
Change in valuation allowance	1,324			4,998			6,969
Other, net	(2,552		)	1,468			3,817
Income tax expense	$	200,373		$	195,690		$	187,002

Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that gave rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2016 and 2015 are presented below:

	2016			2015
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	122,682		$	121,619
Interest rate agreements	107,782			51,067
Net operating loss carryforwards	514,391			313,224
Charitable and other credit carryforwards	22,273			22,281
Other	23,648			36,695
Total deferred tax assets	790,776			544,886
Valuation allowance	(10,481		)	(10,872		)
Net deferred tax assets	780,295			534,014
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(2,259,278		)	(1,890,886		)
Pension funding	(30,652		)	(35,247		)
Gas cost adjustments	(54,725		)	(43,634		)
Other	(38,696		)	(31,480		)
Total deferred tax liabilities	(2,383,351		)	(2,001,247		)
Net deferred tax liabilities	$	(1,603,056	)	$	(1,467,233	)
Deferred credits for rate regulated entities	$	861		$	412

At September 30, 2016, we had $494.0 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards which do not expire. In addition, the Company has $11.0 million in charitable contribution carryforwards to offset taxable income. The Company’s charitable contribution carryforwards expire in 2017 - 2021.

For state taxable income, the Company has $20.4 million of state net operating loss carryforwards (net of $11.0 million of federal effects) and $1.1 million of state tax credits carryforwards (net of federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire between 2017 and 2031.

We believe it is more likely than not that the benefit from certain charitable contribution carryforwards, state net operating loss carryforwards and state credit carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the carryforwards, a valuation allowance of $1.1 million and $5.0 million was established for the years ended September 30, 2016 and 2015. In addition, $1.4 million of deferred tax assets expired for which a valuation allowance had previously been recorded and $0.2 million of deferred tax assets expired for which a valuation allowance had not been previously recorded during the year ended September 30, 2016.

At September 30, 2016, we had recorded liabilities associated with unrecognized tax benefits totaling $20.3 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2016			2015
	(In thousands)
Unrecognized tax benefits - beginning balance	$	17,069		$	12,629
Increase (decrease) resulting from prior period tax positions	(290		)	1,009
Increase resulting from current period tax positions	3,519			3,431
Unrecognized tax benefits - ending balance	20,298			17,069
Less: deferred federal and state income tax benefits	(7,104		)	(5,974		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	13,194		$	11,095

The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties in operating expense. During the years ended September 30, 2016 and 2015, the Company recognized approximately $2.5 million and $0.5 million in interest and penalties. The Company had approximately $3.3 million and $0.8 million for the payment of interest and penalties accrued at September 30, 2016 and 2015.

We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2007 and concluded substantially all Texas income tax matters through fiscal year 2010.

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Financial Instruments

12 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Instruments

Financial Instruments

We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. Currently, we utilize financial instruments in our regulated distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated pipeline segment.

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

As discussed in Note 2, we report our financial instruments as risk management assets and liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. The following table shows the fair values of our risk management assets and liabilities by segment at September 30, 2016 and 2015:

	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2016
Assets from risk management activities, current(1)	$	3,029		$	6,775	$	9,804
Assets from risk management activities, noncurrent	1,822			—		1,822
Liabilities from risk management activities, current(1)	(56,771		)	—		(56,771		)
Liabilities from risk management activities, noncurrent(1)	(184,048		)	—		(184,048		)
Net assets (liabilities)	$	(235,968	)	$	6,775	$	(229,193	)
September 30, 2015
Assets from risk management activities, current(2)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(2)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(2)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)

⁽¹⁾  Includes $25.7 million of cash held on deposit to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. Also includes $24.7 million of cash held on deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

⁽²⁾  Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

Regulated Commodity Risk Management Activities

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

Our regulated distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2015-2016 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or approximately 23.0 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $3.14 per Mcf. We have not designated these financial instruments as hedges.

Nonregulated Commodity Risk Management Activities

In our nonregulated operations, we buy, sell and deliver natural gas at competitive prices by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.

As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Future contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. Specifically, these operations use financial instruments in the following ways:

•Gas delivery and related services - We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, 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 63 months.

•Transportation and storage services - Our nonregulated operations use storage and basis swaps, futures and various over-the-counter and exchange-traded options 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.

Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. A risk committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.

Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations in order to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Our operations can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on September 30, 2016, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 Bcf.

Interest Rate Risk Management Activities

We currently manage interest rate risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the then anticipated issuance of $500 million senior notes in October 2014. These notes were issued as planned in October 2014 and we settled swaps with the receipt of $13.4 million. Because the swaps were effective, the realized gain was recorded as a component of accumulated other comprehensive income and is being recognized as a component of interest expense over the 30-year life of the senior notes. In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with $210 million of the anticipated issuance of $250 million unsecured senior notes in fiscal 2017. Additionally, in fiscal 2014 and 2015, we entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with $450 million of the anticipated issuance of $450 million unsecured senior notes in fiscal 2019. We designated all of these swaps as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps will be recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred, will be reported as a component of interest expense.

Prior to fiscal 2012, we entered into several interest rate agreements to fix the Treasury yield component of the interest cost of financing for various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these interest rate agreements were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled interest rate agreements extend through fiscal 2045.

Quantitative Disclosures Related to Financial Instruments

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

As of September 30, 2016, 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 September 30, 2016, 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	—	(19,395	)
	Cash Flow	—	39,278
	Not designated	18,595	71,147
		18,595	91,030

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 September 30, 2016 and 2015. The gross amounts of recognized assets and liabilities are netted within our 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)
September 30, 2016
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	6,612		$	(21,903	)
Interest rate contracts	Other current assets / Other current liabilities	—		(68,481		)	—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			2,178			(3,779		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(198,008		)	—			—
Total		—		(266,489		)	8,790			(25,682		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	3,029		—			18,157			(18,812		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,822		—			12,343			(12,701		)
Total		4,851		—			30,500			(31,513		)
Gross Financial Instruments		4,851		(266,489		)	39,290			(57,195		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(39,290		)	39,290
Net Financial Instruments		4,851		(266,489		)	—			(17,905		)
Cash collateral		—		25,670			6,775			17,905
Net Assets/Liabilities from Risk Management Activities		$	4,851	$	(240,819	)	$	6,775		$	—

		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 years ended September 30, 2016, 2015 and 2014, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $21.6 million, $0.2 million and $1.9 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 consolidated income statement for the years ended September 30, 2016, 2015 and 2014 is presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Commodity contracts	$	3,516		$	10,311		$	(792	)
Fair value adjustment for natural gas inventory designated as the hedged item	18,079			(9,768		)	2,486
Total decrease in purchased gas cost	$	21,595		$	543		$	1,694
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(1,390	)	$	811		$	(919	)
Timing ineffectiveness	22,985			(268		)	2,613
	$	21,595		$	543		$	1,694

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 consolidated income statements for the years ended September 30, 2016, 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.

	Fiscal Year Ended September 30, 2016
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(52,651	)	$	(52,651	)
Loss arising from ineffective portion of commodity contracts	—			(19		)	(19		)
Total impact on purchased gas cost	—			(52,670		)	(52,670		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(546		)	—			(546		)
Total impact from cash flow hedges	$	(546	)	$	(52,670	)	$	(53,216	)

	Fiscal Year Ended September 30, 2015
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(41,716	)	$	(41,716	)
Loss arising from ineffective portion of commodity contracts	—			(325		)	(325		)
Total impact on purchased gas cost	—			(42,041		)	(42,041		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(853		)	—			(853		)
Total impact from cash flow hedges	$	(853	)	$	(42,041	)	$	(42,894	)

	Fiscal Year Ended September 30, 2014
	Regulated Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	8,365	$	8,365
Gain arising from ineffective portion of commodity contracts	—			198		198
Total impact on purchased gas cost	—			8,563		8,563
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(4,230		)	—		(4,230		)
Total impact from cash flow hedges	$	(4,230	)	$	8,563	$	4,333

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 years ended September 30, 2016 and 2015. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.

	Fiscal Year Ended September 30
	2016			2015
	(In thousands)
Decrease in fair value:
Interest rate agreements	$	(99,029	)	$	(71,003	)
Forward commodity contracts	(11,662		)	(49,211		)
Recognition of losses in earnings due to settlements:
Interest rate agreements	347			542
Forward commodity contracts	32,117			25,448
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(78,227	)	$	(94,224	)

⁽¹⁾  Utilizing an income tax rate ranging from approximately 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, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of September 30, 2016. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2017	$	(447	)	$	(3,983	)	$	(4,430	)
2018	(649		)	(561		)	(1,210		)
2019	(673		)	(414		)	(1,087		)
2020	(698		)	(26		)	(724		)
2021	(698		)	2			(696		)
Thereafter	(15,139		)	—			(15,139		)
Total(1)	$	(18,304	)	$	(4,982	)	$	(23,286	)

⁽¹⁾  Utilizing an income tax rate ranging from approximately 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 consolidated income statements for the years ended September 30, 2016, 2015 and 2014 was an increase (decrease) in purchased gas cost of $(15.5) million, $15.5 million and $(5.0) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

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.

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Fair Value Measurements

12 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. The fair value of these assets is presented in Note 7.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. 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 September 30, 2016 and 2015. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(2)			September 30, 2016
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	4,851	$	—	$	—		$	4,851
Nonregulated segment	—		39,290		—		(32,515		)	6,775
Total financial instruments	—		44,141		—		(32,515		)	11,626
Hedged portion of gas stored underground	52,578		—		—		—			52,578
Available-for-sale securities
Money market funds	—		2,630		—		—			2,630
Registered investment companies	38,677		—		—		—			38,677
Bonds	—		31,394		—		—			31,394
Total available-for-sale securities	38,677		34,024		—		—			72,701
Total assets	$	91,255	$	78,165	$	—	$	(32,515	)	$	136,905
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	266,489	$	—	$	(25,670	)	$	240,819
Nonregulated segment	—		57,195		—		(57,195		)	—
Total liabilities	$	—	$	323,684	$	—	$	(82,865	)	$	240,819

	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 September 30, 2016, we had $25.7 million of cash held in margin accounts to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. As of September 30, 2016 we also had $24.7 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $6.8 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 nonregulated financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting agreements 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 September 30, 2016
Domestic equity mutual funds	$	26,692	$	6,419	$	(590	)	$	32,521
Foreign equity mutual funds	4,954		1,202		—			6,156
Bonds	31,296		108		(10		)	31,394
Money market funds	2,630		—		—			2,630
	$	65,572	$	7,729	$	(600	)	$	72,701
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 September 30, 2016 and 2015, our available-for-sale securities included $41.3 million and $41.7 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 7. At September 30, 2016 we maintained investments in bonds that have contractual maturity dates ranging from October 2016 through May 2020.

Other Fair Value Measures

In addition to the financial instruments above, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. The nonfinancial assets and liabilities include asset retirement obligations and pension and post-retirement plan assets. We record cash and cash equivalents, accounts receivable, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities.

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 September 30, 2016:

	September 30, 2016
	(In thousands)
Carrying Amount	$	2,460,000
Fair Value	$	2,844,990

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Subsequent Events

12 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Event

On October 29, 2016, AEH entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. to sell all of the equity interests of AEM for $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. We expect this transaction to close during the second quarter of fiscal 2017.

The following table summarizes the approximate value of the assets and liabilities that are part of the disposal group as of September 30, 2016:

	September 30, 2016
	(In thousands)
Assets:
Net property, plant and equipment	$	13,000
Accounts receivable	94,000
Gas stored underground	56,000
Other current assets	13,000
Goodwill	15,000
Deferred charges and other assets	300
Total assets included in disposal group	$	191,300
Liabilities:
Accounts payable and accrued liabilities	$	71,000
Other current liabilities	8,000
Deferred credits and other	200
Total liabilities included in disposal group	$	79,200

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Concentration of Credit Risk

12 Months Ended

Sep. 30, 2016

Risks and Uncertainties [Abstract]

Concentration of Credit Risk

Concentration of Credit Risk

Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the regulated distribution segment is mitigated by the large number of individual customers and diversity in our customer base. The credit risk for our other segments is not significant.

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Selected Quarterly Financial Data

12 Months Ended

Sep. 30, 2016

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below. The sum of net income per share by quarter may not equal the net income per share for the fiscal year due to variations in the weighted average shares outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section herein.

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2016:
Operating revenues
Regulated distribution	$	638,602		$	849,685		$	414,226		$	389,353
Regulated pipeline	94,677			95,703			109,249			109,204
Nonregulated	272,524			287,395			214,555			291,889
Intersegment eliminations	(99,582		)	(100,490		)	(105,114		)	(111,927		)
	906,221			1,132,293			632,916			678,519
Gross profit	443,763			517,811			407,311			376,011
Operating income	196,205			250,016			137,164			84,633
Net income	102,861			141,810			71,193			34,240
Net income per share — basic	$	1.00		$	1.38		$	0.69		$	0.33
Net income per share — diluted	$	1.00		$	1.38		$	0.69		$	0.33

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2015:
Operating revenues
Regulated distribution	$	846,772		$	1,130,613		$	416,794		$	369,656
Regulated pipeline	83,567			91,730			97,008			97,807
Nonregulated	462,288			438,322			278,769			292,830
Intersegment eliminations	(133,862		)	(120,597		)	(106,170		)	(103,391		)
	1,258,765			1,540,068			686,401			656,902
Gross profit	423,285			520,738			381,673			354,321
Operating income	187,725			250,210			117,607			75,853
Net income	97,595			137,684			56,281			23,515
Net income per share — basic	$	0.96		$	1.35		$	0.55		$	0.23
Net income per share — diluted	$	0.96		$	1.35		$	0.55		$	0.23

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Sep. 30, 2016

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2016

			Additions
	Balance at beginning of period		Charged to cost & expenses		Charged to other accounts		Deductions			Balance at end of period
			(In thousands)
2016
Allowance for doubtful accounts	$	15,283	$	10,397	$	—	$	12,313	(1)	$	13,367
2015
Allowance for doubtful accounts	$	23,992	$	15,082	$	—	$	23,791	(1)	$	15,283
2014
Allowance for doubtful accounts	$	20,624	$	19,491	$	—	$	16,123	(1)	$	23,992

⁽¹⁾  Uncollectible accounts written off.

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Summary of Significant Accounting Policies (Policy)

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Principles of consolidation

Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.

Basis of comparison

Basis of comparison — As described under Recent Accounting Pronouncements below, we reclassified debt issuance costs from deferred charges and other assets to long-term debt. Additionally, we recorded immaterial corrections to the presentation of certain activities on our Consolidated Statement of Cash Flows for the years ended September 30, 2015 and 2014.

Use of estimates

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.

Regulation

Regulation — Our regulated distribution and regulated pipeline operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. 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 that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations.

We record regulatory assets as a component of other current assets and deferred charges and other assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded either on the face of the balance sheet or as a component of current liabilities, deferred income taxes or deferred credits and other liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

Revenue recognition

Revenue recognition — Sales of natural gas to our regulated distribution customers are billed on a monthly basis; however, the billing cycle periods for certain classes of customers do not necessarily coincide with accounting periods used for financial reporting purposes. We follow the revenue accrual method of accounting for regulated distribution segment revenues whereby revenues applicable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense.

On occasion, we are permitted to implement new rates that have not been formally approved by our state regulatory commissions, which are subject to refund. As permitted by accounting principles generally accepted in the United States, we recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.

Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no gross profit generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our regulated distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our balance sheet.

Operating revenues for our regulated pipeline and nonregulated segments are recognized in the period in which actual volumes are transported and storage services are provided.

Operating revenues for our nonregulated segment and the associated carrying value of natural gas inventory (inclusive of storage costs) are recognized when we sell the gas and physically deliver it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial instruments used in our nonregulated activities.

Cash and cash equivalents

Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts

Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our collection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Gas stored underground

Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our regulated distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for substantially all of our regulated operations. Our nonregulated segment utilizes the average cost method; however, most of this inventory is hedged and is therefore reported at fair value at the end of each month. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.

Property, plant and equipment

Regulated property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes when the completed projects are placed in service. Interest expense of $2.8 million, $2.3 million and $1.5 million was capitalized in 2016, 2015 and 2014.

Major renewals, including replacement pipe, and betterments that are recoverable under our regulatory rate base are capitalized while the costs of maintenance and repairs that are not recoverable through rates are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.

Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.2 percent for the fiscal year ended September 30, 2016, and 3.3 percent for each of the fiscal years ended September 30, 2015 and 2014.

Nonregulated property, plant and equipment — Nonregulated property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from three to 43 years.

Asset retirement obligations

Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense.

As of September 30, 2016 and 2015, we had asset retirement obligations of $13.4 million and $11.1 million. Additionally, we had $8.1 million and $4.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.

We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.

Impairment of long-lived assets

Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

Goodwill

Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

Marketable securities

Marketable securities — As of September 30, 2016 and 2015, all of our marketable securities were classified as available for sale. In accordance with the authoritative accounting standards, 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 an individual investment by investment 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 investment is written down to its estimated fair value.

Financial instruments and hedging activities

Financial instruments and hedging activities — We use financial instruments to mitigate commodity price risk in our regulated distribution and nonregulated segments and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses and are discussed in Note 13.

We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ultimately recorded in the income statement. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.

The timing of when changes in fair value of our financial instruments are recorded in the income statement depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the income statement as they occur.

Financial Instruments Associated with Commodity Price Risk

In our regulated distribution segment, the costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our regulated distribution segment as a result of the use of financial instruments.

In our nonregulated segment, we have designated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge. This inventory is marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. The financial instruments associated with this natural gas inventory have been designated as fair-value hedges and are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges. For the fiscal years ended September 30, 2016, 2015 and 2014, we included unrealized gains (losses) on open contracts of $1.3 million, $(2.4) million and $9.6 million as a component of nonregulated purchased gas cost.

Additionally, we have elected to treat fixed-price forward contracts used in our nonregulated segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries are recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts have been designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments are recorded as a component of accumulated other comprehensive income, and are recognized in earnings as a component of purchased gas cost when the hedged volumes are sold.

Gains and losses from hedge ineffectiveness are recognized in the income statement. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges 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 is referred to as timing ineffectiveness. Hedge ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost.

Our nonregulated segment also utilizes master netting agreements with significant counterparties that allow us to offset gains and losses arising from financial instruments that may be settled in cash with gains and losses arising from financial instruments that may be settled with the physical commodity. Assets and liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under master netting agreements used to offset gains and losses arising from financial instruments. As of September 30, 2016 and 2015, the Company netted $24.7 million and $43.5 million of cash held in margin accounts into its current and noncurrent risk management assets and liabilities.

Financial Instruments Associated with Interest Rate Risk

We manage interest rate risk, primarily when we plan to issue new long-term debt or to refinance existing long-term debt. We currently manage this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest expense. As of September 30, 2016, the Company netted $25.7 million of cash held in margin accounts into its current and noncurrent risk management liabilities. As of September 30, 2015 no cash was required to be held in margin accounts.

Fair Value Measurements

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 primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.

Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.

Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.

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) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:

Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices), as permitted under current accounting standards. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed.

Our Level 1 measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.

Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as common collective trusts, corporate bonds and investments in limited partnerships.

Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.

Pension and other postretirement plans

Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. Our measurement date is September 30. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds.

The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors when making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.

The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this calculation will delay the impact of current market fluctuations on the pension expense for the period.

We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.

We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon the annual review of our participant census information as of the measurement date.

Income taxes

Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.

Contingencies

Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and reasonably estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.

Earnings per share

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

Segment Reporting Policy

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 aggregated and 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. We evaluate performance based on net income or loss of the respective operating units. Interest expense is allocated pro rata to each segment based upon our net investment in each segment. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.

Tax Collections

Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.

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Nature of Business (Table)

12 Months Ended

Sep. 30, 2016

Schedule of Divisions And Service Areas Table [Abstract]

Schedule of divisions and service areas

Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated distribution divisions in the service areas described below:

Division	Service Area
Atmos Energy Colorado-Kansas Division	Colorado, Kansas
Atmos Energy Kentucky/Mid-States Division	Kentucky, Tennessee, Virginia(1)
Atmos Energy Louisiana Division	Louisiana
Atmos Energy Mid-Tex Division	Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division	Mississippi
Atmos Energy West Texas Division	West Texas

⁽¹⁾  Denotes location where we have more limited service areas.

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Summary of Significant Accounting Policies (Table)

12 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Schedule Of Regulatory Assets And Liabilities

Significant regulatory assets and liabilities as of September 30, 2016 and 2015 included the following:

	September 30
	2016		2015
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	132,348	$	121,183
Infrastructure Mechanisms(2)	42,719		32,813
Deferred gas costs	45,184		9,715
Recoverable loss on reacquired debt	13,761		16,319
Deferred pipeline record collection costs	7,336		3,118
APT annual adjustment mechanism	7,171		1,002
Rate case costs	1,539		1,533
Other	13,565		6,656
	$	263,623	$	192,339
Regulatory liabilities:
Regulatory cost of removal obligation	$	476,891	$	483,676
Deferred gas costs	20,180		28,100
Asset retirement obligation	13,404		9,063
Other	4,250		3,693
	$	514,725	$	524,532

^[1],[2]

[1] Includes $12.4 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 eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

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Segment Information (Table)

12 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Schedule of segment reporting income statement, by segment

Summarized income statements and capital expenditures by segment are shown in the following tables.

	Year Ended September 30, 2016
	Regulated Distribution		Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,284,185	$	104,007		$	961,757	$	—		$	3,349,949
Intersegment revenues	7,681		304,826			104,606		(417,113		)	—
	2,291,866		408,833			1,066,363		(417,113		)	3,349,949
Purchased gas cost	1,019,061		—			1,002,573		(416,581		)	1,605,053
Gross profit	1,272,805		408,833			63,790		(532		)	1,744,896
Operating expenses
Operation and maintenance	404,115		129,525			27,658		(532		)	560,766
Depreciation and amortization	233,036		55,576			4,484		—			293,096
Taxes, other than income	196,070		24,298			2,648		—			223,016
Total operating expenses	833,221		209,399			34,790		(532		)	1,076,878
Operating income	439,584		199,434			29,000		—			668,018
Miscellaneous income (expense)	455		(1,683		)	1,443		(1,808		)	(1,593		)
Interest charges	79,404		36,574			1,778		(1,808		)	115,948
Income before income taxes	360,635		161,177			28,665		—			550,477
Income tax expense	128,265		59,488			12,620		—			200,373
Net income	$	232,370	$	101,689		$	16,045	$	—		$	350,104
Capital expenditures	$	740,039	$	346,400		$	511	$	—		$	1,086,950

	Year Ended September 30, 2015
	Regulated Distribution			Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,757,585		$	97,662		$	1,286,889		$	—		$	4,142,136
Intersegment revenues	6,250			272,450			185,320			(464,020		)	—
	2,763,835			370,112			1,472,209			(464,020		)	4,142,136
Purchased gas cost	1,526,258			—			1,399,349			(463,488		)	2,462,119
Gross profit	1,237,577			370,112			72,860			(532		)	1,680,017
Operating expenses
Operation and maintenance	388,486			118,866			35,048			(532		)	541,868
Depreciation and amortization	223,048			47,236			4,512			—			274,796
Taxes, other than income	205,894			22,743			3,321			—			231,958
Total operating expenses	817,428			188,845			42,881			(532		)	1,048,622
Operating income	420,149			181,267			29,979			—			631,395
Miscellaneous expense	(377		)	(1,243		)	(760		)	(2,009		)	(4,389		)
Interest charges	84,132			33,151			967			(2,009		)	116,241
Income before income taxes	335,640			146,873			28,252			—			510,765
Income tax expense	130,827			52,211			12,652			—			195,690
Net income	$	204,813		$	94,662		$	15,600		$	—		$	315,075
Capital expenditures	$	670,575		$	291,603		$	1,443		$	—		$	963,621

	Year Ended September 30, 2014
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	3,056,212		$	92,166		$	1,792,538	$	—		$	4,940,916
Intersegment revenues	5,334			226,293			274,754		(506,381		)	—
	3,061,546			318,459			2,067,292		(506,381		)	4,940,916
Purchased gas cost	1,885,031			—			1,979,337		(505,878		)	3,358,490
Gross profit	1,176,515			318,459			87,955		(503		)	1,582,426
Operating expenses
Operation and maintenance	387,228			91,466			26,963		(503		)	505,154
Depreciation and amortization	208,376			41,031			4,580		—			253,987
Taxes, other than income	196,343			13,143			2,450		—			211,936
Total operating expenses	791,947			145,640			33,993		(503		)	971,077
Operating income	384,568			172,819			53,962		—			611,349
Miscellaneous income (expense)	(381		)	(3,181		)	2,216		(3,889		)	(5,235		)
Interest charges	94,918			36,280			1,986		(3,889		)	129,295
Income before income taxes	289,269			133,358			54,192		—			476,819
Income tax expense	117,684			47,167			22,151		—			187,002
Net income	$	171,585		$	86,191		$	32,041	$	—		$	289,817
Capital expenditures	$	574,372		$	248,230		$	1,839	$	—		$	824,441

Revenue from External Customers by Products and Services

The following table summarizes our revenues from external parties by products and services for the fiscal year ended September 30.

	2016		2015		2014
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,477,049	$	1,761,689	$	1,933,099
Commercial	619,979		772,187		876,042
Industrial	51,999		74,981		90,536
Public authority and other	41,307		53,401		64,779
Total gas sales revenues	2,190,334		2,662,258		2,964,456
Transportation revenues	70,383		67,475		64,049
Other gas revenues	23,468		27,852		27,707
Total regulated distribution revenues	2,284,185		2,757,585		3,056,212
Regulated pipeline revenues	104,007		97,662		92,166
Nonregulated revenues	961,757		1,286,889		1,792,538
Total operating revenues	$	3,349,949	$	4,142,136	$	4,940,916

Schedule of segment reporting balance sheet information, by segment

Balance sheet information at September 30, 2016 and 2015 by segment is presented in the following tables.

	September 30, 2016
	Regulated Distribution		Regulated Pipeline		Nonregulated		Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	6,220,425	$	2,008,997	$	51,089	$	—		$	8,280,511
Investment in subsidiaries	1,026,859		—		—		(1,026,859		)	—
Current assets
Cash and cash equivalents	21,072		—		26,462		—			47,534
Assets from risk management activities	3,029		—		6,775		—			9,804
Other current assets	446,868		19,204		367,220		(208,944		)	624,348
Intercompany receivables	978,093		—		—		(978,093		)	—
Total current assets	1,449,062		19,204		400,457		(1,187,037		)	681,686
Goodwill	576,114		132,582		34,711		—			743,407
Noncurrent assets from risk management activities	1,822		—		—		—			1,822
Deferred charges and other assets	275,496		27,631		336		—			303,463
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,463,059	$	678,964	$	347,895	$	(1,026,859	)	$	3,463,059
Long-term debt	2,188,779		—		—		—			2,188,779
Total capitalization	5,651,838		678,964		347,895		(1,026,859		)	5,651,838
Current liabilities
Current maturities of long-term debt	250,000		—		—		—			250,000
Short-term debt	1,026,811		—		—		(197,000		)	829,811
Liabilities from risk management activities	56,771		—		—		—			56,771
Other current liabilities	549,328		22,427		91,888		(11,944		)	651,699
Intercompany payables	—		950,215		27,878		(978,093		)	—
Total current liabilities	1,882,910		972,642		119,766		(1,187,037		)	1,788,281
Deferred income taxes	1,058,895		536,732		7,429		—			1,603,056
Noncurrent liabilities from risk management activities	184,048		—		—		—			184,048
Regulatory cost of removal obligation	424,281		—		—		—			424,281
Pension and postretirement liabilities	297,743		—		—		—			297,743
Deferred credits and other liabilities	50,063		76		11,503		—			61,642
	$	9,549,778	$	2,188,414	$	486,593	$	(2,213,896	)	$	10,010,889

	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	421,591		24,628		480,503			(338,301		)	588,421
Intercompany receivables	887,713		—		—			(887,713		)	—
Total current assets	1,333,545		24,628		494,147			(1,226,014		)	626,306
Goodwill	575,449		132,542		34,711			—			742,702
Noncurrent assets from risk management activities	368		—		—			—			368
Deferred charges and other assets	252,499		17,288		5,329			—			275,116
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,194,797	$	577,275	$	461,395		$	(1,038,670	)	$	3,194,797
Long-term debt	2,437,515		—		—			—			2,437,515
Total capitalization	5,632,312		577,275		461,395			(1,038,670		)	5,632,312
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
	$	8,870,837	$	1,880,907	$	585,916		$	(2,262,588	)	$	9,075,072

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Earnings Per Share (Table)

12 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings per share table

Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:

	2016		2015		2014
	(In thousands, except per share data)
Basic Earnings Per Share
Net Income	$	350,104	$	315,075	$	289,817
Less: Income allocated to participating securities	546		626		711
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Net Income per share — Basic	$	3.38	$	3.09	$	2.96
Diluted Earnings Per Share
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Effect of dilutive stock options and other shares	—		—		—
Net Income available to common shareholders	$	349,558	$	314,449	$	289,106
Basic weighted average shares outstanding	103,524		101,892		97,606
Additional dilutive stock options and other shares	—		—		2
Diluted weighted average shares outstanding	103,524		101,892		97,608
Net Income per share — Diluted	$	3.38	$	3.09	$	2.96

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Debt (Table)

12 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt instrument table

Long-term debt at September 30, 2016 and 2015 consisted of the following:

	2016		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 Series A notes, 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	4,270		4,612
Debt issuance cost	16,951		17,873
Current maturities	250,000		—
	$	2,188,779	$	2,437,515

Debt maturity schedule

Maturities of long-term debt at September 30, 2016 were as follows (in thousands):

2017	$	250,000
2018	—
2019	450,000
2020	—
2021	—
Thereafter	1,760,000
	$	2,460,000

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Shareholders' Equity (Table)

12 Months Ended

Sep. 30, 2016

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

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	(263		)	(99,029		)	(11,662		)	(110,954		)
Amounts reclassified from accumulated other comprehensive income	(202		)	347			32,117			32,262
Net current-period other comprehensive income (loss)	(465		)	(98,682		)	20,455			(78,692		)
September 30, 2016	$	4,484		$	(187,524	)	$	(4,982	)	$	(188,022	)

	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	(2,173		)	(71,003		)	(49,211		)	(122,387		)
Amounts reclassified from accumulated other comprehensive income	(540		)	542			25,448			25,450
Net current-period other comprehensive income (loss)	(2,713		)	(70,461		)	(23,763		)	(96,937		)
September 30, 2015	$	4,949		$	(88,842	)	$	(25,437	)	$	(109,330	)

Reclassification out of Accumulated Other Comprehensive Income

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2016 and 2015. Amounts in parentheses below indicate decreases to net income in the statement of income.

	Fiscal Year Ended September 30, 2016
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	$	318		Operation and maintenance expense
	318			Total before tax
	(116		)	Tax expense
	$	202		Net of tax
Cash flow hedges
Interest rate agreements	$	(546	)	Interest charges
Commodity contracts	(52,651		)	Purchased gas cost
	(53,197		)	Total before tax
	20,733			Tax benefit
	$	(32,464	)	Net of tax
Total reclassifications	$	(32,262	)	Net of tax

	Fiscal Year Ended September 30, 2015
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	$	850		Operation and maintenance expense
	850			Total before tax
	(310		)	Tax expense
	$	540		Net of tax
Cash flow hedges
Interest rate agreements	$	(853	)	Interest charges
Commodity contracts	(41,716		)	Purchased gas cost
	(42,569		)	Total before tax
	16,579			Tax benefit
	$	(25,990	)	Net of tax
Total reclassifications	$	(25,450	)	Net of tax

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Retirement and Post-Retirement Employee Benefit Plans (Table)

12 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Periodic Benefit Cost Not Yet Recognized And Recorded as Regulatory Assets

The amounts that have not yet been recognized in net periodic pension cost that have been recorded as regulatory assets are as follows:

	Defined Benefits Plan			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2016
Unrecognized prior service credit	$	(1,509	)	$	—	$	(2,880	)	$	(4,389	)
Unrecognized actuarial (gain) loss	127,028			51,558		(54,298		)	124,288
	$	125,519		$	51,558	$	(57,178	)	$	119,899
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial (gain) loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537

Schedule of Allocation of Plan Assets

The following table presents asset allocation information for the Master Trust as of September 30, 2016 and 2015.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2016		2015
Domestic equities	35%-55%	40.5	%	41.3	%
International equities	10%-20%	15.5	%	14.9	%
Fixed income	5%-30%	11.2	%	11.0	%
Company stock	0%-15%	15.1	%	15.2	%
Other assets	0%-20%	17.7	%	17.6	%

The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2016 and 2015.

	Actual Allocation September 30
Security Class	2016		2015
Diversified investment funds	97.2	%	97.5	%
Cash and cash equivalents	2.8	%	2.5	%

Schedule of Employee Pension Plans Investments at Fair Value

In addition to the assets shown below, the Plan had net accounts receivable of $2.6 million and $2.4 million at September 30, 2016 and 2015 which materially approximates fair value due to the short-term nature of these assets.

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	157,111	$	—	$	—	$	157,111
Money market funds	—		11,522		—		11,522
Registered investment companies	87,396		—		—		87,396
Common/collective trusts	—		105,124		—		105,124
Government securities:
Mortgage-backed securities	—		15,223		—		15,223
U.S. treasuries	4,704		863		—		5,567
Corporate bonds	—		31,929		—		31,929
Limited partnerships	—		57,438		—		57,438
Total investments at fair value	$	249,211	$	222,099	$	—	$	471,310

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	159,304	$	—	$	—	$	159,304
Money market funds	—		11,787		—		11,787
Registered investment companies	81,960		—		—		81,960
Common/collective trusts	—		93,081		—		93,081
Government securities:
Mortgage-backed securities	—		14,359		—		14,359
U.S. treasuries	5,279		805		—		6,084
Corporate bonds	—		28,973		—		28,973
Limited partnerships	—		52,996		—		52,996
Total investments at fair value	$	246,543	$	202,001	$	—	$	448,544

Schedule of Expected Benefit Payments

The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years:

	Pension Plan		Supplemental Plans
	(In thousands)
2017	$	31,306	$	36,604
2018	32,047		14,289
2019	33,674		7,181
2020	35,232		4,395
2021	37,279		4,306
2022-2026	202,442		60,658

The following benefit payments paid by us, retirees and prescription drug subsidy payments for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years. Company payments for fiscal 2016 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2017	$	15,806	$	3,679	$	—	$	19,485
2018	11,602		3,992		—		15,594
2019	12,165		4,036		—		16,201
2020	13,246		4,756		—		18,002
2021	14,210		5,420		—		19,630
2022-2026	84,642		36,837		—		121,479

Schedule of Postretirement Benefit Plans Investments at Fair Value

	Assets at Fair Value as of September 30, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	4,470	$	—	$	4,470
Registered investment companies	154,507		—		—		154,507
Total investments at fair value	$	154,507	$	4,470	$	—	$	158,977

	Assets at Fair Value as of September 30, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,486	$	—	$	3,486
Registered investment companies	134,523		—		—		134,523
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

Schedule of Assumptions Used [Table Text Block]

The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2015, 2014 and 2013. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.00	%	7.00	%	7.25	%	7.25	%

The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2016 and 2015 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2015, 2014 and 2013. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2016		2015		2016		2015		2014
Discount rate	3.73	%	4.55	%	4.55	%	4.43	%	4.95	%
Expected return on plan assets	4.45	%	4.45	%	4.45	%	4.60	%	4.60	%
Initial trend rate	7.50	%	7.50	%	7.50	%	7.50	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2022		2021		2021		2020		2020

Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]

The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	516,924		$	485,921
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	508,599		$	493,594
Service cost	16,419			16,231
Interest cost	23,193			21,850
Actuarial loss	41,847			7,420
Benefits paid(1)	(44,578		)	(30,496		)
Benefit obligation at end of year	545,480			508,599
Change in plan assets:
Fair value of plan assets at beginning of year	450,932			434,767
Actual return on plan assets	52,596			8,661
Employer contributions	15,000			38,000
Benefits paid(1)	(44,578		)	(30,496		)
Fair value of plan assets at end of year	473,950			450,932
Reconciliation:
Funded status	(71,530		)	(57,667		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(71,530	)	$	(57,667	)

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Accumulated benefit obligation	$	137,616		$	118,835
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	122,393		$	113,219
Service cost	2,371			3,971
Interest cost	5,185			4,943
Actuarial loss	17,229			4,811
Benefits paid	(4,604		)	(4,551		)
Benefit obligation at end of year	142,574			122,393
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,604			4,551
Benefits paid	(4,604		)	(4,551		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(142,574		)	(122,393		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(142,574	)	$	(122,393	)

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2016 and 2015:

	2016			2015
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	267,179		$	315,118
Service cost	10,823			15,583
Interest cost	12,424			14,385
Plan participants’ contributions	4,289			4,563
Actuarial gain	(1,052		)	(69,962		)
Benefits paid	(14,441		)	(12,508		)
Benefit obligation at end of year	279,222			267,179
Change in plan assets:
Fair value of plan assets at beginning of year	138,009			134,821
Actual return on plan assets	14,528			(8,851		)
Employer contributions	16,592			19,984
Plan participants’ contributions	4,289			4,563
Benefits paid	(14,441		)	(12,508		)
Fair value of plan assets at end of year	158,977			138,009
Reconciliation:
Funded status	(120,245		)	(129,170		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(120,245	)	$	(129,170	)

Schedule of Net Benefit Costs [Table Text Block]

Net periodic pension cost for the supplemental plans for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016		2015		2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	2,371	$	3,971	$	3,607
Interest cost	5,185		4,943		4,966
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,586		2,343		1,948
Settlements	—		—		4,539
Net periodic pension cost	$	10,142	$	11,257	$	15,060

Net periodic pension cost for the Plan for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,419		$	16,231		$	15,345
Interest cost	23,193			21,850			22,330
Expected return on assets	(27,522		)	(25,744		)	(23,601		)
Amortization of prior service credit	(226		)	(192		)	(136		)
Recognized actuarial loss	10,693			13,322			13,777
Net periodic pension cost	$	22,557		$	25,467		$	27,715

Net periodic postretirement cost for fiscal 2016, 2015 and 2014 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	10,823		$	15,583		$	16,784
Interest cost	12,424			14,385			15,951
Expected return on assets	(6,264		)	(6,431		)	(5,167		)
Amortization of transition obligation	82			272			274
Amortization of prior service credit	(1,644		)	(1,644		)	(1,450		)
Recognized actuarial (gain) loss	(2,167		)	—			631
Net periodic postretirement cost	$	13,254		$	22,165		$	27,023

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations:

	One-Percentage Point Increase		One-Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components	$	4,539	$	(3,596	)
Effect on postretirement benefit obligation	$	42,079	$	(34,531	)

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Stock and Other Compensation Plans (Table)

12 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of restricted stock activity

The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2016, 2015 and 2014:

	2016				2015				2014
	Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value		Number of Restricted Units		Weighted Average Grant-Date Fair Value
Nonvested at beginning of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20
Granted	357,323		65.98		444,543		50.50		464,438		45.05
Vested	(448,136	)	45.88		(551,688	)	39.28		(524,532	)	32.67
Forfeited	(4,860	)	53.52		(3,388	)	48.55		(4,113	)	39.00
Nonvested at end of year	782,431		$	57.66	878,104		$	48.24	988,637		$	42.22

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Details of Selected Consolidated Balance Sheet Captions (Table)

12 Months Ended

Sep. 30, 2016

Details Of Selected Consolidated Balance Sheet Captions Disclosure [Abstract]

Accounts Receivables Detail Table

Accounts receivable was comprised of the following at September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Billed accounts receivable	$	206,248		$	204,585
Unbilled revenue	67,396			65,008
Other accounts receivable	39,730			40,850
Total accounts receivable	313,374			310,443
Less: allowance for doubtful accounts	(13,367		)	(15,283		)
Net accounts receivable	$	300,007		$	295,160

Other Current Assets Detail Table

Other current assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Assets from risk management activities	$	9,804	$	9,232
Deferred gas costs	45,184		9,715
Taxes receivable	5,456		4,479
Prepaid expenses	23,053		23,055
Materials and supplies	5,825		12,587
Other	11,507		6,822
Total	$	100,829	$	65,890

Property, Plant and Equipment Detail Table

Property, plant and equipment was comprised of the following as of September 30, 2016 and 2015:

	September 30
	2016			2015
	(In thousands)
Production plant	$	66		$	131
Storage plant	353,523			286,011
Transmission plant	2,232,927			1,844,117
Distribution plant	6,598,990			6,019,001
General plant	761,057			769,311
Intangible plant	40,515			41,131
	9,987,078			8,959,702
Construction in progress	184,062			280,398
	10,171,140			9,240,100
Less: accumulated depreciation and amortization	(1,890,629		)	(1,809,520		)
Net property, plant and equipment(1)	$	8,280,511		$	7,430,580

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

Goodwill Detail Table

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2016:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702
Deferred tax adjustments on prior acquisitions(1)	665		40		—		705
Balance as of September 30, 2016	$	576,114	$	132,582	$	34,711	$	743,407

⁽¹⁾  We annually adjust certain deferred taxes recorded in connection with acquisitions completed in fiscal 2001 and fiscal 2004, which resulted in an increase to goodwill and net deferred tax liabilities of $0.7 million

Deferred Charges and Other Assets Detail Table

Deferred charges and other assets as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Marketable securities	$	72,701	$	74,200
Regulatory assets	214,890		182,573
Assets from risk management activities	1,822		368
Other	15,872		18,343
Total	$	305,285	$	275,484

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Trade accounts payable	$	114,533	$	78,534
Accrued gas payable	108,526		119,825
Accrued liabilities	36,375		40,583
Total	$	259,434	$	238,942

Other Current Liabilities Detail Table

Other current liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer credit balances and deposits	$	81,890	$	100,232
Accrued employee costs	47,058		47,602
Deferred gas costs	20,180		28,100
Accrued interest	34,863		34,914
Liabilities from risk management activities	56,771		9,568
Taxes payable	104,457		93,674
Pension and postretirement obligations	36,606		21,857
Current deferred tax liability	—		55,918
Regulatory cost of removal accrual	52,610		56,123
Other	14,601		9,966
Total	$	449,036	$	457,954

Deferred Credits and Other Liabilities Detail Table

Deferred credits and other liabilities as of September 30, 2016 and 2015 were comprised of the following accounts.

	September 30
	2016		2015
	(In thousands)
Customer advances for construction	$	9,850	$	9,316
Regulatory liabilities	4,152		3,693
Asset retirement obligation	13,404		9,063
Liabilities from risk management activities	184,048		110,539
Other	34,236		29,085
Total	$	245,690	$	161,696

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Leases (Table)

12 Months Ended

Sep. 30, 2016

Leases [Abstract]

Schedule of Future Minimum Lease Payments

The related future minimum lease payments at September 30, 2016 were as follows:

	Operating Leases
	(In thousands)
2017	$	17,073
2018	16,824
2019	15,450
2020	14,479
2021	14,335
Thereafter	47,714
Total minimum lease payments	$	125,875

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Commitments and Contingencies (Table)

12 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of Estimated Contractual Demand Fees

The estimated contractual demand fees for contracted storage and transportation under these contracts as of September 30, 2016 are as follows (in thousands):

2017	$	9,065
2018	2,336
2019	424
2020	400
2021	327
Thereafter	678
	$	13,230

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Income Taxes (Table)

12 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of income tax expense from continuing operations for 2016, 2015 and 2014 were as follows:

	2016			2015			2014
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	6,822			7,251			5,527
Deferred
Federal	181,790			175,897			169,106
State	11,766			12,548			12,375
Investment tax credits	(5		)	(6		)	(6		)
	$	200,373		$	195,690		$	187,002

Schedule of Effective Income Tax Rate Reconciliation

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2016, 2015 and 2014 are set forth below:

	2016			2015			2014
	(In thousands)
Tax at statutory rate of 35%	$	192,667		$	178,768		$	166,887
Common stock dividends deductible for tax reporting	(2,570		)	(2,413		)	(2,307		)
State taxes (net of federal benefit)	11,504			12,869			11,636
Change in valuation allowance	1,324			4,998			6,969
Other, net	(2,552		)	1,468			3,817
Income tax expense	$	200,373		$	195,690		$	187,002

Schedule of Deferred Tax Assets and Liabilities

The tax effect of temporary differences that gave rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2016 and 2015 are presented below:

	2016			2015
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	122,682		$	121,619
Interest rate agreements	107,782			51,067
Net operating loss carryforwards	514,391			313,224
Charitable and other credit carryforwards	22,273			22,281
Other	23,648			36,695
Total deferred tax assets	790,776			544,886
Valuation allowance	(10,481		)	(10,872		)
Net deferred tax assets	780,295			534,014
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(2,259,278		)	(1,890,886		)
Pension funding	(30,652		)	(35,247		)
Gas cost adjustments	(54,725		)	(43,634		)
Other	(38,696		)	(31,480		)
Total deferred tax liabilities	(2,383,351		)	(2,001,247		)
Net deferred tax liabilities	$	(1,603,056	)	$	(1,467,233	)
Deferred credits for rate regulated entities	$	861		$	412

Schedule of Unrecognized Tax Benefits Roll Forward

The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2016			2015
	(In thousands)
Unrecognized tax benefits - beginning balance	$	17,069		$	12,629
Increase (decrease) resulting from prior period tax positions	(290		)	1,009
Increase resulting from current period tax positions	3,519			3,431
Unrecognized tax benefits - ending balance	20,298			17,069
Less: deferred federal and state income tax benefits	(7,104		)	(5,974		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	13,194		$	11,095

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Financial Instruments (Table)

12 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of financial instrument assets and liabilities at fair value

The following table shows the fair values of our risk management assets and liabilities by segment at September 30, 2016 and 2015:

	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2016
Assets from risk management activities, current(1)	$	3,029		$	6,775	$	9,804
Assets from risk management activities, noncurrent	1,822			—		1,822
Liabilities from risk management activities, current(1)	(56,771		)	—		(56,771		)
Liabilities from risk management activities, noncurrent(1)	(184,048		)	—		(184,048		)
Net assets (liabilities)	$	(235,968	)	$	6,775	$	(229,193	)
September 30, 2015
Assets from risk management activities, current(2)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(2)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(2)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)

⁽¹⁾  Includes $25.7 million of cash held on deposit to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. Also includes $24.7 million of cash held on deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

⁽²⁾  Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

Outstanding commodity contracts volumes table

As of September 30, 2016, 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	—	(19,395	)
	Cash Flow	—	39,278
	Not designated	18,595	71,147
		18,595	91,030

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 September 30, 2016 and 2015. The gross amounts of recognized assets and liabilities are netted within our 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)
September 30, 2016
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	6,612		$	(21,903	)
Interest rate contracts	Other current assets / Other current liabilities	—		(68,481		)	—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			2,178			(3,779		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(198,008		)	—			—
Total		—		(266,489		)	8,790			(25,682		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	3,029		—			18,157			(18,812		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,822		—			12,343			(12,701		)
Total		4,851		—			30,500			(31,513		)
Gross Financial Instruments		4,851		(266,489		)	39,290			(57,195		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(39,290		)	39,290
Net Financial Instruments		4,851		(266,489		)	—			(17,905		)
Cash collateral		—		25,670			6,775			17,905
Net Assets/Liabilities from Risk Management Activities		$	4,851	$	(240,819	)	$	6,775		$	—

		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		$	—

Fair value hedges table

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our consolidated income statement for the years ended September 30, 2016, 2015 and 2014 is presented below.

	Fiscal Year Ended September 30
	2016			2015			2014
	(In thousands)
Commodity contracts	$	3,516		$	10,311		$	(792	)
Fair value adjustment for natural gas inventory designated as the hedged item	18,079			(9,768		)	2,486
Total decrease in purchased gas cost	$	21,595		$	543		$	1,694
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(1,390	)	$	811		$	(919	)
Timing ineffectiveness	22,985			(268		)	2,613
	$	21,595		$	543		$	1,694

Cash flow hedges table

The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2016, 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.

	Fiscal Year Ended September 30, 2016
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(52,651	)	$	(52,651	)
Loss arising from ineffective portion of commodity contracts	—			(19		)	(19		)
Total impact on purchased gas cost	—			(52,670		)	(52,670		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(546		)	—			(546		)
Total impact from cash flow hedges	$	(546	)	$	(52,670	)	$	(53,216	)

	Fiscal Year Ended September 30, 2015
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(41,716	)	$	(41,716	)
Loss arising from ineffective portion of commodity contracts	—			(325		)	(325		)
Total impact on purchased gas cost	—			(42,041		)	(42,041		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(853		)	—			(853		)
Total impact from cash flow hedges	$	(853	)	$	(42,041	)	$	(42,894	)

	Fiscal Year Ended September 30, 2014
	Regulated Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	8,365	$	8,365
Gain arising from ineffective portion of commodity contracts	—			198		198
Total impact on purchased gas cost	—			8,563		8,563
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(4,230		)	—		(4,230		)
Total impact from cash flow hedges	$	(4,230	)	$	8,563	$	4,333

Other comprehensive income from hedging table

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 years ended September 30, 2016 and 2015. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.

	Fiscal Year Ended September 30
	2016			2015
	(In thousands)
Decrease in fair value:
Interest rate agreements	$	(99,029	)	$	(71,003	)
Forward commodity contracts	(11,662		)	(49,211		)
Recognition of losses in earnings due to settlements:
Interest rate agreements	347			542
Forward commodity contracts	32,117			25,448
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(78,227	)	$	(94,224	)

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

Expected recognition in earnings of deferred losses in AOCI table

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 September 30, 2016. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2017	$	(447	)	$	(3,983	)	$	(4,430	)
2018	(649		)	(561		)	(1,210		)
2019	(673		)	(414		)	(1,087		)
2020	(698		)	(26		)	(724		)
2021	(698		)	2			(696		)
Thereafter	(15,139		)	—			(15,139		)
Total(1)	$	(18,304	)	$	(4,982	)	$	(23,286	)

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

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Fair Value Measurements (Table)

12 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair value measurements table

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 September 30, 2016 and 2015. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(2)			September 30, 2016
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	4,851	$	—	$	—		$	4,851
Nonregulated segment	—		39,290		—		(32,515		)	6,775
Total financial instruments	—		44,141		—		(32,515		)	11,626
Hedged portion of gas stored underground	52,578		—		—		—			52,578
Available-for-sale securities
Money market funds	—		2,630		—		—			2,630
Registered investment companies	38,677		—		—		—			38,677
Bonds	—		31,394		—		—			31,394
Total available-for-sale securities	38,677		34,024		—		—			72,701
Total assets	$	91,255	$	78,165	$	—	$	(32,515	)	$	136,905
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	266,489	$	—	$	(25,670	)	$	240,819
Nonregulated segment	—		57,195		—		(57,195		)	—
Total liabilities	$	—	$	323,684	$	—	$	(82,865	)	$	240,819

	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 September 30, 2016, we had $25.7 million of cash held in margin accounts to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. As of September 30, 2016 we also had $24.7 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $6.8 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 nonregulated financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $8.9 million is classified as current risk management assets.

Available for sale securities

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

	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of September 30, 2016
Domestic equity mutual funds	$	26,692	$	6,419	$	(590	)	$	32,521
Foreign equity mutual funds	4,954		1,202		—			6,156
Bonds	31,296		108		(10		)	31,394
Money market funds	2,630		—		—			2,630
	$	65,572	$	7,729	$	(600	)	$	72,701
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

Other fair value measurements table

The following table presents the carrying value and fair value of our debt as of September 30, 2016:

	September 30, 2016
	(In thousands)
Carrying Amount	$	2,460,000
Fair Value	$	2,844,990

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Subsequent Events (Tables)

12 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Disposal Groups, Including Discontinued Operations [Table Text Block]

The following table summarizes the approximate value of the assets and liabilities that are part of the disposal group as of September 30, 2016:

	September 30, 2016
	(In thousands)
Assets:
Net property, plant and equipment	$	13,000
Accounts receivable	94,000
Gas stored underground	56,000
Other current assets	13,000
Goodwill	15,000
Deferred charges and other assets	300
Total assets included in disposal group	$	191,300
Liabilities:
Accounts payable and accrued liabilities	$	71,000
Other current liabilities	8,000
Deferred credits and other	200
Total liabilities included in disposal group	$	79,200

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Selected Quarterly Financial Data (Table)

12 Months Ended

Sep. 30, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized unaudited quarterly financial data is presented below. The sum of net income per share by quarter may not equal the net income per share for the fiscal year due to variations in the weighted average shares outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section herein.

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2016:
Operating revenues
Regulated distribution	$	638,602		$	849,685		$	414,226		$	389,353
Regulated pipeline	94,677			95,703			109,249			109,204
Nonregulated	272,524			287,395			214,555			291,889
Intersegment eliminations	(99,582		)	(100,490		)	(105,114		)	(111,927		)
	906,221			1,132,293			632,916			678,519
Gross profit	443,763			517,811			407,311			376,011
Operating income	196,205			250,016			137,164			84,633
Net income	102,861			141,810			71,193			34,240
Net income per share — basic	$	1.00		$	1.38		$	0.69		$	0.33
Net income per share — diluted	$	1.00		$	1.38		$	0.69		$	0.33

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2015:
Operating revenues
Regulated distribution	$	846,772		$	1,130,613		$	416,794		$	369,656
Regulated pipeline	83,567			91,730			97,008			97,807
Nonregulated	462,288			438,322			278,769			292,830
Intersegment eliminations	(133,862		)	(120,597		)	(106,170		)	(103,391		)
	1,258,765			1,540,068			686,401			656,902
Gross profit	423,285			520,738			381,673			354,321
Operating income	187,725			250,210			117,607			75,853
Net income	97,595			137,684			56,281			23,515
Net income per share — basic	$	0.96		$	1.35		$	0.55		$	0.23
Net income per share — diluted	$	0.96		$	1.35		$	0.55		$	0.23

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Nature of Business (Details) customers in Millions	Sep. 30, 2016 customers regulated_gas_distributions_divisions
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number Of Divisions, Regulated Distribution | regulated_gas_distributions_divisions	6
Number Of Customers, Regulated Distribution | customers	3

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Mar. 31, 2016
Regulatory Assets [Line Items]
Regulatory Assets		$ 263,623	$ 192,339
Regulatory Liabilities [Line Items]
Regulatory Liabilities		514,725	524,532
Regulatory Assets and Liabilities, Other Disclosures [Abstract]
Regulatory Asset - Future Recoverable Pension Costs		12,400	16,600
Property, Plant and Equipment [Line Items]
Interest Costs Capitalized		$ 2,800	$ 2,300	$ 1,500
Composite depreciation rate for regulated property, plant and equipment		3.20%	3.30%	3.30%
Derivative [Line Items]
Unrealized gain (loss) on open contracts		$ 1,300	$ (2,400)	$ 9,600
Asset Retirement Costs in Property, Plant and Equipment		8,100	4,800
Asset Retirement Obligation		13,400	11,100
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred charges and other assets		305,285	275,484
Deferred Tax Assets, Operating Loss Carryforwards		514,391	313,224
Retained earnings		1,262,534	1,073,029
Long-term debt		(2,188,779)	(2,437,515)
Income tax expense		200,373	195,690	187,002
Regulated Distribution Segment [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Long-term debt		(2,188,779)	(2,437,515)
Income tax expense		128,265	130,827	117,684
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		25,670	0
Nonregulated Segment [Member]
Derivative [Line Items]
Cash Held in Margin Accounts		24,700	43,500
New Accounting Pronouncement, Early Adoption [Line Items]
Long-term debt		0	0
Income tax expense		12,620	12,652	$ 22,151
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		17,905	34,620
Regulatory Cost Of Removal Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		476,891	483,676
Deferred Gas Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		20,180	28,100
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		13,404	9,063
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		4,250	3,693
Pension And Postretirement Benefit Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[1]	132,348	121,183
Infrastructure Mechanisms [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[2]	42,719	32,813
Deferred Gas Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		45,184	9,715
Recoverable Loss On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets		13,761	16,319
Deferred Pipeline Record Collection Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		7,336	3,118
APT Annual Adjustment Mechanism Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets		7,171	1,002
Rate Case Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		1,539	1,533
Other [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 13,565	6,656
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives for nonregulated property, plant and equipment		3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives for nonregulated property, plant and equipment		43 years
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2016-09 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards		$ 5,000
Income tax expense		(5,000)
New Accounting Pronouncement, Early Adoption, Effect [Member] | Accounting Standards Update 2015-03 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred charges and other assets		(17,000)	(17,900)
Long-term debt		$ (17,000)	$ (17,900)
Adjustments for New Accounting Principle, Early Adoption [Member] | Accounting Standards Update 2016-09 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards					$ 14,500
Retained earnings					$ 14,500

[1] Includes $12.4 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 eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

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Segment Information (Details) customers in Millions		3 Months Ended										12 Months Ended
		Sep. 30, 2016 USD ($) state customers regulated_gas_distributions_divisions		Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)		Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2016 USD ($) segment state customers regulated_gas_distributions_divisions		Sep. 30, 2015 USD ($)		Sep. 30, 2014 USD ($)	Sep. 30, 2013 USD ($)
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		$ 678,519,000		$ 632,916,000	$ 1,132,293,000	$ 906,221,000	$ 656,902,000		$ 686,401,000	$ 1,540,068,000	$ 1,258,765,000	$ 3,349,949,000		$ 4,142,136,000		$ 4,940,916,000
Purchased gas cost												1,605,053,000		2,462,119,000		3,358,490,000
Gross profit		376,011,000		407,311,000	517,811,000	443,763,000	354,321,000		381,673,000	520,738,000	423,285,000	1,744,896,000		1,680,017,000		1,582,426,000
Operating expenses
Operation and maintenance												560,766,000		541,868,000		505,154,000
Depreciation and amortization												293,096,000		274,796,000		253,987,000
Taxes, other than income												223,016,000		231,958,000		211,936,000
Total operating expenses												1,076,878,000		1,048,622,000		971,077,000
Operating income		84,633,000		137,164,000	250,016,000	196,205,000	75,853,000		117,607,000	250,210,000	187,725,000	668,018,000		631,395,000		611,349,000
Miscellaneous income (expense), net												(1,593,000)		(4,389,000)		(5,235,000)
Interest charges												115,948,000		116,241,000		129,295,000
Income (loss) before income taxes												550,477,000		510,765,000		476,819,000
Income tax expense												200,373,000		195,690,000		187,002,000
Net income		34,240,000		71,193,000	141,810,000	102,861,000	23,515,000		56,281,000	137,684,000	97,595,000	350,104,000		315,075,000		289,817,000
Capital expenditures												1,086,950,000		963,621,000		824,441,000
ASSETS
Net property, plant and equipment	[1]	8,280,511,000					7,430,580,000					8,280,511,000		7,430,580,000
Investment in subsidaries		0					0					0		0
Current assets
Cash and cash equivalents		47,534,000					28,653,000					47,534,000		28,653,000		42,258,000	$ 66,199,000
Assets from risk management activities current		9,804,000					9,232,000					9,804,000		9,232,000
Other current assets		624,348,000					588,421,000					624,348,000		588,421,000
Intercompany receivables		0					0					0		0
Total current assets		681,686,000					626,306,000					681,686,000		626,306,000
Goodwill		743,407,000					742,702,000					743,407,000		742,702,000
Assets from risk management activities noncurrent		1,822,000					368,000					1,822,000		368,000
Deferred charges and other assets		303,463,000					275,116,000					303,463,000		275,116,000
Total assets		10,010,889,000					9,075,072,000					10,010,889,000		9,075,072,000
CAPITALIZATION AND LIABILITIES
Shareholders' equity		3,463,059,000					3,194,797,000					3,463,059,000		3,194,797,000		3,086,232,000	$ 2,580,409,000
Long-term debt		2,188,779,000					2,437,515,000					2,188,779,000		2,437,515,000
Total capitalization		5,651,838,000					5,632,312,000					5,651,838,000		5,632,312,000
Current liabilities
Current maturities of long-term debt		250,000,000					0					250,000,000		0
Short-term debt		829,811,000					457,927,000					829,811,000		457,927,000
Liabilities from risk management activities current		56,771,000					9,568,000					56,771,000		9,568,000
Other current liabilities		651,699,000					687,328,000					651,699,000		687,328,000
Intercompany payables		0					0					0		0
Total current liabilities		1,788,281,000					1,154,823,000					1,788,281,000		1,154,823,000
Deferred income taxes		1,603,056,000					1,411,315,000					1,603,056,000		1,411,315,000
Liabilities from risk management activities noncurrent		184,048,000					110,539,000					184,048,000		110,539,000
Regulatory cost of removal obligation		424,281,000					427,553,000					424,281,000		427,553,000
Pension and postretirement liabilities		297,743,000					287,373,000					297,743,000		287,373,000
Deferred credits and other liabilities		61,642,000					51,157,000					61,642,000		51,157,000
Total shareholders' equity and liabilities		$ 10,010,889,000					9,075,072,000					$ 10,010,889,000		9,075,072,000
Number Of Customers, Regulated Distribution | customers		3										3
Number Of Divisions, Regulated Distribution | regulated_gas_distributions_divisions		6										6
Number of States in which Entity Operates | state		8										8
Number of Operating Segments | segment												3
Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												$ 3,349,949,000		4,142,136,000		4,940,916,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												3,349,949,000		4,142,136,000		4,940,916,000
Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												0		0		0
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												0		0		0
Regulated Distribution Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		$ 389,353,000		414,226,000	849,685,000	638,602,000	369,656,000		416,794,000	1,130,613,000	846,772,000	2,291,866,000		2,763,835,000		3,061,546,000
Purchased gas cost												1,019,061,000		1,526,258,000		1,885,031,000
Gross profit												1,272,805,000		1,237,577,000		1,176,515,000
Operating expenses
Operation and maintenance												404,115,000		388,486,000		387,228,000
Depreciation and amortization												233,036,000		223,048,000		208,376,000
Taxes, other than income												196,070,000		205,894,000		196,343,000
Total operating expenses												833,221,000		817,428,000		791,947,000
Operating income												439,584,000		420,149,000		384,568,000
Miscellaneous income (expense), net												455,000		(377,000)		(381,000)
Interest charges												79,404,000		84,132,000		94,918,000
Income (loss) before income taxes												360,635,000		335,640,000		289,269,000
Income tax expense												128,265,000		130,827,000		117,684,000
Net income												232,370,000		204,813,000		171,585,000
Capital expenditures												740,039,000		670,575,000		574,372,000
ASSETS
Net property, plant and equipment		6,220,425,000					5,670,306,000					6,220,425,000		5,670,306,000
Investment in subsidaries		1,026,859,000					1,038,670,000					1,026,859,000		1,038,670,000
Current assets
Cash and cash equivalents		21,072,000					23,863,000					21,072,000		23,863,000
Assets from risk management activities current		3,029,000					378,000					3,029,000		378,000
Other current assets		446,868,000					421,591,000					446,868,000		421,591,000
Intercompany receivables		978,093,000					887,713,000					978,093,000		887,713,000
Total current assets		1,449,062,000					1,333,545,000					1,449,062,000		1,333,545,000
Goodwill		576,114,000					575,449,000					576,114,000		575,449,000
Assets from risk management activities noncurrent		1,822,000					368,000					1,822,000		368,000
Deferred charges and other assets		275,496,000					252,499,000					275,496,000		252,499,000
Total assets		9,549,778,000					8,870,837,000					9,549,778,000		8,870,837,000
CAPITALIZATION AND LIABILITIES
Shareholders' equity		3,463,059,000					3,194,797,000					3,463,059,000		3,194,797,000
Long-term debt		2,188,779,000					2,437,515,000					2,188,779,000		2,437,515,000
Total capitalization		5,651,838,000					5,632,312,000					5,651,838,000		5,632,312,000
Current liabilities
Current maturities of long-term debt		250,000,000										250,000,000
Short-term debt		1,026,811,000					782,927,000					1,026,811,000		782,927,000
Liabilities from risk management activities current		56,771,000					9,568,000					56,771,000		9,568,000
Other current liabilities		549,328,000					569,273,000					549,328,000		569,273,000
Intercompany payables		0					0					0		0
Total current liabilities		1,882,910,000					1,361,768,000					1,882,910,000		1,361,768,000
Deferred income taxes		1,058,895,000					1,008,091,000					1,058,895,000		1,008,091,000
Liabilities from risk management activities noncurrent		184,048,000					110,539,000					184,048,000		110,539,000
Regulatory cost of removal obligation		424,281,000					427,553,000					424,281,000		427,553,000
Pension and postretirement liabilities		297,743,000					287,373,000					297,743,000		287,373,000
Deferred credits and other liabilities		50,063,000					43,201,000					50,063,000		43,201,000
Total shareholders' equity and liabilities		9,549,778,000					8,870,837,000					9,549,778,000		8,870,837,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												2,284,185,000		2,757,585,000		3,056,212,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												2,284,185,000		2,757,585,000		3,056,212,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Sales Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												2,190,334,000		2,662,258,000		2,964,456,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												2,190,334,000		2,662,258,000		2,964,456,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Sales Revenues [Member] | Residential Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												1,477,049,000		1,761,689,000		1,933,099,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												1,477,049,000		1,761,689,000		1,933,099,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Sales Revenues [Member] | Commercial Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												619,979,000		772,187,000		876,042,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												619,979,000		772,187,000		876,042,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Sales Revenues [Member] | Industrial Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												51,999,000		74,981,000		90,536,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												51,999,000		74,981,000		90,536,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Sales Revenues [Member] | Public Authority and Other Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												41,307,000		53,401,000		64,779,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												41,307,000		53,401,000		64,779,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Gas Transportation Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												70,383,000		67,475,000		64,049,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												70,383,000		67,475,000		64,049,000
Regulated Distribution Segment [Member] | Reportable Subsegments [Member] | Other Gas Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												23,468,000		27,852,000		27,707,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												23,468,000		27,852,000		27,707,000
Regulated Distribution Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												7,681,000		6,250,000		5,334,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												7,681,000		6,250,000		5,334,000
Regulated Pipeline Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		109,204,000		109,249,000	95,703,000	94,677,000	97,807,000		97,008,000	91,730,000	83,567,000	408,833,000		370,112,000		318,459,000
Purchased gas cost												0		0		0
Gross profit												408,833,000		370,112,000		318,459,000
Operating expenses
Operation and maintenance												129,525,000		118,866,000		91,466,000
Depreciation and amortization												55,576,000		47,236,000		41,031,000
Taxes, other than income												24,298,000		22,743,000		13,143,000
Total operating expenses												209,399,000		188,845,000		145,640,000
Operating income												199,434,000		181,267,000		172,819,000
Miscellaneous income (expense), net												(1,683,000)		(1,243,000)		(3,181,000)
Interest charges												36,574,000		33,151,000		36,280,000
Income (loss) before income taxes												161,177,000		146,873,000		133,358,000
Income tax expense												59,488,000		52,211,000		47,167,000
Net income												101,689,000		94,662,000		86,191,000
Capital expenditures												346,400,000		291,603,000		248,230,000
ASSETS
Net property, plant and equipment		2,008,997,000					1,706,449,000					2,008,997,000		1,706,449,000
Investment in subsidaries		0					0					0		0
Current assets
Cash and cash equivalents		0					0					0		0
Assets from risk management activities current		0					0					0		0
Other current assets		19,204,000					24,628,000					19,204,000		24,628,000
Intercompany receivables		0					0					0		0
Total current assets		19,204,000					24,628,000					19,204,000		24,628,000
Goodwill		132,582,000					132,542,000					132,582,000		132,542,000
Assets from risk management activities noncurrent		0					0					0		0
Deferred charges and other assets		27,631,000					17,288,000					27,631,000		17,288,000
Total assets		2,188,414,000					1,880,907,000					2,188,414,000		1,880,907,000
CAPITALIZATION AND LIABILITIES
Shareholders' equity		678,964,000					577,275,000					678,964,000		577,275,000
Long-term debt		0					0					0		0
Total capitalization		678,964,000					577,275,000					678,964,000		577,275,000
Current liabilities
Current maturities of long-term debt		0										0
Short-term debt		0					0					0		0
Liabilities from risk management activities current		0					0					0		0
Other current liabilities		22,427,000					29,780,000					22,427,000		29,780,000
Intercompany payables		950,215,000					867,409,000					950,215,000		867,409,000
Total current liabilities		972,642,000					897,189,000					972,642,000		897,189,000
Deferred income taxes		536,732,000					406,254,000					536,732,000		406,254,000
Liabilities from risk management activities noncurrent		0					0					0		0
Regulatory cost of removal obligation		0					0					0		0
Pension and postretirement liabilities		0					0					0		0
Deferred credits and other liabilities		76,000					189,000					76,000		189,000
Total shareholders' equity and liabilities		2,188,414,000					1,880,907,000					2,188,414,000		1,880,907,000
Regulated Pipeline Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												104,007,000		97,662,000		92,166,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												104,007,000		97,662,000		92,166,000
Regulated Pipeline Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												304,826,000		272,450,000		226,293,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												304,826,000		272,450,000		226,293,000
Nonregulated Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		291,889,000		214,555,000	287,395,000	272,524,000	292,830,000		278,769,000	438,322,000	462,288,000	1,066,363,000		1,472,209,000		2,067,292,000
Purchased gas cost												1,002,573,000		1,399,349,000		1,979,337,000
Gross profit												63,790,000		72,860,000		87,955,000
Operating expenses
Operation and maintenance												27,658,000		35,048,000		26,963,000
Depreciation and amortization												4,484,000		4,512,000		4,580,000
Taxes, other than income												2,648,000		3,321,000		2,450,000
Total operating expenses												34,790,000		42,881,000		33,993,000
Operating income												29,000,000		29,979,000		53,962,000
Miscellaneous income (expense), net												1,443,000		(760,000)		2,216,000
Interest charges												1,778,000		967,000		1,986,000
Income (loss) before income taxes												28,665,000		28,252,000		54,192,000
Income tax expense												12,620,000		12,652,000		22,151,000
Net income												16,045,000		15,600,000		32,041,000
Capital expenditures												511,000		1,443,000		1,839,000
ASSETS
Net property, plant and equipment		51,089,000					53,825,000					51,089,000		53,825,000
Investment in subsidaries		0					(2,096,000)					0		(2,096,000)
Current assets
Cash and cash equivalents		26,462,000					4,790,000					26,462,000		4,790,000
Assets from risk management activities current		6,775,000	[2]				8,854,000	[3]				6,775,000	[2]	8,854,000	[3]
Other current assets		367,220,000					480,503,000					367,220,000		480,503,000
Intercompany receivables		0					0					0		0
Total current assets		400,457,000					494,147,000					400,457,000		494,147,000
Goodwill		34,711,000					34,711,000					34,711,000		34,711,000
Assets from risk management activities noncurrent		0					0					0		0
Deferred charges and other assets		336,000					5,329,000					336,000		5,329,000
Total assets		486,593,000					585,916,000					486,593,000		585,916,000
CAPITALIZATION AND LIABILITIES
Shareholders' equity		347,895,000					461,395,000					347,895,000		461,395,000
Long-term debt		0					0					0		0
Total capitalization		347,895,000					461,395,000					347,895,000		461,395,000
Current liabilities
Current maturities of long-term debt		0										0
Short-term debt		0					0					0		0
Liabilities from risk management activities current		0	[2]				0	[3]				0	[2]	0	[3]
Other current liabilities		91,888,000					99,480,000					91,888,000		99,480,000
Intercompany payables		27,878,000					20,304,000					27,878,000		20,304,000
Total current liabilities		119,766,000					119,784,000					119,766,000		119,784,000
Deferred income taxes		7,429,000					(3,030,000)					7,429,000		(3,030,000)
Liabilities from risk management activities noncurrent		0	[2]				0	[3]				0	[2]	0	[3]
Regulatory cost of removal obligation		0					0					0		0
Pension and postretirement liabilities		0					0					0		0
Deferred credits and other liabilities		11,503,000					7,767,000					11,503,000		7,767,000
Total shareholders' equity and liabilities		486,593,000					585,916,000					486,593,000		585,916,000
Nonregulated Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												961,757,000		1,286,889,000		1,792,538,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												961,757,000		1,286,889,000		1,792,538,000
Nonregulated Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												104,606,000		185,320,000		274,754,000
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												104,606,000		185,320,000		274,754,000
Intersegment Elimination [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		(111,927,000)		$ (105,114,000)	$ (100,490,000)	$ (99,582,000)	(103,391,000)		$ (106,170,000)	$ (120,597,000)	$ (133,862,000)	(417,113,000)		(464,020,000)		(506,381,000)
Purchased gas cost												(416,581,000)		(463,488,000)		(505,878,000)
Gross profit												(532,000)		(532,000)		(503,000)
Operating expenses
Operation and maintenance												(532,000)		(532,000)		(503,000)
Depreciation and amortization												0		0		0
Taxes, other than income												0		0		0
Total operating expenses												(532,000)		(532,000)		(503,000)
Operating income												0		0		0
Miscellaneous income (expense), net												(1,808,000)		(2,009,000)		(3,889,000)
Interest charges												(1,808,000)		(2,009,000)		(3,889,000)
Income (loss) before income taxes												0		0		0
Income tax expense												0		0		0
Net income												0		0		0
Capital expenditures												0		0		0
ASSETS
Net property, plant and equipment		0					0					0		0
Investment in subsidaries		(1,026,859,000)					(1,036,574,000)					(1,026,859,000)		(1,036,574,000)
Current assets
Cash and cash equivalents		0					0					0		0
Assets from risk management activities current		0					0					0		0
Other current assets		(208,944,000)					(338,301,000)					(208,944,000)		(338,301,000)
Intercompany receivables		(978,093,000)					(887,713,000)					(978,093,000)		(887,713,000)
Total current assets		(1,187,037,000)					(1,226,014,000)					(1,187,037,000)		(1,226,014,000)
Goodwill		0					0					0		0
Assets from risk management activities noncurrent		0					0					0		0
Deferred charges and other assets		0					0					0		0
Total assets		(2,213,896,000)					(2,262,588,000)					(2,213,896,000)		(2,262,588,000)
CAPITALIZATION AND LIABILITIES
Shareholders' equity		(1,026,859,000)					(1,038,670,000)					(1,026,859,000)		(1,038,670,000)
Long-term debt		0					0					0		0
Total capitalization		(1,026,859,000)					(1,038,670,000)					(1,026,859,000)		(1,038,670,000)
Current liabilities
Current maturities of long-term debt		0										0
Short-term debt		(197,000,000)					(325,000,000)					(197,000,000)		(325,000,000)
Liabilities from risk management activities current		0					0					0		0
Other current liabilities		(11,944,000)					(11,205,000)					(11,944,000)		(11,205,000)
Intercompany payables		(978,093,000)					(887,713,000)					(978,093,000)		(887,713,000)
Total current liabilities		(1,187,037,000)					(1,223,918,000)					(1,187,037,000)		(1,223,918,000)
Deferred income taxes		0					0					0		0
Liabilities from risk management activities noncurrent		0					0					0		0
Regulatory cost of removal obligation		0					0					0		0
Pension and postretirement liabilities		0					0					0		0
Deferred credits and other liabilities		0					0					0		0
Total shareholders' equity and liabilities		$ (2,213,896,000)					$ (2,262,588,000)					(2,213,896,000)		(2,262,588,000)
Intersegment Elimination [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												0		0		0
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												0		0		0
Intersegment Elimination [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												(417,113,000)		(464,020,000)		(506,381,000)
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												$ (417,113,000)		$ (464,020,000)		$ (506,381,000)

[1] Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

[2] ncludes $24.7 million of cash held on deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

[3] Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

XML

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Basic Earnings per Share
Net income	$ 34,240	$ 71,193	$ 141,810	$ 102,861	$ 23,515	$ 56,281	$ 137,684	$ 97,595	$ 350,104	$ 315,075	$ 289,817
Less: Income allocated to participating securities									546	626	711
Net Income available to common shareholders									$ 349,558	$ 314,449	$ 289,106
Basic weighted average shares outstanding (shares)									103,524	101,892	97,606
Income per share - basic (usd per share)									$ 3.38	$ 3.09	$ 2.96
Diluted Earnings per Share
Effect of dilutive stock options and other shares									$ 0	$ 0	$ 0
Net Income available to common shareholders									$ 349,558	$ 314,449	$ 289,106
Additional dilutive stock options and other shares									0	0	2
Diluted weighted average shares outstanding (shares)									103,524	101,892	97,608
Diluted net income per share	$ 0.33	$ 0.69	$ 1.38	$ 1.00	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 3.38	$ 3.09	$ 2.96

XML

Debt (Details) - USD ($)

12 Months Ended

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Oct. 15, 2014

Sep. 30, 2016

Sep. 30, 2015

Debt Instrument [Line Items]

Debt Instrument Carrying Amount

$ 2,460,000,000

$ 2,460,000,000

Debt Issuance Costs, Net

16,951,000

17,873,000

Debt Instrument Unamortized Discount

4,270,000

4,612,000

Current maturities of long-term debt

250,000,000

0

Long-term Debt, Excluding Current Maturities

2,188,779,000

2,437,515,000

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

1,300,000,000

Long-term Debt, Other Disclosures [Abstract]

Commercial Paper

$ 829,800,000

$ 457,900,000

Commercial Paper Weighted Average Interest Rate

0.81%

0.42%

Term Loan Agreement, Maximum Borrowing Capacity

$ 200,000,000

Term Loan Agreement, Incremental Borrowings

1,000,000

Term Loan Agreement, Amount Outstanding

0

Long-term Debt, Fiscal Year Maturity [Abstract]

2017

250,000,000

2018

0

2019

450,000,000

2020

0

2021

0

Thereafter

$ 1,760,000,000

Subsequent Event [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

$ 1,600,000,000

Subsequent Event, Date

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Subsequent Event, Description

AEH entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. to sell all of the equity interests of AEM for $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. We expect this transaction to close during the second quarter of fiscal 2017.

the uncommitted $25 million 364-day bilateral credit facility was renewed through July 31, 2017.

the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table.

we amended our existing $1.25 billion unsecured credit facility (the five-year unsecured credit facility) which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021.

Required by Covenant [Member]

Line Of Credit Facility [Line Items]

Ratio of Total Debt to Total Capital

70.00%

Actual [Member]

Line Of Credit Facility [Line Items]

Ratio of Total Debt to Total Capital

50.00%

Unregulated Operation [Member]

Line Of Credit Facility [Line Items]

Line of Credit Facility, Remaining Borrowing Capacity

$ 32,800,000

Minimum [Member] | Required by Covenant [Member]

Line Of Credit Facility [Line Items]

Excess of Debt

15,000,000

Maximum [Member] | Required by Covenant [Member]

Line Of Credit Facility [Line Items]

Excess of Debt

$ 100,000,000

Unsecured Senior Notes Due 2014 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

4.95%

Debt Instrument Carrying Amount

$ 500,000,000

Extinguishment of Debt, Amount

$ 500,000,000

Unsecured Senior Notes Due 2017 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

6.35%

6.35%

Debt Instrument, Maturity Date

Jun. 15, 2017

Jun. 15, 2017

Debt Instrument Carrying Amount

$ 250,000,000

$ 250,000,000

Unsecured Senior Notes Due 2019 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

8.50%

8.50%

Debt Instrument, Maturity Date

Mar. 15, 2019

Mar. 15, 2019

Debt Instrument Carrying Amount

$ 450,000,000

$ 450,000,000

Unsecured Senior Notes Due 2034 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

5.95%

5.95%

Debt Instrument, Maturity Date

Oct. 15, 2034

Oct. 15, 2034

Debt Instrument Carrying Amount

$ 200,000,000

$ 200,000,000

Unsecured Senior Notes Due 2041 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

5.50%

5.50%

Debt Instrument, Maturity Date

Jun. 15, 2041

Jun. 15, 2041

Debt Instrument Carrying Amount

$ 400,000,000

$ 400,000,000

Unsecured Senior Notes Due 2043 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

4.15%

4.15%

Debt Instrument, Maturity Date

Jan. 15, 2043

Jan. 15, 2043

Debt Instrument Carrying Amount

$ 500,000,000

$ 500,000,000

Unsecured Senior Notes Due 2044 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

4.125%

4.125%

4.125%

Debt Instrument, Maturity Date

Oct. 15, 2044

Oct. 15, 2044

Debt Instrument Carrying Amount

$ 500,000,000

$ 500,000,000

$ 500,000,000

Debt Instrument Interest Rate Effective Percentage

4.086%

Net Proceeds From Issuance of Debt

$ 494,000,000

Medium Term Notes Due 2025 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

6.67%

6.67%

Debt Instrument, Maturity Date

Dec. 15, 2025

Dec. 15, 2025

Debt Instrument Carrying Amount

$ 10,000,000

$ 10,000,000

Unsecured Debentures Due 2028 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage

6.75%

6.75%

Debt Instrument, Maturity Date

Jul. 15, 2028

Jul. 15, 2028

Debt Instrument Carrying Amount

$ 150,000,000

$ 150,000,000

Commercial Paper [Member] | Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

1,250,000,000

Line of Credit Facility, Accordion Feature

250,000,000

Commercial Paper [Member] | Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member] | Subsequent Event [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

$ 1,500,000,000

Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature

$ 1,750,000,000

Uncommitted Revolving Credit Facility [Member] | Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Amount Outstanding

0

Line of Credit Facility, Remaining Borrowing Capacity

420,200,000

Uncommitted Revolving Credit Facility [Member] | Regulated Operation [Member] | Uncommitted Revolving Credit Facility and Promissory Note (AEH to AEC) [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

500,000,000

Line Of Credit Facility Amount Outstanding

197,000,000

Uncommitted Revolving Credit Facility [Member] | Unregulated Operation [Member] | Uncommitted Revolving Credit Facility and Promissory Note (AEC to AEH) [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

500,000,000

Line Of Credit Facility Amount Outstanding

$ 0

Debt Instrument, Basis Spread on Variable Rate

3.00%

Uncommitted Revolving Credit Facility [Member] | Unregulated Operation [Member] | $25 Million Uncommitted Facility [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

$ 25,000,000

Unsecured Revolving Credit Note [Member] | Regulated Operation [Member] | $10 Million Revolving Credit Note [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

10,000,000

Line Of Credit Facility Amount Outstanding

$ 0

Debt Instrument, Basis Spread on Variable Rate

1.50%

Letters of Credit Outstanding, Amount

$ 5,900,000

Unsecured Revolving Credit Note [Member] | Unregulated Operation [Member] | $15 Million Revolving Credit Note [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

15,000,000

Unsecured Loan Agreement [Member] | Regulated Operation [Member] | $25 Million Bank Loan Agreement [Member]

Line Of Credit Facility [Line Items]

Line Of Credit Facility Maximum Borrowing Capacity

25,000,000

Line Of Credit Facility Amount Outstanding

$ 0

XML

Shareholders' Equity Components (Details) - USD ($)		1 Months Ended	12 Months Ended
	Feb. 18, 2014	Feb. 29, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance			$ 3,194,797,000	$ 3,086,232,000	$ 2,580,409,000
Net current-period other comprehensive income (loss)			(78,692,000)	(96,937,000)	(51,271,000)
Shareholders' equity, ending balance			3,463,059,000	$ 3,194,797,000	3,086,232,000
Shareholders' Equity Other Disclosures [Abstract]
Debt and Equity Securities Authorized for Issuance			2,500,000,000.0
Debt And Equity Securities Available For Issuance			2,400,000,000
ATM Equity Distribution Offering Price Maximum Amount			$ 200,000,000
ATM Equity Distribution, Shares Issued			1,360,756
ATM Agent Commission Proceeds Percentage			1.00%
ATM Equity Distribution, Net Proceeds			$ 98,600,000
ATM Equity Distribution, Gross Proceeds			$ 100,000,000
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized			11,200,000.0	8,700,000.0
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized		2,500,000.0
Stock Issued During Period, Shares, New Issues	9,200,000
Shares Issued At Overallotment Option	1,200,000
Share Price	$ 44.00
Net proceeds from equity offering	$ 390,205,000		$ 98,574,000	$ 0	390,205,000
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance			4,949,000	7,662,000
Other comprehensive income (loss) before reclassifications			(263,000)	(2,173,000)
Amounts reclassified from accumulated other comprehensive income			(202,000)	(540,000)
Net current-period other comprehensive income (loss)			(465,000)	(2,713,000)
Shareholders' equity, ending balance			4,484,000	4,949,000	7,662,000
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance			(88,842,000)	(18,381,000)
Other comprehensive income (loss) before reclassifications			(99,029,000)	(71,003,000)
Amounts reclassified from accumulated other comprehensive income			347,000	542,000
Net current-period other comprehensive income (loss)			(98,682,000)	(70,461,000)
Shareholders' equity, ending balance			(187,524,000)	(88,842,000)	(18,381,000)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Commodity Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance			(25,437,000)	(1,674,000)
Other comprehensive income (loss) before reclassifications			(11,662,000)	(49,211,000)
Amounts reclassified from accumulated other comprehensive income			32,117,000	25,448,000
Net current-period other comprehensive income (loss)			20,455,000	(23,763,000)
Shareholders' equity, ending balance			(4,982,000)	(25,437,000)	(1,674,000)
Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance			(109,330,000)	(12,393,000)	38,878,000
Other comprehensive income (loss) before reclassifications			(110,954,000)	(122,387,000)
Amounts reclassified from accumulated other comprehensive income			32,262,000	25,450,000
Net current-period other comprehensive income (loss)			(78,692,000)	(96,937,000)	(51,271,000)
Shareholders' equity, ending balance			$ (188,022,000)	$ (109,330,000)	$ (12,393,000)

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Shareholders' Equity AOCI Affected Line Item in the Statement of Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance	$ (560,766)	$ (541,868)	$ (505,154)
Interest charges	(115,948)	(116,241)	(129,295)
Purchased gas cost	(1,605,053)	(2,462,119)	(3,358,490)
Income (loss) before income taxes	550,477	510,765	476,819
Income Tax Expense (Benefit)	(200,373)	(195,690)	$ (187,002)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (loss) from continuing operations	(32,262)	(25,450)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance	318	850
Income (loss) before income taxes	318	850
Income Tax Expense (Benefit)	(116)	(310)
Income (loss) from continuing operations	202	540
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before income taxes	(53,197)	(42,569)
Income Tax Expense (Benefit)	20,733	16,579
Income (loss) from continuing operations	(32,464)	(25,990)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Interest Rate Contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	(546)	(853)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Commodity Contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Purchased gas cost	$ (52,651)	$ (41,716)

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Retirement and Post-Retirement Employee Benefit Plans Defined Benefit Plans Disclosure (Details) - USD ($)
$ in Thousands

12 Months Ended

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Oct. 02, 2013

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2014

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided

15 years

Available-for-sale Securities, Supplemental Executive Benefit Plans

$ 41,300

$ 41,700

Pension and Other Postretirement Plans Costs [Member] | Unrecognized Transition Obligation [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

82

Pension and Other Postretirement Plans Costs [Member] | Unrecognized Prior Service Credit [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

(4,389)

(6,259)

Pension and Other Postretirement Plans Costs [Member] | Unrecognized Actuarial (Gain) Loss [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

124,288

110,714

Pension and Other Postretirement Plans Costs [Member] | Total Unrecognized in Net Periodic Pension Cost [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ 119,899

$ 104,537

Subsequent Event [Member]

Subsequent Event [Line Items]

Subsequent Event, Date

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Subsequent Event, Description

AEH entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. to sell all of the equity interests of AEM for $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. We expect this transaction to close during the second quarter of fiscal 2017.

the uncommitted $25 million 364-day bilateral credit facility was renewed through July 31, 2017.

the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table.

we amended our existing $1.25 billion unsecured credit facility (the five-year unsecured credit facility) which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021.

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract

Discount rate

4.55%

4.43%

4.95%

Rate of compensation increase

3.50%

3.50%

3.50%

Expected return on plan assets

7.00%

7.25%

7.25%

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract

Discount rate

3.73%

4.55%

Rate of compensation increase

3.50%

3.50%

Expected return on plan assets

7.00%

7.00%

Defined Benefit Plan Change In Benefit Obligation Roll Forward

Accumulated benefit obligation

$ 516,924

$ 485,921

Benefit obligation at beginning of year

508,599

493,594

Service cost

16,419

16,231

$ 15,345

Interest cost

23,193

21,850

22,330

Actuarial (gain) loss

41,847

7,420

Benefits paid

(44,578)

^[1]

(30,496)

Benefit obligation at end of year

545,480

508,599

$ 493,594

Funded Status of Plan Reconciliation

Funded status

(71,530)

(57,667)

Unrecognized prior service cost

0

0

Unrecognized net loss

0

0

Net amount recognized

(71,530)

$ (57,667)

Estimated Future Benefits Payment, Total

FY2017

31,306

FY2018

32,047

FY2019

33,674

FY2020

35,232

FY2021

37,279

2022-2026

202,442

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, One-Time Voluntary Pension Buyout

$ 12,800

Pension Plans, Defined Benefit [Member] | Minimum [Member]

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Investment Performance Review Period

3 years

Pension Plans, Defined Benefit [Member] | Maximum [Member]

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Investment Performance Review Period

5 years

Pension Plans, Defined Benefit [Member] | Domestic Equity Securities [Member]

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

35.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

55.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

40.50%

41.30%

Pension Plans, Defined Benefit [Member] | International Equity Securities [Member]

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

10.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

20.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

15.50%

14.90%

Pension Plans, Defined Benefit [Member] | Fixed Income Securities [Member]

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

5.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

30.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

11.20%

11.00%

Pension Plans, Defined Benefit [Member] | Company Stock [Member]

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

0.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

15.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

15.10%

15.20%

Number of shares of Atmos Energy common stock in Master Trust

956,700

1,169,700

Amount of dividend income from Atmos Energy common stock in Master Trust

$ 1,800

$ 1,800

Pension Plans, Defined Benefit [Member] | Other Investment Assets [Member]

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

0.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

20.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

17.70%

17.60%

Pension Plans, Defined Benefit [Member] | Pension Costs [Member] | Unrecognized Transition Obligation [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ 0

Pension Plans, Defined Benefit [Member] | Pension Costs [Member] | Unrecognized Prior Service Credit [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ (1,509)

(1,735)

Pension Plans, Defined Benefit [Member] | Pension Costs [Member] | Unrecognized Actuarial (Gain) Loss [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

127,028

120,948

Pension Plans, Defined Benefit [Member] | Pension Costs [Member] | Total Unrecognized in Net Periodic Pension Cost [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ 125,519

$ 119,213

Pension Account Plan, Defined Benefit [Member]

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Vesting Period

3 years

Supplemental Employee Retirement Plan [Member]

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract

Discount rate

4.55%

4.43%

4.95%

Rate of compensation increase

3.50%

3.50%

3.50%

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract

Discount rate

3.73%

4.55%

Rate of compensation increase

3.50%

3.50%

Defined Benefit Plan Change In Benefit Obligation Roll Forward

Accumulated benefit obligation

$ 137,616

$ 118,835

Benefit obligation at beginning of year

122,393

113,219

Service cost

2,371

3,971

$ 3,607

Interest cost

5,185

4,943

4,966

Actuarial (gain) loss

17,229

4,811

Benefits paid

(4,604)

(4,551)

Benefit obligation at end of year

142,574

122,393

113,219

Funded Status of Plan Reconciliation

Funded status

(142,574)

(122,393)

Unrecognized prior service cost

0

0

Unrecognized net loss

0

0

Net amount recognized

(142,574)

(122,393)

Estimated Future Benefits Payment, Total

FY2017

36,604

FY2018

14,289

FY2019

7,181

FY2020

4,395

FY2021

4,306

2022-2026

60,658

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Settlements

0

0

$ 4,539

Supplemental Employee Retirement Plan [Member] | Supplemental Executive Benefit Plan Costs [Member] | Unrecognized Transition Obligation [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

0

Supplemental Employee Retirement Plan [Member] | Supplemental Executive Benefit Plan Costs [Member] | Unrecognized Prior Service Credit [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

0

0

Supplemental Employee Retirement Plan [Member] | Supplemental Executive Benefit Plan Costs [Member] | Unrecognized Actuarial (Gain) Loss [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

51,558

36,915

Supplemental Employee Retirement Plan [Member] | Supplemental Executive Benefit Plan Costs [Member] | Total Unrecognized in Net Periodic Pension Cost [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ 51,558

$ 36,915

Supplemental Executive Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan Change In Benefit Obligation Roll Forward

Benefits paid

$ (16,800)

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Percent of Covered Compensation

75.00%

Defined Benefit Plan, Description of Settlements and Curtailments

On October 2, 2013, due to the retirement of one of our executives, we recognized a settlement loss of $4.5 million associated with our SEBP and made a $16.8 million benefit payment.

Settlements

$ 4,500

1998 Supplemental Executive Retirement Plan, Defined Benefit [Member]

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Percent of Covered Compensation

60.00%

2009 Supplemental Executive Retirement Plan, Defined Benefit [Member]

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract

Interest crediting rate

4.69%

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Vesting Period

3 years

Defined Benefit Plan, Age Attained

55 years

Defined Benefit Plan, Percent of Contributed Compensation

10.00%

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract

Discount rate

4.55%

4.43%

4.95%

Expected return on plan assets

4.45%

4.60%

4.60%

Initial Trend

7.50%

7.50%

8.00%

Ultimate trend rate

5.00%

5.00%

5.00%

Ultimate trend rate reached in

2021

2020

2020

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract

Discount rate

3.73%

4.55%

Expected return on plan assets

4.45%

4.45%

Initial trend rate

7.50%

7.50%

Ultimate trend rate

5.00%

5.00%

Ultimate trend reached in

2022

2021

Defined Benefit Plan Change In Benefit Obligation Roll Forward

Benefit obligation at beginning of year

$ 267,179

$ 315,118

Service cost

10,823

15,583

$ 16,784

Interest cost

12,424

14,385

15,951

Plan participants' contributions

4,289

4,563

Actuarial (gain) loss

(1,052)

(69,962)

Benefits paid

(14,441)

(12,508)

Benefit obligation at end of year

279,222

267,179

$ 315,118

Funded Status of Plan Reconciliation

Funded status

(120,245)

(129,170)

Unrecognized prior service cost

0

0

Unrecognized transition obligation

0

0

Unrecognized net loss

0

0

Net amount recognized

(120,245)

$ (129,170)

Estimated company benefit payments

FY2017

15,806

FY2018

11,602

FY2019

12,165

FY2020

13,246

FY2021

14,210

2022-2026

84,642

Estimated retiree benefit payments

FY2017

3,679

FY2018

3,992

FY2019

4,036

FY2020

4,756

FY2021

5,420

2022-2026

36,837

Disclosure Of Expected Gross Prescription Drug Subsidy Receipts Abstract

FY2017

0

FY2018

0

FY2019

0

FY2020

0

FY2021

0

2022-2026

0

Estimated Future Benefits Payment, Total

FY2017

19,485

FY2018

15,594

FY2019

16,201

FY2020

18,002

FY2021

19,630

2022-2026

121,479

Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates

Effect of One Percentage Point Increase on Service and Interest Cost Components

4,539

Effect of One Percentage Point Decrease on Service and Interest Cost Components

(3,596)

Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation

42,079

Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation

$ (34,531)

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Employer Claims Paid

80.00%

Defined Benefit Plan, Employee Paid Claims

20.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Minimum [Member]

Current Year Benefit Plan Contributions [Abstract]

Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year

$ 10,000

Other Postretirement Benefit Plans, Defined Benefit [Member] | Maximum [Member]

Current Year Benefit Plan Contributions [Abstract]

Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year

$ 20,000

Other Postretirement Benefit Plans, Defined Benefit [Member] | Diversified Investment Funds [Member]

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

97.20%

97.50%

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Plan, Funds Available for Investment in Common Stock and Convertible Securities

75.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Cash and Cash Equivalents [Member]

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations

2.80%

2.50%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Postretirement Benefit Costs [Member] | Unrecognized Transition Obligation [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ 82

Other Postretirement Benefit Plans, Defined Benefit [Member] | Postretirement Benefit Costs [Member] | Unrecognized Prior Service Credit [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ (2,880)

(4,524)

Other Postretirement Benefit Plans, Defined Benefit [Member] | Postretirement Benefit Costs [Member] | Unrecognized Actuarial (Gain) Loss [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

(54,298)

(47,149)

Other Postretirement Benefit Plans, Defined Benefit [Member] | Postretirement Benefit Costs [Member] | Total Unrecognized in Net Periodic Pension Cost [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Net Regulatory Assets

$ (57,178)

$ (51,591)

[1] Includes $12.8 million of one-time payments to eligible deferred vested participants who elected to receive a lump-sum payout of their pension benefits during fiscal 2016.

XML

Retirement and Post-Retirement Employee Benefit Plans Fair Value Disclosures (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Sep. 30, 2015
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		$ 72,701	$ 74,200
Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		38,677	40,619
Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	[1]	34,024	33,581
Fair Value Inputs Level 3 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		471,310	448,544
Fair value of accounts receivable		2,600	2,400
Pension Plans, Defined Benefit [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		157,111	159,304
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		11,522	11,787
Pension Plans, Defined Benefit [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		87,396	81,960
Pension Plans, Defined Benefit [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		105,124	93,081
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		15,223	14,359
Pension Plans, Defined Benefit [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		5,567	6,084
Pension Plans, Defined Benefit [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		31,929	28,973
Pension Plans, Defined Benefit [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		57,438	52,996
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		249,211	246,543
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		157,111	159,304
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		87,396	81,960
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		4,704	5,279
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		222,099	202,001
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		11,522	11,787
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		105,124	93,081
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		15,223	14,359
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		863	805
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		31,929	28,973
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		57,438	52,996
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		158,977	138,009
Other Postretirement Benefit Plans, Defined Benefit [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		4,470	3,486
Other Postretirement Benefit Plans, Defined Benefit [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		154,507	134,523
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		154,507	134,523
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		154,507	134,523
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		4,470	3,486
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		4,470	3,486
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Mutual Fund [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		$ 0	$ 0

[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.

XML

Retirement and Post-Retirement Employee Benefit Plans Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016		Sep. 30, 2015
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 450,932		$ 434,767
Actual return on plan assets	52,596		8,661
Employer contributions	15,000		38,000
Benefits paid	(44,578)	[1]	(30,496)
Fair value of plan assets at end of year	473,950		450,932
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	0		0
Employer contributions	4,604		4,551
Benefits paid	(4,604)		(4,551)
Fair value of plan assets at end of year	0		0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	138,009		134,821
Actual return on plan assets	14,528		(8,851)
Employer contributions	16,592		19,984
Plan participants' contributions	4,289		4,563
Benefits paid	(14,441)		(12,508)
Fair value of plan assets at end of year	$ 158,977		$ 138,009

[1] Includes $12.8 million of one-time payments to eligible deferred vested participants who elected to receive a lump-sum payout of their pension benefits during fiscal 2016.

XML

Retirement and Post-Retirement Employee Benefit Plans Net Periodic Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 16,419	$ 16,231	$ 15,345
Interest cost	23,193	21,850	22,330
Expected return on assets	(27,522)	(25,744)	(23,601)
Amortization of prior service cost	(226)	(192)	(136)
Recognized actuarial loss	10,693	13,322	13,777
Net periodic pension cost	22,557	25,467	27,715
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2,371	3,971	3,607
Interest cost	5,185	4,943	4,966
Amortization of transition asset	0	0	0
Amortization of prior service cost	0	0	0
Recognized actuarial loss	2,586	2,343	1,948
Settlements	0	0	4,539
Net periodic pension cost	10,142	11,257	15,060
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	10,823	15,583	16,784
Interest cost	12,424	14,385	15,951
Expected return on assets	(6,264)	(6,431)	(5,167)
Amortization of transition asset	82	272	274
Amortization of prior service cost	(1,644)	(1,644)	(1,450)
Recognized actuarial loss	(2,167)	0	631
Net periodic pension cost	$ 13,254	$ 22,165	$ 27,023

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Retirement and Post-Retirement Employee Benefit Plans Defined Contribution Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Retirement Savings Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	65.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%
Defined Contribution Plan, Employer Contribution Service Period Until Eligibility	1 year
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%
Defined Contribution Plan, Employer Discretionary Contribution Percent	4.00%
Defined Contribution Plan, Percent of Equity Securities Issued by Employer and Related Parties Included in Plan Assets	4.20%	4.30%
Defined Contribution Plan, Vesting Period	3 years
AEH 401K Profit-Sharing Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 300	$ 1,100	$ 1,400
Retirement Savings Plan and Union 401K Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	12,600	11,500	10,900
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 0	$ 0	$ 0

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Stock and Other Compensation Plans (Details) - USD ($)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Stock Based Compensation Expense	$ 24,600,000	$ 27,500,000	$ 25,500,000
Share-based Compensation, Capitalized Amount	9,800,000	11,500,000	10,800,000
Share Based Compensation, Tax Benefit	$ 5,000,000	$ 4,700,000	$ 3,100,000
Authorized Shares	11,200,000.0	8,700,000.0
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available	2,400,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Nonvested at beginning of year-Shares	878,104	988,637	1,052,844
Nonvested at beginning of year-Weighted Average	$ 48.24	$ 42.22	$ 36.20
Granted-Shares	357,323	444,543	464,438
Granted-Weighted Average	$ 65.98	$ 50.50	$ 45.05
Vested-Shares	(448,136)	(551,688)	(524,532)
Vested-Weighted Average	$ 45.88	$ 39.28	$ 32.67
Forfeited-Shares	(4,860)	(3,388)	(4,113)
Forfeited-Weighted Average	$ 53.52	$ 48.55	$ 39.00
Nonvested at end of year-Shares	782,431	878,104	988,637
Nonvested at end of year-Weighted Average	$ 57.66	$ 48.24	$ 42.22
Unrecognized Compensation Cost	$ 11,400,000
Weighted Average Recognized Period	1 year 7 months
Fair Value Restricted Stock Vested	$ 20,600,000	$ 21,700,000	$ 17,100,000
Direct Stock Purchse Plan [Abstract]
Minimum Initial Investment for Direct Stock Purchase Plan	1,250
Minimum Continuing Investment for Direct Stock Purchase Plan	25
Annual Maximum Investment for Direct Stock Purchase Plan	$ 100,000

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Details of Selected Consolidated Balance Sheet Captions (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2016		Sep. 30, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		$ 313,374		$ 310,443
Less: allowance for doubtful accounts		(13,367)		(15,283)
Net accounts receivable		300,007		295,160
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		9,804		9,232
Deferred gas cost		45,184		9,715
Taxes receivable		5,456		4,479
Prepaid expenses		23,053		23,055
Materials and supplies		5,825		12,587
Other		11,507		6,822
Total other current assets		100,829		65,890
Public Utilities, Property, Plant and Equipment [Abstract]
Production plant		66		131
Storage plant		353,523		286,011
Transmission plant		2,232,927		1,844,117
Distribution plant		6,598,990		6,019,001
General plant		761,057		769,311
Intangible plant		40,515		41,131
Property, plant and equipment		9,987,078		8,959,702
Construction in progress		184,062		280,398
Total property, plant and equipment and construction in progress		10,171,140		9,240,100
Less accumulated depreciation and amortization		(1,890,629)		(1,809,520)
Net property, plant and equipment	[1]	8,280,511		7,430,580
Plant acquisition adjustments		(59,800)		(68,100)
Goodwill [Line Items]
Goodwill, Beginning Balance		742,702
Goodwill, Other Changes	[2]	705
Goodwill, Ending Balance		743,407
Schedule of Other Noncurrent Assets [Abstract]
Marketable securities		72,701		74,200
Regulatory assets		214,890		182,573
Assets from risk management activities noncurrent		1,822		368
Other		15,872		18,343
Total		305,285		275,484
Schedule of Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable		114,533		78,534
Accrued gas payable		108,526		119,825
Accrued liabilities		36,375		40,583
Total		259,434		238,942
Schedule of Other Current Liabilities [Abstract]
Customer deposits		81,890		100,232
Accrued employee costs		47,058		47,602
Deferred gas costs		20,180		28,100
Accrued interest		34,863		34,914
Liabilities from risk management activities current		56,771		9,568
Taxes payable		104,457		93,674
Pension and postretirement obligations		36,606		21,857
Regulatory cost of removal accrual		52,610		56,123
Current deferred tax liability		0		55,918
Other		14,601		9,966
Total		449,036		457,954
Schedule of Other Noncurrent Liabilities [Abstract]
Customer advances for construction		9,850		9,316
Regulatory liabilities		4,152		3,693
Asset retirement obligation		13,404		9,063
Liabilities from risk management activities noncurrent		184,048		110,539
Other		34,236		29,085
Total		245,690		161,696
Regulated Distribution Segment [Member]
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		3,029		378
Public Utilities, Property, Plant and Equipment [Abstract]
Net property, plant and equipment		6,220,425		5,670,306
Goodwill [Line Items]
Goodwill, Beginning Balance		575,449
Goodwill, Other Changes	[2]	665
Goodwill, Ending Balance		576,114
Schedule of Other Noncurrent Assets [Abstract]
Assets from risk management activities noncurrent		1,822		368
Schedule of Other Current Liabilities [Abstract]
Liabilities from risk management activities current		56,771		9,568
Schedule of Other Noncurrent Liabilities [Abstract]
Liabilities from risk management activities noncurrent		184,048		110,539
Regulated Pipeline Segment [Member]
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		0		0
Public Utilities, Property, Plant and Equipment [Abstract]
Net property, plant and equipment		2,008,997		1,706,449
Goodwill [Line Items]
Goodwill, Beginning Balance		132,542
Goodwill, Other Changes	[2]	40
Goodwill, Ending Balance		132,582
Schedule of Other Noncurrent Assets [Abstract]
Assets from risk management activities noncurrent		0		0
Schedule of Other Current Liabilities [Abstract]
Liabilities from risk management activities current		0		0
Schedule of Other Noncurrent Liabilities [Abstract]
Liabilities from risk management activities noncurrent		0		0
Nonregulated Segment [Member]
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		6,775	[3]	8,854	[4]
Public Utilities, Property, Plant and Equipment [Abstract]
Net property, plant and equipment		51,089		53,825
Goodwill [Line Items]
Goodwill, Beginning Balance		34,711
Goodwill, Other Changes	[2]	0
Goodwill, Ending Balance		34,711
Schedule of Other Noncurrent Assets [Abstract]
Assets from risk management activities noncurrent		0		0
Schedule of Other Current Liabilities [Abstract]
Liabilities from risk management activities current		0	[3]	0	[4]
Schedule of Other Noncurrent Liabilities [Abstract]
Liabilities from risk management activities noncurrent		0	[3]	0	[4]
Trade Accounts Receivable [Member] | Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		206,248		204,585
Trade Accounts Receivable [Member] | Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		67,396		65,008
Other Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		$ 39,730		$ 40,850

[1] Net property, plant and equipment includes plant acquisition adjustments of $(59.8) million and $(68.1) million at September 30, 2016 and 2015.

[2] We annually adjust certain deferred taxes recorded in connection with acquisitions completed in fiscal 2001 and fiscal 2004, which resulted in an increase to goodwill and net deferred tax liabilities of $0.7 million for fiscal 2016.

[3] ncludes $24.7 million of cash held on deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

[4] Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

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Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2017	$ 17,073
2018	16,824
2019	15,450
2020	14,479
2021	14,335
Operating Leases, Thereafter	47,714
Total Operating Lease Payments	125,875
Lease and Rental Expense	$ 32,600	$ 32,500	$ 31,700
Minimum [Member]
Operating Leased Assets [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	1 year
Maximum [Member]
Operating Leased Assets [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	18 years

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Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2016 USD ($) $ / MMcf MMcf	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
Estimated Contractual Demand Fees [Abstract]
2017	$ 9,065
2018	2,336
2019	424
2020	400
2021	327
Thereafter	678
Total Estimated Contractual Demand Fees	13,230
Mid-Tex Division [Member]
Long Term Purchase Commitment [Line Items]
Significant Purchase Commitment, Amount	85,300	$ 113,300	$ 140,900
Nonregulated Segment [Member]
Long Term Purchase Commitment [Line Items]
Significant Purchase Commitment, Amount	$ 763,200	$ 1,141,300	$ 1,687,500
Inventories Under Indexed Contracts [Member] | Mid-Tex Division [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year | MMcf	28,500
Long Term Purchase Commitment Minimum Quantity Required One To Three Years | MMcf	4,200
Long Term Purchase Commitment Minimum Quantity Required After Three Years | MMcf	600
Inventories Under Indexed Contracts [Member] | Nonregulated Segment [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year | MMcf	93,500
Long Term Purchase Commitment Minimum Quantity Required One To Three Years | MMcf	9,100
Long Term Purchase Commitment Minimum Quantity Required After Three Years | MMcf	200
Inventories Under Fixed Price Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year | MMcf	11,900
Inventories Under Fixed Price Contracts [Member] | Nonregulated Segment [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required One To Three Years | MMcf	1,300
Purchase Commitment Amount Minimum | $ / MMcf	0.25
Purchase Commitment Amount Maximum | $ / MMcf	3.16

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Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Current income taxes
Federal	$ 0	$ 0	$ 0
State	6,822	7,251	5,527
Deferred income taxes
Federal	181,790	175,897	169,106
State	11,766	12,548	12,375
Investment tax credits	(5)	(6)	(6)
Income tax expense	200,373	195,690	187,002
Deferred tax assets
Employee benefit plans	122,682	121,619
Interest rate agreements	107,782	51,067
Tax net operating loss carryforwards	514,391	313,224
Tax credit carryforward	22,273	22,281
Other	23,648	36,695
Total deferred tax assets	790,776	544,886
Valuation allowance	(10,481)	(10,872)
Net deferred tax assets	780,295	534,014
Deferred tax liabilities
Difference in net book value and net tax value of assets	(2,259,278)	(1,890,886)
Pension funding	(30,652)	(35,247)
Gas Cost Adjustments	(54,725)	(43,634)
Other	(38,696)	(31,480)
Total deferred tax liabilities	(2,383,351)	(2,001,247)
Net deferred tax liabilities	(1,603,056)	(1,467,233)
Deferred credits for rate regulated entities	861	412
Deferred Tax Assets, Charitable Contribution Carryforwards [Abstract]
Deferred Tax Assets, Charitable Contribution Carryforwards	$ 11,000
Charitable Contribution Carryforwards, Expiration Date, Minimum	Dec. 31, 2017
Charitable Contribution Carryforwards, Expiration Date, Maximum	Dec. 31, 2021
Valuation and Qualifying Accounts Disclosure [Line Items]
Expiration of Deferred Tax Assets	$ 200
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	17,069	12,629
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions		1,009
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(290)
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	3,519	3,431
Unrecognized Tax Benefits, Ending Balance	20,298	17,069	$ 12,629
Unrecognized Tax Benefits, Deferred Federal and State Income Tax Benefits	(7,104)	(5,974)
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	13,194	11,095
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	2,500	500
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	3,300	800
Valuation Allowance of Deferred Tax Assets [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Charged to Cost and Expense	1,100	$ 5,000
Valuation Allowances and Reserves, Deductions	1,400
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	20,400
Operating Loss Carryforwards, Federal Tax Effects	$ 11,000
State and Local Jurisdiction [Member] | Minimum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2017
State and Local Jurisdiction [Member] | Maximum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2031
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 494,000
Domestic Tax Authority [Member] | Minimum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029

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Income Taxes Tax Credit Carryforwards (Details) $ in Millions	Sep. 30, 2016 USD ($)
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 1.1
Domestic Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 10.1

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Income Taxes Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Tax at statutory rate of 35%	$ 192,667	$ 178,768	$ 166,887
Common stock dividends deductible for tax reporting	(2,570)	(2,413)	(2,307)
State taxes (net of federal benefit)	11,504	12,869	11,636
Change in valuation allowance	1,324	4,998	6,969
Other, net	(2,552)	1,468	3,817
Income tax expense (benefit)	$ 200,373	$ 195,690	$ 187,002

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Financial Instruments Financial Instruments at Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2016		Sep. 30, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Current	$ 9,804		$ 9,232
Derivative Asset, Noncurrent	1,822		368
Derivative Liability, Current	(56,771)		(9,568)
Derivative Liability, Noncurrent	(184,048)		(110,539)
Derivative Assets (Liabilities), at Fair Value, Net	(229,193)		(110,507)
Regulated Distribution Segment [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Current	3,029		378
Derivative Asset, Noncurrent	1,822		368
Derivative Liability, Current	(56,771)		(9,568)
Derivative Liability, Noncurrent	(184,048)		(110,539)
Derivative Assets (Liabilities), at Fair Value, Net	(235,968)		(119,361)
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities	25,670		0
Cash Held In Margin Accounts Classified Current Risk Management Asset	0		0
Nonregulated Segment [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Current	6,775	[1]	8,854	[2]
Derivative Asset, Noncurrent	0		0
Derivative Liability, Current	0	[1]	0	[2]
Derivative Liability, Noncurrent	0	[1]	0	[2]
Derivative Assets (Liabilities), at Fair Value, Net	6,775		8,854
Cash Held in Margin Accounts	24,700		43,500
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities	17,905		34,620
Cash Held In Margin Accounts Classified Current Risk Management Asset	$ 6,775		$ 8,854

[1] ncludes $24.7 million of cash held on deposit to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $6.8 million is classified as current risk management assets.

[2] Includes $43.5 million of cash held on deposit to collateralize certain nonregulated 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.

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Financial Instruments Balance Sheet Location (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Sep. 30, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset	$ 11,626	$ 9,600
Derivative Liability	(240,819)	(120,107)
Regulated Distribution Segment [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,851	746
Derivative Asset, Contract Netting	0	0
Derivative Asset, Net of Contract Netting	4,851	746
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Asset	4,851	746
Derivative Liability, Fair Value, Gross Liability	(266,489)	(120,107)
Derivative Liability, Contract Netting	0	0
Derivative Liability, Net of Contract Netting	(266,489)	(120,107)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	25,670	0
Derivative Liability	(240,819)	(120,107)
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(266,489)	(110,539)
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(68,481)
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(198,008)	(110,539)
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,851	746
Derivative Liability, Fair Value, Gross Liability	0	(9,568)
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,029	378
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,822	368
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(9,568)
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Nonregulated Segment [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	39,290	91,363
Derivative Asset, Contract Netting	(39,290)	(91,363)
Derivative Asset, Net of Contract Netting	0	0
Derivative, Collateral, Right to Reclaim Cash	6,775	8,854
Derivative Asset	6,775	8,854
Derivative Liability, Fair Value, Gross Liability	(57,195)	(125,983)
Derivative Liability, Contract Netting	39,290	91,363
Derivative Liability, Net of Contract Netting	(17,905)	(34,620)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	17,905	34,620
Derivative Liability	0	0
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,790	11,806
Derivative Liability, Fair Value, Gross Liability	(25,682)	(45,985)
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,612	11,680
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,178	126
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(21,903)	(36,067)
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,779)	(9,918)
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	0
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	30,500	79,557
Derivative Liability, Fair Value, Gross Liability	(31,513)	(79,998)
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,157	65,239
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,343	14,318
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(18,812)	(65,780)
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (12,701)	$ (14,218)

XML

Financial Instruments Descriptions (Details) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2014 USD ($)	Sep. 30, 2016 USD ($) $ / Mcf MMcf	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Minimum Hedge Percentage Of Anticipated Heating Season Gas		25.00%
Maximum Hedge Percentage Of Anticipated Heating Season Gas		50.00%
Hedge Percentage Of Actual Heating Season Gas		33.00%
Hedge Volume Of Actual Heating Season Gas | MMcf		23,000
Weighted Average Cost Of Actual Heating Season Gas | $ / Mcf		3.14
Minimum Length Of Time Hedged In Cash Flow Hedge		1 month
Maximum Length of Time Hedged in Cash Flow Hedge		63 months
Net Open Positions | MMcf		100
Gain (Loss) On Hedge Ineffectiveness		$ 21.6	$ 0.2	$ 1.9
Regulated Segments Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate		37.00%	37.00%
Nonregulated Segment Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate		39.00%	39.00%
Gain (Loss) On Derivative Instruments Not Designated Hedges Net Pretax		$ (15.5)	$ 15.5	$ (5.0)
Interest Rate Hedges, Senior Notes 2015 Issuance [Member]
Derivative [Line Items]
Derivative, Notional Amount		500.0
Derivative, Cash Received on Hedge	$ 13.4
Interest Rate Hedges, Senior Notes 2017 Issuance [Member]
Derivative [Line Items]
Derivative, Notional Amount		210.0
Anticipated Debt Issuance, Amount		250.0
Interest Rate Hedges, Senior Notes 2019 Issuance [Member]
Derivative [Line Items]
Derivative, Notional Amount		450.0
Anticipated Debt Issuance, Amount		$ 450.0

XML

Financial Instruments Commodity Contract Volumes (Details)	Sep. 30, 2016 MMcf
Regulated Distribution Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	18,595
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	18,595
Regulated Distribution Segment [Member] | Fair Value Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	0
Regulated Distribution Segment [Member] | Cash Flow Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	0
Nonregulated Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	91,030
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	71,147
Nonregulated Segment [Member] | Fair Value Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	(19,395)
Nonregulated Segment [Member] | Cash Flow Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	39,278

XML

Financial Instruments Fair Value Hedges and Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Effect of Fair Value Hedges on Results of Operations [Abstract]
Commodity contracts	$ 3,516	$ 10,311	$ (792)
Fair value adjustment for natural gas inventory designated as the hedged item	18,079	(9,768)	2,486
Total (increase) decrease in purchased gas cost	21,595	543	1,694
Fair Value Hedge Basis Ineffectiveness	(1,390)	811	(919)
Fair Value Hedge Timing Ineffectiveness	22,985	(268)	2,613
Cash Flow Hedge [Line Items]
Gain (loss) reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	(52,651)	(41,716)	8,365
Gain (loss) arising from ineffective portion of commodity contracts	(19)	(325)	198
Total impact on purchased gas cost	(52,670)	(42,041)	8,563
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	(546)	(853)	(4,230)
Total Impact from Cash Flow Hedges	(53,216)	(42,894)	4,333
Regulated Distribution Segment [Member]
Cash Flow Hedge [Line Items]
Gain (loss) reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	0	0	0
Gain (loss) arising from ineffective portion of commodity contracts	0	0	0
Total impact on purchased gas cost	0	0	0
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	(546)	(853)	(4,230)
Total Impact from Cash Flow Hedges	(546)	(853)	(4,230)
Nonregulated Segment [Member]
Cash Flow Hedge [Line Items]
Gain (loss) reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	(52,651)	(41,716)	8,365
Gain (loss) arising from ineffective portion of commodity contracts	(19)	(325)	198
Total impact on purchased gas cost	(52,670)	(42,041)	8,563
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	0	0	0
Total Impact from Cash Flow Hedges	$ (52,670)	$ (42,041)	$ 8,563

XML

Financial Instruments Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Other Comprehensive Income [Abstract]
Interest rate agreements fair value		$ (99,029)	$ (71,003)
Forward commodity contracts fair value		(11,662)	(49,211)
Interest rate agreements		347	542
Forward commodity contracts		32,117	25,448
Total other comprehensive income (loss) from hedging, net of tax	[1]	(78,227)	(94,224)
Expected Earnings [Line Items]
FY2017		(4,430)
FY2018		(1,210)
FY2019		(1,087)
FY2020		(724)
FY2021		(696)
Thereafter		(15,139)
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	(23,286)
Interest Rate Contract [Member]
Other Comprehensive Income [Abstract]
Total other comprehensive income (loss) from hedging, net of tax		(98,682)	(70,461)	$ (56,287)
Expected Earnings [Line Items]
FY2017		(447)
FY2018		(649)
FY2019		(673)
FY2020		(698)
FY2021		(698)
Thereafter		(15,139)
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	(18,304)
Commodity Contract [Member]
Other Comprehensive Income [Abstract]
Total other comprehensive income (loss) from hedging, net of tax		20,455	$ (23,763)	$ 2,802
Expected Earnings [Line Items]
FY2017		(3,983)
FY2018		(561)
FY2019		(414)
FY2020		(26)
FY2021		2
Thereafter		0
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	$ (4,982)

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

[2] Utilizing an income tax rate ranging from approximately 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

XML

Fair Value Measurements (Details) - USD ($)		Sep. 30, 2016		Sep. 30, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		$ (32,515,000)	[1]	$ (82,509,000)	[2]
Derivative Asset		11,626,000		9,600,000
Hedged portion of gas stored underground		52,578,000		43,901,000
Available-for-sale Securities		72,701,000		74,200,000
Total assets		136,905,000		127,701,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(82,865,000)	[1]	(125,983,000)	[2]
Derivative Liability		240,819,000		120,107,000
Additional Fair Value Elements [Abstract]
Debt Instrument Carrying Amount		2,460,000,000		2,460,000,000
Debt Instrument Fair Value		2,844,990,000
Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		2,630,000		1,072,000
Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		38,677,000		40,619,000
Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		31,394,000		32,509,000
Regulated Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		0	[1]	0	[2]
Derivative Asset		4,851,000		746,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(25,670,000)	[1]	0	[2]
Derivative Liability		240,819,000		120,107,000
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities		25,670,000		0
Cash Held In Margin Accounts Classified Current Risk Management Asset		0		0
Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(32,515,000)	[1]	(82,509,000)	[2]
Derivative Asset		6,775,000		8,854,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(57,195,000)	[1]	(125,983,000)	[2]
Derivative Liability		0		0
Cash Held in Margin Accounts		24,700,000		43,500,000
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities		17,905,000		34,620,000
Cash Held In Margin Accounts Classified Current Risk Management Asset		6,775,000		8,854,000
Fair Value Inputs Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Hedged portion of gas stored underground		52,578,000		43,901,000
Available-for-sale Securities		38,677,000		40,619,000
Total assets		91,255,000		84,520,000
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		0
Fair Value Inputs Level 1 [Member] | Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		0		0
Fair Value Inputs Level 1 [Member] | Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		38,677,000		40,619,000
Fair Value Inputs Level 1 [Member] | Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		0		0
Fair Value Inputs Level 1 [Member] | Regulated Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		0
Fair Value Inputs Level 1 [Member] | Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		0
Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement	[3]	44,141,000		92,109,000
Hedged portion of gas stored underground	[3]	0		0
Available-for-sale Securities	[3]	34,024,000		33,581,000
Total assets	[3]	78,165,000		125,690,000
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	323,684,000		246,090,000
Fair Value Inputs Level 2 [Member] | Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	[3]	2,630,000		1,072,000
Fair Value Inputs Level 2 [Member] | Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	[3]	0		0
Fair Value Inputs Level 2 [Member] | Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	[3]	31,394,000		32,509,000
Fair Value Inputs Level 2 [Member] | Regulated Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement	[3]	4,851,000		746,000
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	266,489,000		120,107,000
Fair Value Inputs Level 2 [Member] | Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement	[3]	39,290,000		91,363,000
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	57,195,000		125,983,000
Fair Value Inputs Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Hedged portion of gas stored underground		0		0
Available-for-sale Securities		0		0
Total assets		0		0
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		0
Fair Value Inputs Level 3 [Member] | Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		0		0
Fair Value Inputs Level 3 [Member] | Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		0		0
Fair Value Inputs Level 3 [Member] | Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		0		0
Fair Value Inputs Level 3 [Member] | Regulated Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		0
Fair Value Inputs Level 3 [Member] | Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement		0		0
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		$ 0		$ 0

[1] 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, 2016, we had $25.7 million of cash held in margin accounts to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. As of September 30, 2016 we also had $24.7 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $17.9 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $6.8 million is classified as current risk management assets.

[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 September 30, 2015 we had $43.5 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $8.9 million is classified as current risk management assets.

[3] Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

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Fair Value Measurements Available-For-Sale Securities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Sep. 30, 2015
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 65,572	$ 66,399
Gross Unrealized Gain	7,729	8,343
Gross Unrealized Loss	(600)	(542)
Fair value	72,701	74,200
Available-for-sale Securities, Other Disclosure Items [Abstract]
Available-for-sale Securities, Supplemental Executive Benefit Plans	41,300	41,700
Equity Funds Domestic [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	26,692	27,643
Gross Unrealized Gain	6,419	7,332
Gross Unrealized Loss	(590)	(456)
Fair value	32,521	34,519
Equity Funds Foreign [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	4,954	5,261
Gross Unrealized Gain	1,202	905
Gross Unrealized Loss	0	(66)
Fair value	6,156	6,100
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	31,296	32,423
Gross Unrealized Gain	108	106
Gross Unrealized Loss	(10)	(20)
Fair value	31,394	32,509
Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	2,630	1,072
Gross Unrealized Gain	0	0
Gross Unrealized Loss	0	0
Fair value	$ 2,630	$ 1,072

XML

Subsequent Events (Details) - USD ($)
$ in Millions

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Sep. 30, 2016

Subsequent Event [Member]

Subsequent Event [Line Items]

Subsequent Event, Date

Oct. 29, 2016

Oct. 25, 2016

Oct. 20, 2016

Oct. 05, 2016

Subsequent Event, Description

AEH entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. to sell all of the equity interests of AEM for $40.0 million plus working capital at the date of closing. No material gain or loss is currently anticipated in connection with the closing of this transaction. We expect this transaction to close during the second quarter of fiscal 2017.

the uncommitted $25 million 364-day bilateral credit facility was renewed through July 31, 2017.

the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States.  As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table.

we amended our existing $1.25 billion unsecured credit facility (the five-year unsecured credit facility) which increased the committed loan to $1.5 billion and extended the facility through September 25, 2021.

Atmos Energy Marketing [Member]

Disposal Group, Including Discontinued Operation, Liabilities [Abstract]

Disposal Group, Including Discontinued Operation, Consideration

$ 40.0

Atmos Energy Marketing [Member] | Disposal Group, Not Discontinued Operations [Member]

Disposal Group, Including Discontinued Operation, Assets [Abstract]

Net property, plant and equipment

13.0

Accounts receivable

94.0

Gas stored underground

56.0

Other current assets

13.0

Goodwill

15.0

Deferred charges and other assets

0.3

Total assets included in disposal group

191.3

Disposal Group, Including Discontinued Operation, Liabilities [Abstract]

Accounts payable and accrued liabilities

71.0

Other current liabilities

8.0

Deferred credits and other

0.2

Total liabilities included in disposal group

$ 79.2

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Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues by Segment [Line Items]
Operating revenues	$ 678,519	$ 632,916	$ 1,132,293	$ 906,221	$ 656,902	$ 686,401	$ 1,540,068	$ 1,258,765	$ 3,349,949	$ 4,142,136	$ 4,940,916
Selected Quarterly Financial Information [Abstract]
Gross profit	376,011	407,311	517,811	443,763	354,321	381,673	520,738	423,285	1,744,896	1,680,017	1,582,426
Operating income	84,633	137,164	250,016	196,205	75,853	117,607	250,210	187,725	668,018	631,395	611,349
Net income	$ 34,240	$ 71,193	$ 141,810	$ 102,861	$ 23,515	$ 56,281	$ 137,684	$ 97,595	$ 350,104	$ 315,075	$ 289,817
Income per share - basic (usd per share)									$ 3.38	$ 3.09	$ 2.96
Net income per share — basic (usd per share)	$ 0.33	$ 0.69	$ 1.38	$ 1.00	$ 0.23	$ 0.55	$ 1.35	$ 0.96	3.38	3.09	2.96
Net income per share — diluted (usd per share)	$ 0.33	$ 0.69	$ 1.38	$ 1.00	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 3.38	$ 3.09	$ 2.96
Regulated Distribution Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	$ 389,353	$ 414,226	$ 849,685	$ 638,602	$ 369,656	$ 416,794	$ 1,130,613	$ 846,772	$ 2,291,866	$ 2,763,835	$ 3,061,546
Selected Quarterly Financial Information [Abstract]
Gross profit									1,272,805	1,237,577	1,176,515
Operating income									439,584	420,149	384,568
Net income									232,370	204,813	171,585
Regulated Pipeline Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	109,204	109,249	95,703	94,677	97,807	97,008	91,730	83,567	408,833	370,112	318,459
Selected Quarterly Financial Information [Abstract]
Gross profit									408,833	370,112	318,459
Operating income									199,434	181,267	172,819
Net income									101,689	94,662	86,191
Nonregulated Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	291,889	214,555	287,395	272,524	292,830	278,769	438,322	462,288	1,066,363	1,472,209	2,067,292
Selected Quarterly Financial Information [Abstract]
Gross profit									63,790	72,860	87,955
Operating income									29,000	29,979	53,962
Net income									16,045	15,600	32,041
Intersegment Elimination [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	$ (111,927)	$ (105,114)	$ (100,490)	$ (99,582)	$ (103,391)	$ (106,170)	$ (120,597)	$ (133,862)	(417,113)	(464,020)	(506,381)
Selected Quarterly Financial Information [Abstract]
Gross profit									(532)	(532)	(503)
Operating income									0	0	0
Net income									$ 0	$ 0	$ 0

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Valuation and Qualifying Accounts (Details) - Allowance For Doubtful Accounts Member - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		$ 15,283	$ 23,992	$ 20,624
Charged to costs & expenses		10,397	15,082	19,491
Charged to other accounts		0	0	0
Valuation Allowances and Reserves, Deductions	[1]	12,313	23,791	16,123
Balance at end of period		$ 13,367	$ 15,283	$ 23,992

[1] Uncollectible accounts written off.