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, 2015

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.    ¨

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, 2015, was $5,500,632,050.

As of October 30, 2015, the registrant had 101,506,645 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 3, 2016 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	17
Item 2.	Properties	17
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	19
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	97
Item 9A.	Controls and Procedures	97
Item 9B.	Other Information	99
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	99
Item 11.	Executive Compensation	100
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	100
Item 13.	Certain Relationships and Related Transactions, and Director Independence	100
Item 14.	Principal Accountant Fees and Services	100
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	100

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 seven years, we have achieved growth by implementing rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved margins from customer usage patterns. In addition, we have developed various commercial opportunities within our regulated transmission and storage operations.

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, 2015, we held 1,005 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	1,629,826
Kentucky/Mid-States	Kentucky	230	180,033
	Tennessee		141,141
	Virginia		23,567
Louisiana	Louisiana	300	356,579
West Texas	Amarillo, Lubbock, Midland	80	305,814
Mississippi	Mississippi	110	266,467
Colorado-Kansas	Colorado	170	115,048
	Kansas		132,837

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 2015 were Anadarko Energy Services Company, ConocoPhillips Company, Devon Gas Services, L.P., Enbridge Marketing (US) Inc., Hydrocarbon Exchange Corporation, Munich Re Trading Ltd, Targa Gas Marketing LLC,

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Targa Pipeline Mid-Continent WestTex LLC, Tenaska Gas Storage, LLC, Texla Energy Management, Inc. and Atmos Energy Marketing, LLC and Trans Louisiana Gas Pipeline, Inc., 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 2015 was on January 7, 2015, when sales to customers reached approximately 3.2 Bcf.

Currently, our distribution divisions, except for our Mid-Tex Division, utilize 35 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.

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 anticipate no problems with obtaining additional gas supply as needed for our customers.

Regulated Pipeline Segment Overview

Our regulated pipeline segment consists of the pipeline and storage operations of our Atmos Pipeline - Texas Division (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 Permian Basin of West Texas. APT’s primary business is providing firm transportation and storage services for our Mid-Tex Division and other LDC customers. APT also provides interruptible transportation, storage and ancillary services for third parties including, industrial and electric generation customers as well as producers, marketers and other shippers.. The regulated pipeline segment represents approximately 30 percent of our consolidated operations.

Gross profit earned from transportation and storage services for our Atmos Pipeline - Texas Division is subject to traditional ratemaking governed by the RRC. Rates are updated through annual filings made under Texas’ Gas Reliability Infrastructure Program (GRIP) and Rider REV. GRIP allows us to include in our rates annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years. Atmos Pipeline-Texas’ existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates. Rider REV is an annual adjustment mechanism that adjusts the regulated rates for a portion of the variation in non-regulated annual revenues from a set base level.

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:

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

• Infrastructure programs in place in four of our states that provide for an annual rate adjustment to rates.

• Implemented various rate mechanisms that allow us to recover over 90 percent of our capital expenditures are recovered 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	04/08/2015	533,774(2)	9.36%	N/A	11.80%
Colorado-Kansas	Colorado	08/26/2014	111,297	8.04%	48/52	9.72%
	Kansas	09/04/2014	177,563	7.75%	47/53	9.10%
	Kansas-GSRS	02/01/2015	2,708	7.75%	N/A	9.10%
Kentucky/Mid-States	Kentucky	04/22/2014	252,738	7.71%	51/49	9.80%
	Kentucky-PRP	10/10/2014	35,382	7.71%	N/A	9.80%
	Tennessee	06/01/2015	247,958	7.73%	47/53	9.80%
	Virginia	09/09/2014	37,456	7.94%	46/54	9.00% - 10.00%
	Virginia-SAVE	10/01/2014	3,896	7.94%	N/A	9.00% - 10.00%
Louisiana	Trans La	04/01/2015	117,462	7.79%	47/53	9.80%
	LGS	07/01/2015	326,875	7.91%	46/54	9.80%
Mid-Tex Cities	Texas	06/01/2015	1,955,948(3)	8.43%	45/55	10.50%
Mid-Tex — Dallas	Texas	06/01/2015	1,935,160(3)	8.33%	46/54	10.10%
Mississippi	Mississippi	02/03/2015	322,610	8.26%	45/55	9.98%
	Mississippi - SGR	11/01/2014	8,960	9.37%	N/A	12.00%
West Texas(5)	Texas	03/15/2015	(4)	8.44%	(4)	10.50%
	Texas-GRIP	04/28/2015	379,303	8.57%	48/52	10.50%

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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	Pending(8)	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

⁽¹⁾  The rate base, authorized rate of return and authorized return on equity presented in this table are those from the most recent rate case or GRIP 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⁾  The APT rate base represents the incremental rate base from the 2011 APT filing.

⁽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.

⁽⁸⁾  The Company and intervenors have entered into a settlement agreement, approved on October 23, 2015, for implementation of an Infrastructure Mechanism effective January 1, 2016.

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, 2015, 2014 and 2013 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 $114.5 million, $93.3 million and $98.1 million, became effective in fiscal 2015, 2014 and 2013, as summarized below:

	Annual Increase to Operating Income For the Fiscal Year Ended September 30
Rate Action	2015		2014			2013
	(In thousands)
Annual formula rate mechanisms	$	113,706	$	71,749		$	40,088
Rate case filings	711		21,819			56,700
Other ratemaking activity	78		(226		)	1,322
	$	114,495	$	93,342		$	98,110

Additionally, the following ratemaking efforts were initiated during fiscal 2015 but had not been completed as of September 30, 2015:

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Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Rate Case(1)	Colorado	$	5,276
	Rate Case	Kansas	5,667
Kentucky/Mid-States	PRP(2)	Kentucky	3,786
	PRP (3)	Virginia	118
Mississippi	SRF	Mississippi	11,186
	SGR (4)	Mississippi	249
			$	26,282

⁽¹⁾  A Stipulation and Settlement was signed on September 23, 2015.  The settlement was approved on October 23, 2015 resulting in an operating income increase of $2.1 million and authorization to implement a long-term program to replace aging infrastructure in Colorado.  The base rate change and infrastructure surcharge will go into effect on January 1, 2016.

⁽²⁾  The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure. The Kentucky PRP was implemented on October 1, 2015.

⁽³⁾  The PRP surcharge relates to a long-term program to replace aging infrastructure. The Virginia PRP was implemented on October 1, 2015.

⁽⁴⁾  The Mississippi Supplemental Growth Rider (SGR) permits the Company to pursue up to $5.0 million of eligible industrial growth projects beyond the division's normal main extension policies. This is the third year of the SGR program.

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 periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi, and Tennessee operations and in a portion of our Texas divisions. The formula rate filing mechanism is referred to as Dallas annual rate review (DARR) and rate review mechanisms (RRM) in our Mid-Tex Division, as the RRM in our West Texas Division, as the stable rate filing (SRF) in the Mississippi Division, the rate stabilization clause (RSC) in the Louisiana Division, and Annual Rate Mechanism (ARM) in Tennessee.

Additionally, we have specific infrastructure programs in substantially all of our distribution divisions and our Atmos Pipeline - Texas Division, Colorado, Kansas, Kentucky, Mississippi, Texas and Virginia distribution operations have 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. These infrastructure programs are referred to as System Safety and Integrity Rider in Colorado (SSIR), Gas System Reliability Surcharge (GSRS) in Kansas, Pipeline Replacement Program (PRP) in Kentucky, System Integrity Rider in Mississippi (SIR), Gas Infrastructure Reliability Program (GRIP) and Steps to Advance Virginia Energy (SAVE). The following table summarizes our annual filing mechanisms with effective dates during the fiscal years ended September 30, 2015, 2014 and 2013:

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Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
			(In thousands)
2015 Filings:
Louisiana	LGS	12/2014	$	1,321		07/01/2015
West Texas	Environs(1)	12/2014	697			06/12/2015
Mid-Tex	Environs(2)	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(3)	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 (4)	09/2015	4,382			10/10/2014
Kentucky/Mid-States - Virginia	Virginia	09/2015	133			10/01/2014
Mid-Tex	Mid-Tex Cities(5)	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(1)	12/2013	858			06/17/2014
Mid-Tex	City of Dallas	09/2013	5,638			06/01/2014
Mid-Tex	Environs(2)	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
Kentucky/Mid-States	Virginia	09/2014	210			10/01/2013
Mid-Tex	Environs(2)	12/2012	768			10/01/2013
Total 2014 Filings			$	71,749
2013 Filings:
Louisiana	LGS	12/2012	$	908		07/01/2013
Mid-Tex	City of Dallas	09/2012	1,800			06/01/2013
Atmos Pipeline — Texas	Texas	12/2012	26,730			05/07/2013
Louisiana	TransLa	09/2012	2,260			04/01/2013
Kentucky/Mid-States	Georgia(6)	09/2013	743			02/01/2013
Colorado-Kansas	Kansas	09/2012	601			01/09/2013
Mississippi	Mississippi	06/2012	3,441			11/01/2012
Kentucky/Mid-States	Georgia(6)	09/2011	1,079			10/01/2012
Kentucky/Mid-States	Kentucky(4)	09/2013	2,425			10/01/2012
Kentucky/Mid-States	Virginia	09/2013	101			10/01/2012
Total 2013 Filings			$	40,088

⁽¹⁾  Incremental net utility plant investment represents the system-wide incremental investment for the West Texas Division. The increase in annual operating income is for the unincorporated areas of the West Texas Division only.

⁽²⁾  Incremental net utility plant investment represents the system-wide incremental investment for the Mid-Tex Division. The increase in annual operating income is for the unincorporated areas of the Mid-Tex Division only.

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⁽³⁾  Incremental net utility plant investment represents the system-wide incremental investment for the West Texas Division. The increase in annual operating income is for the cities of Amarillo, Channing, Dalhart and Lubbock in the West Texas Division only.

⁽⁴⁾  The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure.

⁽⁵⁾  On June 1, 2014 rates, subject to refund, were implemented. On June 1, 2015, concurrent with implementation of the 2015 RRM, final rates were implemented.    

⁽⁶⁾  On April 1, 2013, we completed the sale of our Georgia operations to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. The increase in operating income arising from the implementation of new rates is included as a component of discontinued operations through March 31, 2013.

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)
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
2013 Rate Case Filings:
Mid-Tex	Texas	$	42,601	12/04/2012
Kentucky/Mid-States	Tennessee	7,530		11/08/2012
West Texas	Texas	6,569		10/01/2012
Total 2013 Rate Case Filings		$	56,700

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2015, 2014 and 2013:

Division	Jurisdiction	Rate Activity	Increase in Annual Operating Income			Effective Date
			(In thousands)
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	)
2013 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem(1)	$	1,322		02/01/2013
Total 2013 Other Rate Activity			$	1,322

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

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.

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 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, 2015, we had 4,753 employees, consisting of 4,642 employees in our regulated operations and 111 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

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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 2015, 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.

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.

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Any adverse changes in economic conditions in the United States, especially in the states in which we operate, similar to the economic downturn we experienced for several years beginning in 2008 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 and bad debt expense. 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.

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 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

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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.

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, the impact of the Health Care Reform Act of 2010 (HCR) and any future legislative changes related to the provision of health care benefits. The impact of additional costs incurred by the health insurance industry arising from the implementation of HCR, 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 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,

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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.

We are committed to constantly monitoring and maintaining 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. The pipeline replacement programs currently underway in several of our divisions typify the preventive maintenance and continual renewal that we perform on our natural gas distribution system in the eight states in which we currently operate. The safety and protection of the public, our customers and our employees is our top priority. However, due primarily to the unfortunate pipeline incident in California in 2010, 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 such increased 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 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 from our regulated distribution segment could be adversely affected through lower gas volumes and revenues, with our regulated pipeline segment also likely experiencing lower volumes and revenues as well.  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 tornados, 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

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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.

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, 2015, in our regulated distribution segment, we owned an aggregate of 70,218 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 5,477 miles of gas transmission and gathering lines as well as 111 miles of transmission and gathering lines through our nonregulated segment.

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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, 2015:

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.

Additionally, we contract for storage service in underground storage facilities on many of the interstate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2015:

Segment	Division/Company	Maximum Storage Quantity (MMBtu)	Maximum Daily Withdrawal Quantity (MDWQ)(1)
Regulated Distribution Segment
	Colorado-Kansas Division	4,761,909	113,689
	Kentucky/Mid-States Division	11,181,603	268,739
	Louisiana Division	2,595,619	179,347
	Mid-Tex Division	3,250,000	175,000
	Mississippi Division	3,554,535	151,334
	West Texas Division	4,500,000	146,000
Total		29,843,666	1,034,109
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		39,544,535	1,352,553

⁽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.

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ITEM 3. Legal Proceedings.

See Note 10 to the consolidated financial statements, which is incorporated in this Item 3 by reference.

ITEM 4. Mine Safety Disclosures.

Not applicable.

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 2015 and 2014 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 2015						Fiscal 2014
	High		Low		Dividends Paid		High		Low		Dividends Paid
Quarter ended:
December 31	$	58.08	$	47.35	$	0.39	$	47.06	$	41.08	$	0.37
March 31	58.81		52.02		0.39		48.01		44.19		0.37
June 30	56.41		51.28		0.39		53.40		46.94		0.37
September 30	58.18		51.48		0.39		52.68		47.01		0.37
					$	1.56					$	1.48

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 30, 2015 was 14,881. 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 2015 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 Standard and Poor’s 500 Stock Index and the cumulative total return of two different customized peer company groups, the New Comparison Company Index and the Old Comparison Company Index. The New Comparison Company Index includes ONE Gas, Inc., The Laclede Group, Inc. and TECO Energy, Inc. and excludes ONEOK, Inc., National Fuel Gas Company and Integrys Energy Group because the Board of Directors determined that these companies better fit the profile of the companies in our peer group, which 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, 2010 in our common stock, the S&P 500 Index and in the common stock of the companies in the New and Old Comparison Company Indexes, 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
	9/30/2010	9/30/2011	9/30/2012	9/30/2013	9/30/2014	9/30/2015
Atmos Energy Corporation	100.00	115.72	133.03	164.05	189.51	237.91
S&P 500 Index	100.00	101.14	131.69	157.17	188.18	187.02
Old Comparison Company Index	100.00	117.66	142.22	167.00	201.17	193.52
New Comparison Company Index	100.00	116.24	134.26	155.06	179.39	204.94

The New 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 included in the index are AGL Resources Inc., CenterPoint Energy, Inc., CMS Energy Corporation, NiSource Inc., ONE Gas, Inc., Piedmont Natural Gas Company, Inc., Questar Corporation, TECO Energy, Inc., The Laclede Group, Inc., Vectren Corporation and WGL Holdings, Inc. The Old Comparison Company Index includes AGL Resources Inc., CenterPoint Energy Resources Corporation, CMS Energy Corporation, Integrys Energy Group, Inc., National Fuel Gas, NiSource Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., Questar Corporation, Vectren Corporation and WGL Holdings, Inc.

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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2015.

	Number of securities to be issued upon exercise of outstanding options, 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	—	$	—	308,582
Total equity compensation plans approved by security holders	—	—		308,582
Equity compensation plans not approved by security holders	—	—		—
Total	—	$	—	308,582

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 is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. Although the program is authorized for a five-year period, it may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the Company deems appropriate. We did not repurchase any shares during fiscal 2015 under the program, which is scheduled to end on September 30, 2016. At September 30, 2015, there were 4,612,009 shares of repurchase authority remaining 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
	2015		2014		2013		2012(1)		2011(1)
	(In thousands, except per share data)
Results of Operations
Operating revenues	$	4,142,136	$	4,940,916	$	3,875,460	$	3,436,162	$	4,286,435
Gross profit	$	1,680,017	$	1,582,426	$	1,412,050	$	1,323,739	$	1,300,820
Income from continuing operations	$	315,075	$	289,817	$	230,698	$	192,196	$	189,588
Net income	$	315,075	$	289,817	$	243,194	$	216,717	$	207,601
Diluted income per share from continuing operations	$	3.09	$	2.96	$	2.50	$	2.10	$	2.07
Diluted net income per share	$	3.09	$	2.96	$	2.64	$	2.37	$	2.27
Cash dividends declared per share	$	1.56	$	1.48	$	1.40	$	1.38	$	1.36
Financial Condition
Net property, plant and equipment(2)	$	7,430,580	$	6,725,906	$	6,030,655	$	5,475,604	$	5,147,918
Total assets	$	9,092,945	$	8,594,704	$	7,934,268	$	7,495,675	$	7,282,871
Capitalization:
Shareholders’ equity	$	3,194,797	$	3,086,232	$	2,580,409	$	2,359,243	$	2,255,421
Long-term debt (excluding current maturities)	2,455,388		2,455,986		2,455,671		1,956,305		2,206,117
Total capitalization	$	5,650,185	$	5,542,218	$	5,036,080	$	4,315,548	$	4,461,538

⁽¹⁾  Financial results for fiscal years 2012 and 2011 reflect a $5.3 million and a $30.3 million pre-tax loss for the impairment of certain assets.

⁽²⁾  Amounts shown for fiscal 2012 and 2011 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; 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 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
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 10 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 12 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 12 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. In addition, recent pipeline safety rulemaking has impacted the level of operating and maintenance expense and capital spending in our regulated business, which we expect to continue. Accordingly, 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 2015. Net income increased 9 percent to $315.1 million, or $3.09 per diluted share. The year-over-year increase largely reflects positive rate outcomes, which more than offset weather that was 10 percent warmer than the prior year, particularly in our nonregulated segment. Additionally, operating cash flow increased $96.5 million to $836.5 million for the fiscal year ended September 30, 2015.

Capital expenditures for fiscal 2015 totaled $975.1 million. Approximately 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. Fiscal 2014 spending under these and other mechanisms enabled the Company to complete 17 regulatory filings during fiscal 2015 that should increase annual operating income from regulated operations by $114.5 million. We plan to continue to fund our growth through the use of operating cash flows and debt and equity securities, to maintain a balanced capital structure.

On July 1, 2015, Fitch Ratings (Fitch) upgraded our senior unsecured debt rating to A from A- with a ratings outlook of stable. Fitch cited its expectation of continued strong financial performance driven primarily by organic growth in our regulated distribution and regulated pipeline segments.

On October 29, 2015, S&P affirmed our senior unsecured debt rating as A- and issued a revised outlook from stable to positive, citing the potential for an upgraded rating in the future if we maintain our current level of financial performance as capital spending levels remain elevated.

As a result of the continued contribution and stability of our regulated earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 7.7 percent for fiscal 2016.

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Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2015, 2014 and 2013.

	For the Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands, except per share data)
Operating revenues	$	4,142,136		$	4,940,916		$	3,875,460
Gross profit	1,680,017			1,582,426			1,412,050
Operating expenses	1,048,622			971,077			910,171
Operating income	631,395			611,349			501,879
Miscellaneous expense	(4,389		)	(5,235		)	(197		)
Interest charges	116,241			129,295			128,385
Income from continuing operations before income taxes	510,765			476,819			373,297
Income tax expense	195,690			187,002			142,599
Income from continuing operations	315,075			289,817			230,698
Income from discontinued operations, net of tax	—			—			7,202
Gain on sale of discontinued operations, net of tax	—			—			5,294
Net income	$	315,075		$	289,817		$	243,194
Diluted net income per share from continuing operations	$	3.09		$	2.96		$	2.50
Diluted net income per share from discontinued operations	$	—		$	—		$	0.14
Diluted net income per share	$	3.09		$	2.96		$	2.64

Regulated operations contributed 95 percent, 89 percent and 95 percent to our consolidated net income from continuing operations for fiscal years 2015, 2014 and 2013. 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
	2015		2014		2013
	(In thousands)
Regulated distribution segment	$	204,813	$	171,585	$	150,856
Regulated pipeline segment	94,662		86,191		68,260
Nonregulated segment	15,600		32,041		11,582
Net income from continuing operations	315,075		289,817		230,698
Net income from discontinued operations	—		—		12,496
Net income	$	315,075	$	289,817	$	243,194

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

	For the Fiscal Year Ended September 30
	2015		2014		2013
	(In thousands, except per share data)
Regulated operations	$	299,475	$	257,776	$	219,116
Nonregulated operations	15,600		32,041		11,582
Net income from continuing operations	315,075		289,817		230,698
Net income from discontinued operations	—		—		12,496
Net income	$	315,075	$	289,817	$	243,194
Diluted EPS from continuing regulated operations	$	2.93	$	2.63	$	2.38
Diluted EPS from nonregulated operations	0.16		0.33		0.12
Diluted EPS from continuing operations	3.09		2.96		2.50
Diluted EPS from discontinued operations	—		—		0.14
Consolidated diluted EPS	$	3.09	$	2.96	$	2.64

We reported net income of $315.1 million, or $3.09 per diluted share for the year ended September 30, 2015, compared with net income of $289.8 million or $2.96 per diluted share in the prior year. Unrealized losses in our nonregulated operations during the current year decreased net income by $1.5 million or $0.01 per diluted share compared with net gains recorded in the prior year of $5.8 million or $0.06 per diluted share.

We reported net income of $289.8 million, or $2.96 per diluted share for the year ended September 30, 2014, compared with net income of $243.2 million or $2.64 per diluted share in fiscal 2013. Income from continuing operations in fiscal 2013 was $230.7 million, or $2.50 per diluted share. Income from discontinued operations was $12.5 million or $0.14 per diluted share for the year ended September 30, 2013, which includes the gain on sale of substantially all our assets in Georgia of $5.3 million. Unrealized gains in our nonregulated operations during fiscal 2014 increased net income by $5.8 million or $0.06 per diluted share compared with net gains recorded in fiscal 2013 of $5.3 million, or $0.05 per diluted share.

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 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 2015, we completed 16 regulatory proceedings in our regulated distribution segment, which should result in a $77.3 million increase in annual operating income.

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In April 2013, we completed the sale of our Georgia regulated distribution operations, representing approximately 64,000 customers.

Review of Financial and Operating Results

Financial and operational highlights for our regulated distribution segment for the fiscal years ended September 30, 2015, 2014 and 2013 are presented below.

	For the Fiscal Year Ended September 30
	2015			2014			2013		2015 vs. 2014			2014 vs. 2013
	(In thousands, unless otherwise noted)
Gross profit	$	1,237,577		$	1,176,515		$	1,081,236	$	61,062		$	95,279
Operating expenses	817,428			791,947			738,143		25,481			53,804
Operating income	420,149			384,568			343,093		35,581			41,475
Miscellaneous income (expense)	(377		)	(381		)	2,535		4			(2,916		)
Interest charges	84,132			94,918			98,296		(10,786		)	(3,378		)
Income from continuing operations before income taxes	335,640			289,269			247,332		46,371			41,937
Income tax expense	130,827			117,684			96,476		13,143			21,208
Income from continuing operations	204,813			171,585			150,856		33,228			20,729
Income from discontinued operations, net of tax	—			—			7,202		—			(7,202		)
Gain on sale of discontinued operations, net of tax	—			—			5,649		—			(5,649		)
Net Income	$	204,813		$	171,585		$	163,707	$	33,228		$	7,878
Consolidated regulated distribution sales volumes from continuing operations — MMcf	293,350			317,320			269,162		(23,970		)	48,158
Consolidated regulated distribution transportation volumes from continuing operations — MMcf	135,972			134,483			123,144		1,489			11,339
Consolidated regulated distribution throughput from continuing operations — MMcf	429,322			451,803			392,306		(22,481		)	59,497
Consolidated regulated distribution throughput from discontinued operations — MMcf	—			—			4,731		—			(4,731		)
Total consolidated regulated distribution throughput — MMcf	429,322			451,803			397,037		(22,481		)	54,766
Consolidated regulated distribution average transportation revenue per Mcf	$	0.50		$	0.48		$	0.46	$	0.02		$	0.02
Consolidated regulated distribution average cost of gas per Mcf sold	$	5.20		$	5.94		$	4.91	$	(0.74	)	$	1.03

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

Income from continuing operations 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-to-date 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. Current period weather was ten percent warmer compared to the prior-year period, 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.

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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 and higher interest expense deferrals under our infrastructure mechanisms.

Fiscal year ended September 30, 2014 compared with fiscal year ended September 30, 2013

Income from continuing operations for our regulated distribution segment increased 14 percent, primarily due to a $95.3 million increase in gross profit, partially offset by a $53.8 million increase in operating expenses. The year-to-date increase in gross profit primarily reflects:

• a $35.3 million net increase in rate adjustments, primarily in our Mid-Tex, Kentucky, West Texas and Louisiana service areas.

• a $14.3 million increase due to increased customer consumption resulting from colder weather, primarily experienced in our Mid-Tex and West Texas Divisions.

• a $27.5 million increase in revenue-related taxes, primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $28.4 million increase in the related tax expense.

• a $13.8 million increase related to increased customer count, higher transportation, late payment and installment plan revenues.

The $53.8 million 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 the following:

• a $28.4 million increase due to the aforementioned increase in revenue-related taxes.

• a $12.8 million increase in depreciation expense.

• a $12.7 million net increase in employee-related expenses, due to lower labor capitalization rates, increased benefit costs and increased variable compensation expense.

• a $4.2 million increase in the provision for doubtful accounts.

The $21.2 million increase in income tax expense was primarily due to increased income from continuing operations before income taxes as well as an increase of approximately $7.0 million in our deferred tax asset valuation allowance due to the uncertainty in the company's ability to utilize certain charitable contribution carryforwards before they expire.

The following table shows our operating income from continuing operations by regulated distribution division, in order of total rate base, for the fiscal years ended September 30, 2015, 2014 and 2013. The presentation of our regulated distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

	For the Fiscal Year Ended September 30
	2015		2014			2013		2015 vs. 2014			2014 vs. 2013
	(In thousands)
Mid-Tex	$	197,559	$	187,265		$	158,900	$	10,294		$	28,365
Kentucky/Mid-States	59,233		55,968			46,164		3,265			9,804
Louisiana	51,001		56,648			52,125		(5,647		)	4,523
West Texas	37,180		29,250			28,085		7,930			1,165
Mississippi	34,333		28,473			29,112		5,860			(639		)
Colorado-Kansas	28,720		28,077			25,478		643			2,599
Other	12,123		(1,113		)	3,229		13,236			(4,342		)
Total	$	420,149	$	384,568		$	343,093	$	35,581		$	41,475

Regulated Pipeline Segment

Our regulated pipeline segment consists of the pipeline and storage operations of the Atmos Pipeline - Texas Division (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 Permian Basin of West Texas. APT’s primary business is providing firm transportation and storage services for our Mid-Tex Division and other LDC customers. APT also provides interruptible transportation, storage and ancillary services for third parties including, industrial and electric generation customers as well as producers, marketers and other shippers..

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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 impact the market value for transportation services between those geographic areas.

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

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

Review of Financial and Operating Results

Financial and operational highlights for our regulated pipeline segment for the fiscal years ended September 30, 2015, 2014 and 2013 are presented below.

	For the Fiscal Year Ended September 30
	2015			2014			2013			2015 vs. 2014			2014 vs. 2013
	(In thousands, unless otherwise noted)
Mid-Tex Division transportation	$	264,059		$	227,230		$	179,628		$	36,829		$	47,602
Third-party transportation	94,893			76,109			66,939			18,784			9,170
Storage and park and lend services	3,575			5,344			5,985			(1,769		)	(641		)
Other	7,585			9,776			16,348			(2,191		)	(6,572		)
Gross profit	370,112			318,459			268,900			51,653			49,559
Operating expenses	188,845			145,640			129,047			43,205			16,593
Operating income	181,267			172,819			139,853			8,448			32,966
Miscellaneous expense	(1,243		)	(3,181		)	(2,285		)	1,938			(896		)
Interest charges	33,151			36,280			30,678			(3,129		)	5,602
Income before income taxes	146,873			133,358			106,890			13,515			26,468
Income tax expense	52,211			47,167			38,630			5,044			8,537
Net income	$	94,662		$	86,191		$	68,260		$	8,471		$	17,931
Gross pipeline transportation volumes — MMcf	738,532			714,464			649,740			24,068			64,724
Consolidated pipeline transportation volumes — MMcf	528,068			493,360			467,178			34,708			26,182

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 Gas Reliability Infrastructure Program (GRIP) filings. Additionally, gross profit reflects increased pipeline demand fees and through-system transportation volumes and rates that were offset by lower storage and other fees and the absence of a $1.8 million increase recorded in the prior-year associated with 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 the prior year as a result of the completion of a state use tax audit.

Fiscal year ended September 30, 2014 compared with fiscal year ended September 30, 2013

Net income for our regulated pipeline segment increased 26 percent in fiscal 2014 compared to fiscal 2013, primarily due to a $49.6 million increase in gross profit. The increase in gross profit primarily reflects a $38.5 million increase in rates from the GRIP filings approved by the Railroad Commission of Texas (RRC) in fiscal 2014 and 2013 coupled with a $4.7 million increase associated with higher transportation volumes and basis spreads driven by colder weather.

The Atmos Pipeline — Texas rate case approved by the RRC on April 18, 2011 contained an annual adjustment mechanism, approved for a three-year pilot program, that adjusted regulated rates up or down by 75 percent of the difference between the non-regulated annual revenue of Atmos Pipeline — Texas and a pre-defined base credit. The annual adjustment

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mechanism expired on June 30, 2013. On January 1, 2014, the RRC approved the extension of the annual adjustment mechanism retroactive to July 1, 2013, which will stay in place until the completion of the next Atmos Pipeline — Texas rate case. As a result of this decision, during fiscal 2014, we recognized a $1.8 million increase in gross profit for the application of the annual adjustment mechanism, for the period July 1, 2013 to September 30, 2013.

Operating expenses increased $16.6 million primarily due to the following:

•a $10.1 million increase in pipeline and right-of-way maintenance activities.

•a $5.7 million increase in depreciation expense associated with increased capital investments.

•a $2.4 million increase due to higher employee-related expenses, partially offset by

•a $6.7 million refund received as a result of the completion of a state use tax audit.

Nonregulated Segment

Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and typically represents 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, the level of domestic natural gas production and the level of 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 level of interest expense recognized by this segment.

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

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

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

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

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Review of Financial and Operating Results

Financial and operational highlights for our nonregulated segment for the fiscal years ended September 30, 2015, 2014 and 2013 are presented below.

	For the Fiscal Year Ended September 30
	2015			2014		2013			2015 vs. 2014			2014 vs. 2013
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	48,930		$	39,529	$	39,839		$	9,401		$	(310	)
Storage and transportation services	13,575			14,696		14,641			(1,121		)	55
Other	12,755			24,170		(103		)	(11,415		)	24,273
Total realized margins	75,260			78,395		54,377			(3,135		)	24,018
Unrealized margins	(2,400		)	9,560		8,954			(11,960		)	606
Gross profit	72,860			87,955		63,331			(15,095		)	24,624
Operating expenses	42,881			33,993		44,404			8,888			(10,411		)
Operating income	29,979			53,962		18,927			(23,983		)	35,035
Miscellaneous income (expense)	(760		)	2,216		2,316			(2,976		)	(100		)
Interest charges	967			1,986		2,168			(1,019		)	(182		)
Income from continuing operations before income taxes	28,252			54,192		19,075			(25,940		)	35,117
Income tax expense	12,652			22,151		7,493			(9,499		)	14,658
Income from continuing operations	15,600			32,041		11,582			(16,441		)	20,459
Loss on sale of discontinued operations, net of tax	—			—		(355		)	—			355
Net income	$	15,600		$	32,041	$	11,227		$	(16,441	)	$	20,814
Gross nonregulated delivered gas sales volumes — MMcf	410,044			439,014		396,561			(28,970		)	42,453
Consolidated nonregulated delivered gas sales volumes — MMcf	351,427			377,441		343,669			(26,014		)	33,772
Net physical position (Bcf)	14.6			9.3		12.0			5.3			(2.7		)

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

Net income for our nonregulated segment decreased 51 percent from the prior year due to lower gross profit and higher operating expenses.

The $15.1 million period-over-period 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 the prior-year period, 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 into the fiscal 2014 second quarter to capture incremental gross profit margin. Market conditions in the current-year period were less volatile than the prior-year period, which provided fewer opportunities to capture incremental gross profit.

• 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 2015. As a result, AEH has experienced fewer deliveries to low-margin marketing and power generation customers, which is 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 the prior year of the Kentucky litigation and the resolution of the Tennessee Business License Tax matter.

Fiscal year ended September 30, 2014 compared with fiscal year ended September 30, 2013

Net income for our nonregulated segment increased 185 percent in fiscal year 2014 compared to the year ended September 30, 2013 due to higher gross profit and decreased operating expenses.

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The period-over-period increase in gross profit was primarily due to a $24.0 million increase in realized margins. The increase in realized margins reflects:

• A $24.3 million increase in other realized margins due to the acceleration of physical withdrawals into the second quarter from future periods to capture gross profit margin during periods of increased natural gas price volatility caused by strong market demand as a result of significantly colder weather during the second quarter. This modification in the execution strategy resulted in the establishment of new positions that were expected to settle in the latter half of fiscal 2014 and beyond. The positions that settled during the fourth quarter of fiscal 2014 were settled during a period of falling prices, which further increased realized margins during fiscal 2014. In contrast, losses were incurred from storage optimization activities in the prior year largely due to unfavorable changes in market prices relative to the execution strategy in place at that time.

• A $0.3 million decrease in gas delivery and related services margins. Consolidated sales volumes increased ten percent as a result of stronger demand from marketing, industrial and utility/municipal customers due to colder weather. However, gas delivery per-unit margins decreased from ten cents per Mcf in the prior-year period to 9 cents per Mcf due primarily to losses incurred during the second quarter to meet peaking requirements for certain customers during periods of colder weather, due to volatility between spot purchase prices and the contractual sales price to the customer.

Operating expenses decreased $10.4 million, primarily due to lower legal expenses related to the dismissal of the Kentucky litigation and the favorable resolution of the Tennessee Business License Tax matter in fiscal 2014.

LIQUIDITY AND CAPITAL RESOURCES

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources, including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.

We regularly evaluate our funding strategy and capital structure to ensure that we (i) have sufficient liquidity for our short-term and long-term needs in a cost-effective manner and (ii) maintain a balanced capital structure with a debt-to-capitalization ratio in a target range of 45 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of capacity from our short-term facilities.

The following table presents our capitalization as of September 30, 2015 and 2014:

	September 30
	2015				2014
	(In thousands, except percentages)
Short-term debt	$	457,927	7.5	%	$	196,695	3.4	%
Long-term debt	2,455,388		40.2	%	2,455,986		42.8	%
Shareholders’ equity	3,194,797		52.3	%	3,086,232		53.8	%
Total capitalization, including short-term debt	$	6,108,112	100.0	%	$	5,738,913	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 47.7 percent and 46.2 percent at September 30, 2015 and 2014.

As we continue to invest in the safety and reliability of our distribution and transportation system, 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 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 2016 and beyond.

On September 25, 2015, we terminated our existing $1.25 billion credit facility and entered into a new five year $1.25 billion credit facility with substantially the same terms. The new facility also retains the $250 million accordion feature, which allows for an increase in the total committed loan amount to $1.5 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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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, 2015, 2014 and 2013 are presented below.

	For the Fiscal Year Ended September 30
	2015			2014			2013			2015 vs. 2014			2014 vs. 2013
	(In thousands)
Total cash provided by (used in)
Operating activities	$	836,519		$	739,986		$	613,127		$	96,533		$	126,859
Investing activities	(974,755		)	(837,576		)	(696,914		)	(137,179		)	(140,662		)
Financing activities	124,631			73,649			85,747			50,982			(12,098		)
Change in cash and cash equivalents	(13,605		)	(23,941		)	1,960			10,336			(25,901		)
Cash and cash equivalents at beginning of period	42,258			66,199			64,239			(23,941		)	1,960
Cash and cash equivalents at end of period	$	28,653		$	42,258		$	66,199		$	(13,605	)	$	(23,941	)

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, 2015 compared with fiscal year ended September 30, 2014

For the fiscal year ended September 30, 2015, we generated operating cash flow of $836.5 million from operating activities compared with $740.0 million in the prior year. The year-over-year increase primarily reflects successful rate case outcomes in the prior year, the timing of gas cost recoveries under our purchased gas cost mechanisms and lower gas prices during the current-year storage injection season.

Fiscal Year ended September 30, 2014 compared with fiscal year ended September 30, 2013

For the fiscal year ended September 30, 2014, we generated operating cash flow of $740.0 million from operating activities compared with $613.1 million in fiscal 2013. The year-over-year increase reflects higher operating results from colder weather and rate increases combined with the timing of customer collections and vendor payments.

Cash flows from investing activities

In recent years, a substantial portion of our cash resources has been used to fund 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 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, 2015, we incurred $975.1 million for capital expenditures compared with $835.3 million for the fiscal year ended September 30, 2014 and $845.0 million for the fiscal year ended September 30, 2013.

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

The $139.8 million increase in capital expenditures in fiscal 2015 compared to fiscal 2014 primarily reflects:

• A $96.9 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.

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Fiscal Year ended September 30, 2014 compared with fiscal year ended September 30, 2013

The $9.7 million decrease in capital expenditures in fiscal 2014 compared to fiscal 2013 primarily reflects:

• A $63.9 million decrease in capital spending in our regulated pipeline segment primarily associated with the completion of the Line WX expansion project, partially offset by

• A $55.5 million increase in capital spending in our regulated distribution segment due to increased spending under our infrastructure replacement programs.

Cash flows from financing activities

We generated a net $124.6 million, $73.6 million and $85.7 million in cash from financing activities for fiscal years 2015, 2014 and 2013. Our significant financing activities for the fiscal years ended September 30, 2015, 2014 and 2013 are summarized as follows:

2015

During the fiscal year ended September 30, 2015, our financing activities generated $124.6 million of cash compared with $73.6 million of cash generated in the prior year. The increase is primarily due to timing between short-term debt borrowings and repayments during the current year, proceeds from the issuance of $500 million unsecured 4.125% senior notes in October 2014 and the settlement of the associated forward starting interest rate swaps. Partially 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 the prior year and proceeds generated from the equity offering completed in February 2014.

2014

During the fiscal year ended September 30, 2014, our financing activities generated $73.6 million of cash compared with $85.7 million of cash generated in the prior year. 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.

2013

During the fiscal year ended September 30, 2013, our financing activities generated $85.7 million of cash compared with $44.8 million of cash used in fiscal 2012. Fiscal year 2013 cash flows from financing activities were significantly influenced by the issuance of $500 million 4.15% 30-year unsecured senior notes on January 11, 2013. We used a portion of the net cash proceeds of $493.8 million to repay a $260 million short-term financing facility executed in fiscal 2012, to settle, for $66.6 million, three Treasury locks associated with the issuance and to reduce short-term debt borrowings by $167.2 million.

The following table shows the number of shares issued for the fiscal years ended September 30, 2015, 2014 and 2013:

	For the Fiscal Year Ended September 30
	2015	2014	2013
Shares issued:
Direct Stock Purchase Plan	176,391	83,150	—
Retirement Savings Plan	398,047	—	—
1998 Long-Term Incentive Plan	664,752	653,130	531,672
Outside Directors Stock-For-Fee Plan	—	1,735	2,088
February 2014 Offering	—	9,200,000	—
Total shares issued	1,239,190	9,938,015	533,760

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 have begun 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. At September 30, 2015, of the 8.7 million shares authorized for issuance from the LTIP, 308,582 shares remained available. 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.

The increased number of shares issued in fiscal 2014 compared with the number of shares issued in fiscal 2013 primarily reflects the equity offering completed in February 2014 as well as a higher number of performance-based awards issued in the

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current year as actual performance exceeded the target. At September 30, 2014, of the 8.7 million shares authorized for issuance from the LTIP, 845,139 shares remained available. For the year ended September 30, 2014, we canceled and retired 190,134 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.

We finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, which is collateralized by our $1.25 billion unsecured credit facility, as well as three additional committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1.3 billion of working capital funding. The $1.25 billion unsecured credit facility has a $250 million accordion feature which allows for an increase in the total committed loan amount to $1.5 billion. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission that permits us to issue a total of $1.75 billion in common stock and/or debt securities. The shelf registration statement is effective until March 28, 2016. As of September 30, 2015, $845 million was available for issuance.

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, Ltd. (Fitch). Our current debt ratings are all considered investment grade and are as follows:

	S&P	Moody’s	Fitch
Unsecured senior long-term debt	A-	A2	A
Commercial paper	A-2	P-1	F-2

On July 1, 2015, Fitch upgraded our senior unsecured debt rating to A from A- with a ratings outlook of stable, citing Fitch's expectation of continued strong financial performance, which has been driven primarily by organic growth in our regulated distribution and regulated pipeline segments.

On October 29, 2015, S&P affirmed our senior unsecured debt rating as A- and issued a revised outlook from stable to positive, citing the potential for an upgraded rating in the future if we maintain our current level of financial performance as capital spending levels remain elevated.

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.

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Debt Covenants

We were in compliance with all of our debt covenants as of September 30, 2015. Our debt covenants are described in Note 5 to the consolidated financial statements.

Contractual Obligations and Commercial Commitments

The following table provides information about contractual obligations and commercial commitments at September 30, 2015.

	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)	457,927		457,927		—		—		—
Interest charges(2)	2,252,802		140,192		259,835		189,559		1,663,216
Operating leases(3)	140,713		16,475		33,129		29,458		61,651
Demand fees for contracted storage(4)	8,188		3,853		3,977		286		72
Demand fees for contracted transportation(5)	7,068		3,990		1,511		538		1,029
Financial instrument obligations(6)	120,107		9,568		110,539		—		—
Pension and postretirement benefit plan contributions(7)	325,606		37,355		50,138		60,238		177,875
Uncertain tax positions(8)	17,069		—		17,069		—		—
Total contractual obligations	$	5,789,480	$	669,360	$	726,198	$	730,079	$	3,663,843

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

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

⁽³⁾  See Note 9 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, 2015. 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 6 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, 2015, we were committed to purchase 36.6 Bcf within one year and 26.8 Bcf within one to 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, 2015, AEH was committed to purchase 101.9 Bcf within one year, 16.0 Bcf within one to three years and 0.5 Bcf after three years under indexed contracts. AEH is committed to purchase 3.0 Bcf within one year under fixed price contracts with prices ranging from $2.32 to $3.23 per Mcf.

38

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 with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.

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, 2015 (in thousands):

Fair value of contracts at September 30, 2014	$	14,284
Contracts realized/settled	(33,892		)
Fair value of new contracts	607
Other changes in value	(100,360		)
Fair value of contracts at September 30, 2015	$	(119,361	)

The fair value of our regulated distribution segment’s financial instruments at September 30, 2015, is presented below by time period and fair value source:

	Fair Value of Contracts at September 30, 2015
	Maturity in years
Source of Fair Value	Less than 1			1-3			4-5		Greater than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(9,190	)	$	(110,171	)	$	—	$	—	$	(119,361	)
Prices based on models and other valuation methods	—			—			—		—		—
Total Fair Value	$	(9,190	)	$	(110,171	)	$	—	$	—	$	(119,361	)

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, 2015 (in thousands):

Fair value of contracts at September 30, 2014	$	(3,033	)
Contracts realized/settled	21,401
Fair value of new contracts	—
Other changes in value	(52,988		)
Fair value of contracts at September 30, 2015	(34,620		)
Netting of cash collateral	43,474
Cash collateral and fair value of contracts at September 30, 2015	$	8,854

39

The fair value of our nonregulated segment’s financial instruments at September 30, 2015, is presented below by time period and fair value source.

	Fair Value of Contracts at September 30, 2015
	Maturity in years
Source of Fair Value	Less than 1			1-3			4-5			Greater than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(24,928	)	$	(8,925	)	$	(767	)	$	—	$	(34,620	)
Prices based on models and other valuation methods	—			—			—			—		—
Total Fair Value	$	(24,928	)	$	(8,925	)	$	(767	)	$	—	$	(34,620	)

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 strived 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 five percent. For fiscal 2016, we anticipate the medical and prescription drug inflation rate will continue at approximately five percent, primarily due to the inflation of health care costs.

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2015, our total net periodic pension and other benefits costs was $58.9 million, compared with $69.8 million and $78.5 million for the fiscal years ended September 30, 2014 and 2013. 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 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.

Our fiscal 2014 costs were determined using a September 30, 2013 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, 2012, the measurement date for our fiscal 2013 net periodic cost. Therefore, we increased the discount rate used to measure our fiscal 2014 net periodic cost from 4.04 percent to 4.95 percent. However, we decreased the expected return on plan assets from 7.75 percent to 7.25 percent in the determination of our fiscal 2014 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 2014 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, 2015. Based on this valuation, we contributed cash of $38.0 million, $27.1 million and $32.7 million to our pension

40

plans during fiscal 2015, 2014 and 2013. Each contribution increased the level of our plan assets to achieve a desirable PPA funding threshold.

We contributed $20.0 million, $23.6 million and $26.6 million to our postretirement benefits plans for the fiscal years ended September 30, 2015, 2014 and 2013. 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 2016 and Beyond

As of September 30, 2015, interest and corporate bond rates were higher than the rates as of September 30, 2014. 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. In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. On October 8, 2015, the Society of Actuaries issued an additional report related to mortality tables and the mortality improvement scale.  As of September 30, 2015, we updated our assumed mortality rates to incorporate both new sets of mortality tables. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2016 net periodic pension cost to decrease by approximately 20 percent.

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 2016. 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 $30 million and $40 million during fiscal 2016.

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 $2.7 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $1.2 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 12 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.

41

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, 2015 of 1.0 Bcf, a $0.50 change in the forward NYMEX price would have had a $0.3 million impact 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, 2015 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 $4.4 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.

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 $2.7 million during 2015.

42

ITEM 8. Financial Statements and Supplementary Data.

Index to financial statements and financial statement schedule:

	Page
Report of independent registered public accounting firm	44
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2015 and 2014	45
Consolidated statements of income for the years ended September 30, 2015, 2014 and 2013	46
Consolidated statements of comprehensive income for the years ended September 30, 2015, 2014 and 2013	47
Consolidated statements of shareholders' equity for the years ended September 30, 2015, 2014 and 2013	48
Consolidated statements of cash flow for the years ended September 30, 2015, 2014 and 2013	49
Notes to consolidated financial statements	50
Selected Quarterly Financial Data (Unaudited)	96
Financial statement schedule for the years ended September 30, 2015, 2014 and 2013
Schedule II. Valuation and Qualifying Accounts	103

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.

43

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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2015, 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, 2015, 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 6, 2015 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Dallas, Texas

November 6, 2015

44

ATMOS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	September 30
	2015			2014
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	8,959,702		$	8,200,121
Construction in progress	280,398			247,579
	9,240,100			8,447,700
Less accumulated depreciation and amortization	1,809,520			1,721,794
Net property, plant and equipment	7,430,580			6,725,906
Current assets
Cash and cash equivalents	28,653			42,258
Accounts receivable, less allowance for doubtful accounts of $15,283 in 2015 and $23,992 in 2014	295,160			343,400
Gas stored underground	236,603			278,917
Other current assets	70,569			111,265
Total current assets	630,985			775,840
Goodwill	742,702			742,029
Deferred charges and other assets	288,678			350,929
	$	9,092,945		$	8,594,704
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2015 — 101,478,818 shares, 2014 — 100,388,092 shares	$	507		$	502
Additional paid-in capital	2,230,591			2,180,151
Accumulated other comprehensive loss	(109,330		)	(12,393		)
Retained earnings	1,073,029			917,972
Shareholders’ equity	3,194,797			3,086,232
Long-term debt	2,455,388			2,455,986
Total capitalization	5,650,185			5,542,218
Commitments and contingencies
Current liabilities
Accounts payable and accrued liabilities	238,942			308,086
Other current liabilities	457,954			405,869
Short-term debt	457,927			196,695
Total current liabilities	1,154,823			910,650
Deferred income taxes	1,411,315			1,286,616
Regulatory cost of removal obligation	427,553			445,387
Pension and postretirement liabilities	287,373			340,963
Deferred credits and other liabilities	161,696			68,870
	$	9,092,945		$	8,594,704

See accompanying notes to consolidated financial statements.

45

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended September 30
	2015			2014			2013
	(In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	2,763,835		$	3,061,546		$	2,399,493
Regulated pipeline segment	370,112			318,459			268,900
Nonregulated segment	1,472,209			2,067,292			1,587,914
Intersegment eliminations	(464,020		)	(506,381		)	(380,847		)
	4,142,136			4,940,916			3,875,460
Purchased gas cost
Regulated distribution segment	1,526,258			1,885,031			1,318,257
Regulated pipeline segment	—			—			—
Nonregulated segment	1,399,349			1,979,337			1,524,583
Intersegment eliminations	(463,488		)	(505,878		)	(379,430		)
	2,462,119			3,358,490			2,463,410
Gross profit	1,680,017			1,582,426			1,412,050
Operating expenses
Operation and maintenance	541,868			505,154			488,020
Depreciation and amortization	274,796			253,987			235,079
Taxes, other than income	231,958			211,936			187,072
Total operating expenses	1,048,622			971,077			910,171
Operating income	631,395			611,349			501,879
Miscellaneous expense, net	(4,389		)	(5,235		)	(197		)
Interest charges	116,241			129,295			128,385
Income from continuing operations before income taxes	510,765			476,819			373,297
Income tax expense	195,690			187,002			142,599
Income from continuing operations	315,075			289,817			230,698
Income from discontinued operations, net of tax ($0, $0 and $3,986)	—			—			7,202
Gain on sale of discontinued operations, net of tax ($0, $0 and $2,909)	—			—			5,294
Net income	$	315,075		$	289,817		$	243,194
Basic earnings per share
Income per share from continuing operations	$	3.09		$	2.96		$	2.54
Income per share from discontinued operations	—			—			0.14
Net income per share — basic	$	3.09		$	2.96		$	2.68
Diluted earnings per share
Income per share from continuing operations	$	3.09		$	2.96		$	2.50
Income per share from discontinued operations	—			—			0.14
Net income per share — diluted	$	3.09		$	2.96		$	2.64
Weighted average shares outstanding:
Basic	101,892			97,606			90,533
Diluted	101,892			97,608			91,711

See accompanying notes to consolidated financial statements.

46

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended September 30
	2015			2014			2013
	(In thousands)
Net income	$	315,075		$	289,817		$	243,194
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(1,559), $1,199 and $(186)	(2,713		)	2,214			(213		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(40,501), $(32,353) and $47,236	(70,461		)	(56,287		)	82,179
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(15,193), $1,791 and $2,889	(23,763		)	2,802			4,519
Total other comprehensive income (loss)	(96,937		)	(51,271		)	86,485
Total comprehensive income	$	218,138		$	238,546		$	329,679

See accompanying notes to consolidated financial statements.

47

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, 2012	90,239,900		$	451		$	1,745,467		$	(47,607	)	$	660,932		$	2,359,243
Net income	—		—			—			—			243,194			243,194
Other comprehensive income	—		—			—			86,485			—			86,485
Repurchase of equity awards	(133,449	)	—			(5,150		)	—			—			(5,150		)
Cash dividends ($1.40 per share)	—		—			—			—			(128,115		)	(128,115		)
Common stock issued:
Direct stock purchase plan	—		—			(50		)	—			—			(50		)
1998 Long-term incentive plan	531,672		2			9,530			—			(744		)	8,788
Employee stock-based compensation	—		—			15,934			—			—			15,934
Outside directors stock-for-fee plan	2,088		—			80			—			—			80
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

See accompanying notes to consolidated financial statements.

48

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended September 30
	2015			2014			2013
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	315,075		$	289,817		$	243,194
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of discontinued operations	—			—			(8,203		)
Depreciation and amortization:
Charged to depreciation and amortization	274,796			253,987			236,928
Charged to other accounts	1,209			969			679
Deferred income taxes	192,886			189,952			141,336
Stock-based compensation	27,491			25,531			17,814
Debt financing costs	5,922			9,409			8,480
Other	(850		)	(428		)	(2,887		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	48,240			(41,408		)	(73,669		)
(Increase) decrease in gas stored underground	33,234			(31,996		)	31,979
(Increase) decrease in other current assets	(11,951		)	(24,411		)	15,644
Decrease in deferred charges and other assets	58,256			30,662			111,069
Increase (decrease) in accounts payable and accrued liabilities	(52,660		)	55,041			31,912
Increase (decrease) in other current liabilities	896			2,413			(44,491		)
Decrease in deferred credits and other liabilities	(56,025		)	(19,552		)	(96,658		)
Net cash provided by operating activities	836,519			739,986			613,127
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures	(975,132		)	(835,251		)	(845,033		)
Proceeds from the sale of discontinued operations	—			—			153,023
Other, net	377			(2,325		)	(4,904		)
Net cash used in investing activities	(974,755		)	(837,576		)	(696,914		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt	254,780			(165,865		)	(208,070		)
Net proceeds from issuance of long-term debt	493,538			—			493,793
Net proceeds from equity offering	—			390,205			—
Settlement of Treasury lock agreements	13,364			—			(66,626		)
Repayment of long-term debt	(500,000		)	—			(131		)
Cash dividends paid	(160,018		)	(146,248		)	(128,115		)
Repurchase of equity awards	(7,985		)	(8,717		)	(5,150		)
Issuance of common stock	30,952			4,274			46
Net cash provided by financing activities	124,631			73,649			85,747
Net increase (decrease) in cash and cash equivalents	(13,605		)	(23,941		)	1,960
Cash and cash equivalents at beginning of year	42,258			66,199			64,239
Cash and cash equivalents at end of year	$	28,653		$	42,258		$	66,199
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest	$	151,334		$	156,606		$	148,461
Income taxes	$	1,802		$	(610	)	$	10,008

See accompanying notes to consolidated financial statements.

49

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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.

During fiscal 2013 and fiscal 2012, we sold our regulated distribution operations serving approximately 148,000 customers in Georgia, Illinois, Iowa and Missouri.

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

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, 2015 and 2014 included the following:

	September 30
	2015		2014
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	121,183	$	162,777
Infrastructure Mechanisms(2)	32,813		26,948
Deferred gas costs	9,715		20,069
Recoverable loss on reacquired debt	16,319		18,877
APT annual adjustment mechanism	1,002		8,479
Rate case costs	1,533		3,757
Other	9,774		9,402
	$	192,339	$	250,309
Regulatory liabilities:
Regulatory cost of removal obligation	$	483,676	$	490,448
Deferred gas costs	28,100		35,063
Asset retirement obligation	9,063		10,508
Deferred franchise fees	—		5,268
Other	3,693		4,472
	$	524,532	$	545,759

⁽¹⁾ Includes $16.6 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.

⁽²⁾ Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest costs along with depreciation and other taxes, 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 $2.3 million, $1.5 million and $1.9 million was capitalized in 2015, 2014 and 2013.

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 3.3 percent, for each of the fiscal years ended September 30, 2015, 2014 and 2013.

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, 2015 and 2014, we had asset retirement obligations of $11.1 million and $10.5 million. Additionally, we had $4.8 million and $5.9 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2015 and 2014, 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 12.

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, 2015, 2014 and 2013, we included unrealized gains (losses) on open contracts of $(2.4) million, $9.6 million and $9.0 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

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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, 2015 and 2014, the Company netted $43.5 million and $25.8 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.

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,

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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 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 utilize models and other valuation methods to determine fair value when external sources are not available. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.

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 current and 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 disclosed in Note 6 regarding the new mortality tables adopted for our pension plans and the approval of the merger of the AEH 401(k) Plan with the Retirement Savings Plan, 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. On July 9, 2015, the FASB voted to approve a deferral of the effective date of the new standard by one year. With the one-year extension, the new standard is currently scheduled to become effective for us beginning on October 1, 2018 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

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

In 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. We anticipate the adoption of this standard will not have a material impact on our financial position, results of operations and cash flows.

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

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operations are geographically dispersed, they are reported as a single segment as each regulated distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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, 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	$	680,961		$	292,728		$	1,443		$	—		$	975,132

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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	$	584,065		$	249,347		$	1,839	$	—		$	835,251

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended September 30, 2013
	Regulated Distribution		Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,394,418	$	89,011		$	1,392,031		$	—		$	3,875,460
Intersegment revenues	5,075		179,889			195,883			(380,847		)	—
	2,399,493		268,900			1,587,914			(380,847		)	3,875,460
Purchased gas cost	1,318,257		—			1,524,583			(379,430		)	2,463,410
Gross profit	1,081,236		268,900			63,331			(1,417		)	1,412,050
Operating expenses
Operation and maintenance	375,188		76,686			37,569			(1,423		)	488,020
Depreciation and amortization	195,581		35,302			4,196			—			235,079
Taxes, other than income	167,374		17,059			2,639			—			187,072
Total operating expenses	738,143		129,047			44,404			(1,423		)	910,171
Operating income	343,093		139,853			18,927			6			501,879
Miscellaneous income (expense)	2,535		(2,285		)	2,316			(2,763		)	(197		)
Interest charges	98,296		30,678			2,168			(2,757		)	128,385
Income from continuing operations before income taxes	247,332		106,890			19,075			—			373,297
Income tax expense	96,476		38,630			7,493			—			142,599
Income from continuing operations	150,856		68,260			11,582			—			230,698
Income from discontinued operations, net of tax	7,202		—			—			—			7,202
Gain (loss) on sale of discontinued operations, net of tax	5,649		—			(355		)	—			5,294
Net income	$	163,707	$	68,260		$	11,227		$	—		$	243,194
Capital expenditures	$	528,599	$	313,230		$	3,204		$	—		$	845,033

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

	2015		2014		2013
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,761,689	$	1,933,099	$	1,512,495
Commercial	772,187		876,042		661,930
Industrial	74,981		90,536		81,155
Public authority and other	53,401		64,779		60,557
Total gas sales revenues	2,662,258		2,964,456		2,316,137
Transportation revenues	67,475		64,049		55,938
Other gas revenues	27,852		27,707		22,343
Total regulated distribution revenues	2,757,585		3,056,212		2,394,418
Regulated pipeline revenues	97,662		92,166		89,011
Nonregulated revenues	1,286,889		1,792,538		1,392,031
Total operating revenues	$	4,142,136	$	4,940,916	$	3,875,460

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at September 30, 2015 and 2014 by segment is presented in the following tables.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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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:

	2015		2014		2013
	(In thousands, except per share data)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	315,075	$	289,817	$	230,698
Less: Income from continuing operations allocated to participating securities	626		711		775
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from continuing operations per share — Basic	$	3.09	$	2.96	$	2.54
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	—	$	12,496
Less: Income from discontinued operations allocated to participating securities	—		—		42
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from discontinued operations per share — Basic	$	—	$	—	$	0.14
Net income per share — Basic	$	3.09	$	2.96	$	2.68
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Effect of dilutive stock options and other shares	—		—		5
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,928
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from continuing operations per share — Diluted	$	3.09	$	2.96	$	2.50
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Effect of dilutive stock options and other shares	—		—		—
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from discontinued operations per share — Diluted	$	—	$	—	$	0.14
Net income per share — Diluted	$	3.09	$	2.96	$	2.64

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the fiscal year ended September 30, 2013. As of September 30, 2015 and 2014 there were no outstanding options.

2014 Equity Offering

On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 1,200,000 shares under our existing shelf registration statement. The offering was priced at $44.00 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.

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Share Repurchase Program

On September 28, 2011 our Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a 5-year period. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. The program may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the Company deems appropriate. As of September 30, 2015, a total of 387,991 shares had been repurchased for an aggregate value of $12.5 million, with no shares repurchased since the first quarter of fiscal 2012. The share repurchase program is scheduled to end on September 30, 2016.

5.    Debt

Long-term debt

Long-term debt at September 30, 2015 and 2014 consisted of the following:

	2015		2014
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	—	$	500,000
Unsecured 6.35% Senior Notes, due 2017	250,000		250,000
Unsecured 8.50% Senior Notes, due 2019	450,000		450,000
Unsecured 5.95% Senior Notes, due 2034	200,000		200,000
Unsecured 5.50% Senior Notes, due 2041	400,000		400,000
Unsecured 4.15% Senior Notes, due 2043	500,000		500,000
Unsecured 4.125% Senior Notes, due 2044	500,000		—
Medium term 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	4,612		4,014
	$	2,455,388	$	2,455,986

On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps discussed in Note 12. The net proceeds of approximately $494 million were used to repay our $500 million4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt

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

We currently finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility, with a total availability from third-party lenders of approximately $1.3 billion of working capital funding. At September 30, 2015 and 2014, there was $457.9 million and $196.7 million outstanding under our commercial paper program with weighted average interest rates of 0.42% and 0.23%, 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 that provide approximately $1.3 billion of working capital funding. The first facility is a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 billion. On September 25, 2015, we terminated our existing $1.25 billion credit facility and entered into a new five-year $1.25 billion credit facility with substantially the same terms. The new facility also retains the $250 million accordion

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feature, which allows for an increase in the total committed loan amount to $1.5 billion. The credit facility 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, 2015, there were no borrowings under this facility, but we had $457.9 million of commercial paper outstanding leaving $792.1 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, 2015. At September 30, 2015, there were no borrowings outstanding under this facility.

The third facility which was renewed on September 30, 2015 for $10 million is a 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, 2015, 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, 2015, 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 $1.25 billion 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, 2015, our total-debt-to-total-capitalization ratio, as defined, was 49 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, 2015. We intend to seek renewal of this facility during the first quarter of fiscal 2016. There was $325.0 million outstanding under this facility at September 30, 2015.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility and one committed $15 million 364-day bilateral credit facility that expire in December 2015. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $36.1 million at September 30, 2015.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015. We intend to seek renewal of this facility during the first quarter of fiscal 2016. There were no borrowings outstanding under this facility at September 30, 2015.

Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013, that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, which generated net proceeds of $390.2 million. After giving effect to this issuance and the aforementioned $500 million senior note issuance completed in October 2014, $845 million of securities remained available for issuance under the shelf registration statement until March 28, 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, 2015. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

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Maturities of long-term debt at September 30, 2015 were as follows (in thousands):

2016	$	—
2017	250,000
2018	—
2019	450,000
2020	—
Thereafter	1,760,000
	$	2,460,000

6.    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 defined contribution plans 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 Plans			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537
September 30, 2014
Unrecognized transition obligation	$	—		$	—	$	354		$	354
Unrecognized prior service credit	(1,927		)	—		(6,168		)	(8,095		)
Unrecognized actuarial loss	109,767			34,447		7,531			151,745
	$	107,840		$	34,447	$	1,717		$	144,004

Defined Benefit Plans

Employee Pension Plans

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. 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).

The Plan also provides for an additional annual allocation based upon a participant’s age as of January 1, 1999 for those participants who were participants in the prior pension plans. The Plan credited this additional allocation each year through December 31, 2008. In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. A special grandfathered benefit also applied through December 31, 2008, for participants who were at

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least age 50 as of January 1, 1999 and who were participants in one of the prior plans on December 31, 1998. 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. In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Plan to new participants effective October 1, 2010. Additionally, employees participating in the Plan as of October 1, 2010 were allowed to make a one-time election to migrate from the Plan into our defined contribution plan, which was enhanced, effective January 1, 2011.

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 2015 and 2014 we contributed $38.0 million and $27.1 million in cash to the Plans to achieve a desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at September 30, 2015, the current funded position of the Plans and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2016. 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, 2015 and 2014.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2015		2014
Domestic equities	35%-55%	41.3	%	44.9	%
International equities	10%-20%	14.9	%	15.3	%
Fixed income	5%-30%	11.0	%	9.7	%
Company stock	0%-15%	15.2	%	12.9	%
Other assets	0%-20%	17.6	%	17.2	%

At September 30, 2015 and 2014, the Plan held 1,169,700 shares of our common stock, which represented 15.2 percent of total Plan assets and 12.9 percent of total Master Trust assets. These shares generated dividend income for the Plan of approximately $1.8 million and $1.7 million during fiscal 2015 and 2014.

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 Plans were determined as of September 30, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the Plans were determined as of September 30, 2014, 2013 and 2012. In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. On October 8, 2015, the Society of Actuaries issued an additional report related to mortality tables and the mortality improvement scale.  As of September 30, 2015, we updated our assumed mortality rates to incorporate both new sets of mortality tables issued by the Society of Actuaries.

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Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.25	%	7.25	%	7.25	%	7.75	%

The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	485,921		$	466,182
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	493,594		$	455,799
Service cost	16,231			15,345
Interest cost	21,850			22,330
Actuarial (gain) loss	7,420			26,611
Benefits paid	(30,496		)	(24,519		)
Plan amendments	—			(1,972		)
Benefit obligation at end of year	508,599			493,594
Change in plan assets:
Fair value of plan assets at beginning of year	434,767			396,887
Actual return on plan assets	8,661			35,289
Employer contributions	38,000			27,110
Benefits paid	(30,496		)	(24,519		)
Fair value of plan assets at end of year	450,932			434,767
Reconciliation:
Funded status	(57,667		)	(58,827		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Net amount recognized	$	(57,667	)	$	(58,827	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic pension cost for the Plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,231		$	15,345		$	17,754
Interest cost	21,850			22,330			19,334
Expected return on assets	(25,744		)	(23,601		)	(22,955		)
Amortization of prior service credit	(192		)	(136		)	(141		)
Recognized actuarial loss	13,322			13,777			19,066
Net periodic pension cost	$	25,467		$	27,715		$	33,058

The following table sets forth by level, within the fair value hierarchy, the Master Trust's assets at fair value as of September 30, 2015 and 2014. 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 Master Trust are fully described in Note 2. In addition to the assets shown below, the Master Trust had net accounts receivable of $2.4 million and $2.7 million at September 30, 2015 and 2014 which materially approximates fair value due to the short-term nature of these assets.

	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:
Domestic funds	33,312		—		—		33,312
International funds	48,648		—		—		48,648
Common/collective trusts — domestic funds	—		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

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	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	155,107	$	—	$	—	$	155,107
Money market funds	—		11,226		—		11,226
Registered investment companies:
Domestic funds	33,266		—		—		33,266
International funds	48,134		—		—		48,134
Common/collective trusts — domestic funds	—		91,792		—		91,792
Government securities:
Mortgage-backed securities	—		12,520		—		12,520
U.S. treasuries	3,117		562		—		3,679
Corporate bonds	—		25,734		—		25,734
Limited partnerships	—		50,496		—		50,496
Real estate	—		—		155		155
Total investments at fair value	$	239,624	$	192,330	$	155	$	432,109

During 2015, the Company determined that a 2014 investment in the registered investment companies - domestic funds should have been classified as common/collective trusts - domestic funds. The amount has been recast in the above table.

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.

On April 1, 2013, due to the retirement of certain executives, we recognized a settlement loss of $3.2 million associated with the supplemental plans and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which reduced our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year.

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, 2015 and

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2014 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2014, 2013 and 2012. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%	(1)
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

⁽¹⁾ The discount rate for the supplemental plans increased from 4.04% to 4.21% effective April 1, 2013 due to a settlement loss recorded in fiscal 2013.

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	118,835		$	106,276
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	113,219		$	117,080
Service cost	3,971			3,607
Interest cost	4,943			4,966
Actuarial (gain) loss	4,811			9,468
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Benefit obligation at end of year	122,393			113,219
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,551			21,902
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(122,393		)	(113,219		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(122,393	)	$	(113,219	)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2015 and 2014, assets held in the rabbi trusts consisted of available-for-sale securities of $41.7 million and $46.2 million, which are included in our fair value disclosures in Note 14.

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Net periodic pension cost for the supplemental plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015		2014		2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	3,971	$	3,607	$	3,039
Interest cost	4,943		4,966		4,755
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,343		1,948		2,918
Settlements	—		4,539		3,160
Net periodic pension cost	$	11,257	$	15,060	$	13,872

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 Plans		Supplemental Plans
	(In thousands)
2016	$	30,909	$	21,857
2017	31,805		13,901
2018	33,086		12,807
2019	34,712		6,808
2020	36,128		4,454
2021-2025	201,857		47,047

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.

As of September 30, 2009, the Board of Directors approved a change to the cost sharing methodology for employees who had not met the participation requirements by that date for the Atmos Retiree Medical Plan. Starting on January 1, 2015, the contribution rates that apply to all non-grandfathered participants are determined using a cost sharing methodology by which Atmos Energy will limit its contribution to a three percent cost increase in claims and administrative costs each year. If medical costs covered by the Atmos Retiree Medical Plan increase more than three percent annually, participants will be 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 $30 million and $40 million to our postretirement benefits plan during fiscal 2016.

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, 2015 and 2014.

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	Actual Allocation September 30
Security Class	2015		2014
Diversified investment funds	97.5	%	99.7	%
Cash and cash equivalents	2.5	%	0.3	%

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, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2014, 2013 and 2012. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Expected return on plan assets	4.45	%	4.60	%	4.60	%	4.60	%	4.70	%
Initial trend rate	7.50	%	7.50	%	7.50	%	8.00	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2021		2020		2020		2020		2019

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	315,118		$	312,148
Service cost	15,583			16,784
Interest cost	14,385			15,951
Plan participants’ contributions	4,563			4,435
Actuarial (gain) loss	(69,962		)	(18,963		)
Benefits paid	(12,508		)	(13,580		)
Plan amendments	—			(1,657		)
Benefit obligation at end of year	267,179			315,118
Change in plan assets:
Fair value of plan assets at beginning of year	134,821			106,413
Actual return on plan assets	(8,851		)	14,003
Employer contributions	19,984			23,550
Plan participants’ contributions	4,563			4,435
Benefits paid	(12,508		)	(13,580		)
Fair value of plan assets at end of year	138,009			134,821
Reconciliation:
Funded status	(129,170		)	(180,297		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(129,170	)	$	(180,297	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic postretirement cost for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	15,583		$	16,784		$	18,800
Interest cost	14,385			15,951			12,964
Expected return on assets	(6,431		)	(5,167		)	(3,988		)
Amortization of transition obligation	272			274			1,081
Amortization of prior service credit	(1,644		)	(1,450		)	(1,450		)
Recognized actuarial loss	—			631			4,196
Net periodic postretirement cost	$	22,165		$	27,023		$	31,603

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	$	4,288	$	(3,426	)
Effect on postretirement benefit obligation	$	39,572	$	(32,440	)

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, 2015 and 2014. 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, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,486	$	—	$	3,486
Registered investment companies:
Domestic funds	123,921		—		—		123,921
International funds	10,602		—		—		10,602
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

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	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	434	$	—	$	434
Registered investment companies:
Domestic funds	124,006		—		—		124,006
International funds	10,381		—		—		10,381
Total investments at fair value	$	134,387	$	434	$	—	$	134,821

During 2015, the Company determined that a 2014 investment in the registered investment companies - international funds should have been classified as registered investment companies - domestic funds. The amount has been recast in the above table.

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 2015 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2016	$	15,498	$	2,382	$	—	$	17,880
2017	11,245		2,677		—		13,922
2018	12,185		2,980		—		15,165
2019	12,755		3,324		—		16,079
2020	13,995		3,766		—		17,761
2021-2025	86,519		26,363		—		112,882

Defined Contribution Plans

As of September 30, 2015, we maintained two defined contribution benefit plans: the Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) and the Atmos Energy Holdings, LLC 401K Profit-Sharing Plan (the AEH 401K Profit-Sharing Plan).

The Retirement Savings Plan covers substantially all employees in our regulated operations 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, 2014, we also maintained the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401K 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 401K Plan were eligible to participate in the Retirement Savings Plan. Participants who did not actively elect to participate in the Retirement Savings Plan were automatically enrolled in the Retirement Savings Plan at a salary reduction level of four percent, which they had the choice to opt out of within 30 days. In addition, participants could have elected to transfer their funds from the Union 401K Plan to the

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Retirement Savings Plan. Effective January 1, 2015, all remaining participants became participants in the Retirement Savings Plan. Following this transfer, the Union 401K Plan was terminated.

Matching contributions to the Retirement Savings Plan and the Union 401K Plan are expensed as incurred and amounted to $11.5 million, $10.9 million and $10.4 millionfor fiscal years2015,2014and2013. 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 2015, 2014 or 2013. At September 30, 2015 and 2014, the Retirement Savings Plan held 4.3 percent and 4.5 percent of our outstanding common stock.

The AEH 401K Profit-Sharing Plan covers substantially all AEH employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Participants may elect a salary reduction up to a maximum of 75 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. The Company may elect to make safe harbor contributions up to four percent of the employee’s salary which vest immediately. The Company may also make discretionary profit sharing contributions to the AEH 401K Profit-Sharing Plan. Participants become fully vested in the discretionary profit-sharing contributions after three years of service. Participants are also permitted to take out loans against their accounts subject to certain restrictions. Discretionary contributions to the AEH 401K Profit-Sharing Plan are expensed as incurred and amounted to $1.1 million, $1.4 million and $1.1 million for fiscal years 2015, 2014 and 2013.

On November 4, 2015, the Atmos Energy Corporation Board of Directors voted to approve the merger of the assets and liabilities of the AEH 401K Profit-Sharing Plan with the Retirement Savings Plan, effective January 1, 2016 to improve administrative efficiency and reduce total costs.

7.    Stock and Other Compensation Plans

Stock-Based Compensation Plans

Total stock-based compensation expense was $27.5 million, $25.5 million and $17.8 million for the fiscal years ended September 30, 2015, 2014 and 2013, primarily related to restricted stock costs.

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, 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. As of September 30, 2015, 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 308,582 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. The associated expense is recognized ratably over the vesting period.

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

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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.

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The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2015, 2014 and 2013:

	2015				2014				2013
	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	988,637		$	42.22	1,052,844		$	36.20	1,262,582		$	32.46
Granted	444,543		50.50		464,438		45.05		473,775		40.48
Vested	(551,688	)	39.28		(524,532	)	32.67		(657,795	)	32.20
Forfeited	(3,388	)	48.55		(4,113	)	39.00		(25,718	)	33.42
Nonvested at end of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20

As of September 30, 2015, there was $10.2 million of total unrecognized compensation cost related to nonvested restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.5 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2015, 2014 and 2013 was $21.7 million, $17.1 million and $21.2 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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8.    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, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Billed accounts receivable	$	204,585		$	262,937
Unbilled revenue	65,008			62,484
Other accounts receivable	40,850			41,971
Total accounts receivable	310,443			367,392
Less: allowance for doubtful accounts	(15,283		)	(23,992		)
Net accounts receivable	$	295,160		$	343,400

Other current assets

Other current assets as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Assets from risk management activities	$	9,232	$	45,827
Deferred gas costs	9,715		20,069
Taxes receivable	4,479		5,481
Prepaid expenses	27,734		25,039
Materials and supplies	12,587		5,704
Other	6,822		9,145
Total	$	70,569	$	111,265

Property, plant and equipment

Property, plant and equipment was comprised of the following as of September 30, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Production plant	$	131		$	4,821
Storage plant	286,011			275,579
Transmission plant	1,844,117			1,622,846
Distribution plant	6,019,001			5,522,794
General plant	769,311			735,223
Intangible plant	41,131			38,858
	8,959,702			8,200,121
Construction in progress	280,398			247,579
	9,240,100			8,447,700
Less: accumulated depreciation and amortization	(1,809,520		)	(1,721,794		)
Net property, plant and equipment(1)	$	7,430,580		$	6,725,906

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

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Goodwill

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2015:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2014	$	574,816	$	132,502	$	34,711	$	742,029
Deferred tax adjustments on prior acquisitions(1)	633		40		—		673
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702

⁽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 2015.

Deferred charges and other assets

Deferred charges and other assets as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Marketable securities	$	74,200	$	79,613
Regulatory assets	182,573		230,240
Deferred financing costs	17,873		13,698
Assets from risk management activities	368		13,038
Other	13,664		14,340
Total	$	288,678	$	350,929

Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Trade accounts payable	$	78,534	$	77,860
Accrued gas payable	119,825		179,425
Accrued liabilities	40,583		50,801
Total	$	238,942	$	308,086

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Other current liabilities

Other current liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer credit balances and deposits	$	100,232	$	82,085
Accrued employee costs	47,602		46,445
Deferred gas costs	28,100		35,063
Accrued interest	34,914		36,768
Liabilities from risk management activities	9,568		1,730
Taxes payable	93,674		77,601
Pension and postretirement obligations	21,857		11,380
Current deferred tax liability	55,918		48,751
Regulatory cost of removal accrual	56,123		45,061
Other	9,966		20,985
Total	$	457,954	$	405,869

Deferred credits and other liabilities

Deferred credits and other liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer advances for construction	$	9,316	$	9,883
Regulatory liabilities	3,693		4,472
Asset retirement obligation	9,063		10,508
Liabilities from risk management activities	110,539		20,126
Other	29,085		23,881
Total	$	161,696	$	68,870

9.    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 19 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, 2015 were as follows:

	Operating Leases
	(In thousands)
2016	$	16,475
2017	16,639
2018	16,490
2019	15,207
2020	14,251
Thereafter	61,651
Total minimum lease payments	$	140,713

Consolidated lease and rental expense amounted to $32.5 million, $31.7 million and $32.4 million for fiscal 2015, 2014 and 2013.

10.    Commitments and Contingencies

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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 distribution hubs. At September 30, 2015, we were committed to purchase 36.6 Bcf within one year and 26.8 Bcf within one to three years under indexed contracts. Purchases under these contracts totaled $113.3 million, $140.9 million and $89.0 million for 2015, 2014, 2013.

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, 2015, we were committed to purchase 101.9 Bcf within one year, 16.0 Bcf within one to three years and 0.5 Bcf after three years under indexed contracts. We are committed to purchase 3.0 Bcf within one year under fixed price contracts with prices ranging from $2.32 to $3.23 per Mcf. Purchases under these contracts totaled $1,141.3 million, $1,687.5 million and $1,246.1 million for 2015, 2014 and 2013.

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, 2015 are as follows (in thousands):

2016	$	7,843
2017	3,522
2018	1,966
2019	426
2020	398
Thereafter	1,101
	$	15,256

Regulatory Matters

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 related reporting and disclosure obligations.

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11.    Income Taxes

The components of income tax expense from continuing operations for 2015, 2014 and 2013 were as follows:

	2015			2014			2013
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	7,251			5,527			8,178
Deferred
Federal	175,897			169,106			124,836
State	12,548			12,375			9,605
Investment tax credits	(6		)	(6		)	(20		)
	$	195,690		$	187,002		$	142,599

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2015, 2014 and 2013 are set forth below:

	2015			2014			2013
	(In thousands)
Tax at statutory rate of 35%	$	178,768		$	166,887		$	130,655
Common stock dividends deductible for tax reporting	(2,413		)	(2,307		)	(2,153		)
State taxes (net of federal benefit)	12,869			11,636			11,559
Change in valuation allowance	4,998			6,969			1,085
Other, net	1,468			3,817			1,453
Income tax expense	$	195,690		$	187,002		$	142,599

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, 2015 and 2014 are presented below:

	2015			2014
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	121,619		$	116,157
Interest rate agreements	51,067			10,565
Net operating loss carryforwards	313,224			236,626
Charitable and other credit carryforwards	22,281			21,614
Other	36,695			28,849
Total deferred tax assets	544,886			413,811
Valuation allowance	(10,872		)	(6,969		)
Net deferred tax assets	534,014			406,842
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(1,890,886		)	(1,655,894		)
Pension funding	(35,247		)	(17,890		)
Gas cost adjustments	(43,634		)	(31,252		)
Other	(31,480		)	(37,173		)
Total deferred tax liabilities	(2,001,247		)	(1,742,209		)
Net deferred tax liabilities	$	(1,467,233	)	$	(1,335,367	)
Deferred credits for rate regulated entities	$	412		$	(109	)

At September 30, 2015, we had $307.3 million of federal net operating loss carryforwards, which includes the impact of stock based compensation. The federal net operating loss carryforwards are available to offset taxable income and will begin to

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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 $11.4 million in charitable contribution carryforwards to offset taxable income. The Company’s charitable contribution carryforwards expire in 2015 - 2020. We believe it is more likely than not that the benefit from certain charitable contribution carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for charitable contribution carryforwards, a valuation allowance of $4.4 million and $7.0 million was established for the years ended September 30, 2015 and 2014. In addition, $1.1 million of deferred tax assets expired for which a valuation allowance had previously been recorded during the year ended September 30, 2015.

For state taxable income, the Company has $14.9 million of state net operating loss carryforwards (net of $8.0 million of federal effects) and $0.8 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 2016 and 2030. We believe it is more likely than not that a portion of the benefit from certain state net operating loss carryfowards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset for these carryforwards, a valuation allowance of $0.6 million (net of federal effects) was established for the year ended September 30, 2015. The state tax credits will begin to expire in 2018.

At September 30, 2015, we had recorded liabilities associated with unrecognized tax benefits totaling $17.1 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2015			2014
	(In thousands)
Unrecognized tax benefits - beginning balance	$	12,629		$	4,158
Increase resulting from prior period tax positions	1,009			3,846
Increase resulting from current period tax positions	3,431			4,625
Unrecognized tax benefits - ending balance	17,069			12,629
Accrued interest and penalties	820			411
Gross unrecognized tax benefits	17,889			13,040
Less: deferred federal and state income tax benefits	(6,261		)	(4,564		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	11,628		$	8,476

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.

12.    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, 2015 and 2014:

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	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2015
Assets from risk management activities, current(1)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(1)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(1)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)
September 30, 2014
Assets from risk management activities, current(2)	$	23,102		$	22,725	$	45,827
Assets from risk management activities, noncurrent	13,038			—		13,038
Liabilities from risk management activities, current(2)	(1,730		)	—		(1,730		)
Liabilities from risk management activities, noncurrent(2)	(20,126		)	—		(20,126		)
Net assets	$	14,284		$	22,725	$	37,009

⁽¹⁾  Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

⁽²⁾  Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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 2014-2015 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 37 percent, or approximately 28.2 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $4.34 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 49 months.

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•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, 2015, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 1.0 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 the anticipated issuance of $250 million 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 Treasury lock 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 Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled Treasury locks extend through fiscal 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, 2015, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of September 30, 2015, we had net long/(short) commodity contracts outstanding in the following quantities:

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Contract Type	Hedge Designation	Regulated Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(18,378	)
	Cash Flow	—	56,368
	Not designated	24,849	58,513
		24,849	96,503

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, 2015 and 2014. 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, 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		$	—

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

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of 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, 2015, 2014 and 2013, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $0.2 million, $1.9 million and $18.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our consolidated income statement for the years ended September 30, 2015, 2014 and 2013 is presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Commodity contracts	$	10,311		$	(792	)	$	2,165
Fair value adjustment for natural gas inventory designated as the hedged item	(9,768		)	2,486			15,938
Total decrease in purchased gas cost	$	543		$	1,694		$	18,103
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	811		$	(919	)	$	(208	)
Timing ineffectiveness	(268		)	2,613			18,311
	$	543		$	1,694		$	18,103

87

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, 2015, 2014 and 2013 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	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

	Fiscal Year Ended September 30, 2013
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(10,778	)	$	(10,778	)
Gain arising from ineffective portion of commodity contracts	—			97			97
Total impact on purchased gas cost	—			(10,681		)	(10,681		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(3,489		)	—			(3,489		)
Total impact from cash flow hedges	$	(3,489	)	$	(10,681	)	$	(14,170	)

88

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, 2015 and 2014. 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
	2015			2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(71,003	)	$	(58,973	)
Forward commodity contracts	(49,211		)	7,904
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	542			2,686
Forward commodity contracts	25,448			(5,102		)
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(94,224	)	$	(53,485	)

⁽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, 2015. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 and fiscal 2014 as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2016	$	(347	)	$	(19,484	)	$	(19,831	)
2017	(447		)	(5,044		)	(5,491		)
2018	(649		)	(819		)	(1,468		)
2019	(673		)	(85		)	(758		)
2020	(698		)	(5		)	(703		)
Thereafter	(15,836		)	—			(15,836		)
Total(1)	$	(18,650	)	$	(25,437	)	$	(44,087	)

⁽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, 2015, 2014 and 2013 was an increase (decrease) in purchased gas cost of $15.5 million, $(5.0) million and $3.0 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.

89

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.    Accumulated Other Comprehensive Income

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, 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	)

	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2013	$	5,448		$	37,906		$	(4,476	)	$	38,878
Other comprehensive income (loss) before reclassifications	3,009			(58,973		)	7,904			(48,060		)
Amounts reclassified from accumulated other comprehensive income	(795		)	2,686			(5,102		)	(3,211		)
Net current-period other comprehensive income (loss)	2,214			(56,287		)	2,802			(51,271		)
September 30, 2014	$	7,662		$	(18,381	)	$	(1,674	)	$	(12,393	)

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.

	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

90

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Fiscal Year Ended September 30, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	1,252		Operation and maintenance expense
	1,252			Total before tax
	(457		)	Tax expense
	$	795		Net of tax
Cash flow hedges
Interest rate agreements	$	(4,230	)	Interest charges
Commodity contracts	8,365			Purchased gas cost
	4,135			Total before tax
	(1,719		)	Tax expense
	$	2,416		Net of tax
Total reclassifications	$	3,211		Net of tax

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 6.

91

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. 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, 2015 and 2014. 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, 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

92

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

⁽¹⁾  Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

⁽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 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⁾  This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2014 we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $22.7 million is classified as current risk management assets.

93

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, 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
As of September 30, 2014
Domestic equity mutual funds	$	26,633	$	10,136	$	—		$	36,769
Foreign equity mutual funds	5,382		1,863		—			7,245
Bonds	33,266		161		(13		)	33,414
Money market funds	2,185		—		—			2,185
	$	67,466	$	12,160	$	(13	)	$	79,613

At September 30, 2015 and 2014, our available-for-sale securities included $41.7 million and $46.2 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 6. At September 30, 2015 we maintained investments in bonds that have contractual maturity dates ranging from October 2015 through September 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, 2015:

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

15.    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.

94

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

16.    Discontinued Operations

On April 1, 2013, we completed the sale of substantially all of our regulated distribution assets and certain related nonregulated assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million, pursuant to an asset purchase agreement executed on August 8, 2012. In connection with the sale, we recognized a pre-tax gain of approximately $8.2 million.

As required under generally accepted accounting principles, the operating results of our Georgia operations for the year ended September 30, 2013 have been aggregated and reported on the consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.

The following table presents statement of income data related to discontinued operations in our Georgia service area for the year ended September 30, 2013.

	Year Ended September 30, 2013
	(In thousands)
Operating revenues	$	37,962
Purchased gas cost	21,464
Gross profit	16,498
Operating expenses	5,858
Operating income	10,640
Other nonoperating income	548
Income from discontinued operations before income taxes	11,188
Income tax expense	3,986
Income from discontinued operations	7,202
Gain on sale of discontinued operations, net of tax	5,294
Net income from discontinued operations	$	12,496

95

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 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

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2014:
Operating revenues
Regulated distribution	$	843,865		$	1,290,960		$	517,707		$	409,014
Regulated pipeline	71,341			73,615			87,189			86,314
Nonregulated	436,431			758,215			465,485			407,161
Intersegment eliminations	(107,779		)	(157,936		)	(127,211		)	(113,455		)
	1,243,858			1,964,854			943,170			789,034
Gross profit	388,957			496,277			359,533			337,659
Operating income	170,720			250,080			106,605			83,944
Net income	87,016			133,367			45,721			23,713
Net income per share — basic	$	0.95		$	1.38		$	0.45		$	0.23
Net income per share — diluted	$	0.95		$	1.38		$	0.45		$	0.23

96

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, 2015 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

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, 2015, 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 6, 2015

97

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, 2015, 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, 2015, 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, 2015 and 2014, 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, 2015 of Atmos Energy Corporation and our report dated November 6, 2015 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Dallas, Texas

November 6, 2015

98

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, 2015 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 3, 2016. Information regarding executive officers is reported below:

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2015, 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	64	9	President, Chief Executive Officer and Director
Michael E. Haefner	55	7	Executive Vice President
Bret J. Eckert	48	3	Senior Vice President and Chief Financial Officer
Marvin L. Sweetin	52	15	Senior Vice President, Utility Operations
Louis P. Gregory	60	15	Senior Vice President, General Counsel and Corporate Secretary

Kim R. Cocklin was named President and designated as the Chief Executive Officer effective October 1, 2010. 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. On October 1, 2015, Mr. Cocklin was appointed to the newly-created position of Chief Executive Officer of the Company.

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.

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.

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

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

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Directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 3, 2016.

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 3, 2016.

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 3, 2016. 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 3, 2016.

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 3, 2016.

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(c) are management contracts or compensatory plans or arrangements.

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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 6, 2015

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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:

/s/    KIM R. COCKLIN	Chief Executive Officer and Director	November 6, 2015
Kim R. Cocklin
/s/    MICHAEL E. HAEFNER	President, Chief Operating Officer and Director	November 6, 2015
Michael E. Haefner
/s/    BRET J. ECKERT	Senior Vice President and Chief Financial Officer	November 6, 2015
Bret J. Eckert
/s/    CHRISTOPHER T. FORSYTHE	Vice President and Controller (Principal Accounting Officer)	November 6, 2015
Christopher T. Forsythe
/s/    ROBERT W. BEST	Chairman of the Board	November 6, 2015
Robert W. Best
/s/    RICHARD W. DOUGLAS	Director	November 6, 2015
Richard W. Douglas
/s/    RUBEN E. ESQUIVEL	Director	November 6, 2015
Ruben E. Esquivel
/s/    RICHARD K. GORDON	Director	November 6, 2015
Richard K. Gordon
/s/    ROBERT C. GRABLE	Director	November 6, 2015
Robert C. Grable
/s/    THOMAS C. MEREDITH	Director	November 6, 2015
Thomas C. Meredith
/s/    NANCY K. QUINN	Director	November 6, 2015
Nancy K. Quinn
/s/    RICHARD A. SAMPSON	Director	November 6, 2015
Richard A. Sampson
/s/    STEPHEN R. SPRINGER	Director	November 6, 2015
Stephen R. Springer
/s/    RICHARD WARE II	Director	November 6, 2015
Richard Ware II

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Schedule II

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2015

			Additions
	Balance at beginning of period		Charged to cost & expenses		Charged to other accounts		Deductions			Balance at end of period
			(In thousands)
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
2013
Allowance for doubtful accounts	$	9,425	$	14,484	$	—	$	3,285	(1)	$	20,624

⁽¹⁾  Uncollectible accounts written off.

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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	Asset Purchase Agreement by and between Atmos Energy Corporation as Seller and Liberty Energy (Georgia) Corp. as Buyer, dated as of August 8, 2012	Exhibit 2.1 to Form 8-K dated August 8, 2012 (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)

104

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	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)
10.2	Guaranty of Algonquin Power & Utilities Corp. dated August 8, 2012	Exhibit 10.1 to Form 8-K dated August 8, 2012 (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(a)*	Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 10, 2011)	Exhibit 10.14 to Form 10-K for fiscal year ended September 30, 2011 (File No. 1-10042)
10.5(b)*	Amendment No 1 to the Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 10, 2011)	Exhibit 10.8(b) to Form 10-K for fiscal year ended September 30, 2012 (File No. 1-10042)
10.5(c)*	Amendment No 2 to the Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 10, 2011)	Exhibit 10.6(c) to Form 10-K for fiscal year ended September 30, 2013 (File No. 1-10042)
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 June 4, 2012)
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)
10.8*	Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan, Effective Date August 5, 2009	Exhibit 10.10(c) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
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)

105

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*	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)
10.12(a)*	Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated September 1, 2014)	Exhibit 10.13(a) to Form 10-K for fiscal year ended September 30, 2014 (File No. 1-10042)
10.12(b)*	Form of Award Agreement of Time-Lapse Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
10.12(c)*	Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
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, 2015
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.

106

EX-10.8(A)

Exhibit 10.8(a)

ATMOS ENERGY CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

AS AMENDED AND RESTATED

EFFECTIVE AS OF JUNE 4, 2012

TABLE OF CONTENTS

Article    Page

ARTICLE I Purpose and Effective Date     1

Section 1.1. Purpose    1

Section 1.2. Effective Date    1

ARTICLE II Definitions and Construction    1

Section 2.1. Definitions    1

Section 2.2. Construction    7

Section 2.3. Governing Law    8

ARTICLE III Eligibility and Participation    8

Section 3.1. Employees Eligible to Participate    8

ARTICLE IV Assets Used for Benefits    8

Section 4.1. Amounts Provided by the Employer    8

Section 4.2. Funding    9

ARTICLE V Supplemental Pension Benefits    9

Section 5.1. Eligibility for Supplemental Pension    9

Section 5.2. Amount of Supplemental Pension    10

Section 5.3. Form of Payment of Supplemental Pension    11

Section 5.4. Commencement of Supplemental Pension    12

Section 5.5. Supplemental Pensions After a Change in Control    13

ARTICLE VI Disability Benefits    14

Section 6.1. Eligibility For Disability Benefit    14

Section 6.2. Amount of Disability Benefit    14

Section 6.3. Payment of Disability Benefit    15

Section 6.4. Payment of Supplemental Pension to Disabled

Participants    15

i

ARTICLE VII Death Benefits    15

Section 7.1. Eligibility For Death Benefit    15

Section 7.2. Amount of Death Benefit    16

Section 7.3. Form of Payment of Death Benefits    17

Section 7.4. Commencement of Death Benefits    18

ARTICLE VIII Administration    18

Section 8.1. Plan Administration    18

Section 8.2. Powers of Plan Administrator    18

Section 8.3. Calculation of Funding Obligations    19

Section 8.4. Annual Statements    19

ARTICLE IX Miscellaneous Provisions    20

Section 9.1. Amendment or Termination of the Plan    20

Section 9.2. Nonguarantee of Employment    23

Section 9.3. Nonalienation of Benefits    23

Section 9.4. Liability    23

Section 9.5. Participation Agreement    23

Section 9.6. Successors to the Employer    24

Section 9.7. Tax Withholding    24

Exhibit A    Participation Agreement

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

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

ii

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 and is being amended and restated again, effective as of June 4, 2012 (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 to June 4, 2012. Except as otherwise provided herein, any Eligible Employee who was a participant in the Prior Plan and who terminated employment prior to June 4, 2012, 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:

1

(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

2

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

3

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.

4

(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 (i) prior to June 4, 2012, was either (A) a corporate officer of the Employer selected by the Board of Directors in its discretion to participate in the Plan, or (B) 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, and (ii) from and after June 4, 2012, is either a (A) corporate officer of the Employer who is a member of the Management Committee of the Company, or (B) another corporate officer selected by the Board of Directors in its discretion 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.

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(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, 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.

(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.

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(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)

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“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 June 4, 2012, 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 June 3, 2012 shall remain a Participant and shall continue to participate in the Plan; and any other Eligible Employee who becomes a Participant shall participate in the Plan, provided he complies with the provisions of Section 9.5 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. The Employer may, in its sole discretion, establish a trust or other funding arrangement that is subject

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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:

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(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

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(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 B 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 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 B, for each full month that the date of commencement precedes age 62.

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

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actuarial assumptions used for determining actuarially equivalent lump sums as set forth in Exhibit B 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.

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(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

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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 B, 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:

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(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:

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(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

16

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 B, 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 B, 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 B, 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 B 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,

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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.

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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 C hereto. In its discretion, at any time prior to a Change in Control of the Employer, the Employer may amend Exhibit C 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 C may be changed with respect to any Participant, Retired Participant, or Beneficiary who was a Participant, Retired Participant, or Beneficiary at the time of

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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:

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(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 or June 4, 2012, 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

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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 B, 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

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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,

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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 shall enter 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 29^th day of December, 2014, to be effective as of the date set forth in Section 1.2 above.

ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN    

Kim R. Cocklin,

President and Chief Executive Officer

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EXHIBIT A

PARTICIPATION AGREEMENT

THIS PARTICIPATION 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 Supplemental Executive Retirement Plan (the “Plan”), pursuant to which certain executive or management employees of the Employer may receive supplemental pension, disability, and death benefits; and

WHEREAS, in accordance with Section 9.5 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. The capitalized terms used in the Plan shall have the same meanings in this Agreement as assigned to them in the Plan. Participant acknowledges he or she has received a copy of the Plan.

2.    Calculation of Supplemental Pension. For purposes of calculating the Participant’s Supplemental Pension under Section 5.2(a) of the Plan and other applicable provisions of the Plan, Covered Employment for the Participant commenced ___________.

3.    Delay in Payment of Supplemental Pension For Certain Participants. If a Participant who is a “specified employee,” as defined in § 1.409A-1(i) of the Final Regulations under Code Section 409A, and whose Supplemental Pension would otherwise be paid (the “Original Payment Date”) before a date which is at least six (6) months following the date of Participant’s termination of employment that constitutes a “separation from service,” as defined in Code Section 409A and the Final Regulations issued thereunder (“Separation from Service”), the Supplemental Pension shall be paid to such Participant onthe date which is six (6) months following the date of Participant’s Separation from Service (or, if earlier, the date of death of Participant),provided such six (6) month delay is required by Code Section 409A. All payments which are delayed as provided in this paragraph 3 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 September preceding the first day of the calendar year in which Participant retires or otherwise becomes entitled to payments without regard to the delay provided for in this paragraph 3.

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4.    Amendment or Termination of the Plan;Separation from Service orTermination of Participation Without Cause. The Employer hereby agrees that, if

(i)    the Employer amends or terminates the Plan in such a manner that results in a decrease in the amount of the benefits to be paid under the Plan to Participant,

(ii)    Participant incurs a Separation from Serviceby reason of Participant’s employment being terminated involuntarily by the Employer for any reason other than for Cause (as defined in subparagraph 4(e) below), or on account of Disability, or

(iii)    Participant’s participation in the Plan is terminated by the Employer for any reason other than for Cause prior to Participant’s Separation from Service with the Employer,

Participant shall have the right to, and the Employer agrees to pay to Participant, any benefits accrued prior to the effective date of such amendment or termination of the Plan or of such Participant’s Separation from Service with the Employer or termination of participation in the Plan. Such benefits shall become payable, however, only upon such an event, in accordance with the terms of the Plan or any portion thereof as in effect immediately prior to the effective date of such amendment or termination of the Plan or such Participant’s Separation from Servicewith the Employer or termination of participation in the Plan, except as otherwise permitted or required under Code Section 409A and the Treasury regulations issued thereunder. The amount of benefits that shall be paid under this paragraph 4 shall be calculated as follows:

(a)    In the event the Employer amends the Plan and such amendment results in a decrease in the amount of the Supplemental Pension, Disability Benefit, or Death Benefits that would be paid under the Plan but for the amendment thereof, the amount of Participant’s benefit shall be the sum of:

(i)    The amount derived by multiplying Participant’s benefit calculated pursuant to the terms of the Plan in effect immediately prior to the amendment and based upon Participant’s Compensation used to calculate the appropriate benefit by the following fraction: The numerator is the number of full years of Covered Employment Participant has prior to the effective date of the amendment, and the denominator is the total number of full years of Covered Employment Participant has; however, neither the numerator nor the denominator shall exceed 10; plus

(ii)    The amount derived by multiplying Participant’s benefit as calculated pursuant to the terms of the Plan as amended based upon Participant’s Compensation used to calculate the appropriate benefit by the following fraction: The numerator is the number of full years that 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 Fixed Annual

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Company Contributions allocated to him under 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 Participant has (but this number shall not exceed 10);

provided, however, that if the Plan is so amended prior to Participant being 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, Participant’s Supplemental Pension, Death Benefit or Disability Benefit payable hereunder shall be calculated solely in accordance with the terms of the Plan as amended; and provided, further, that, if such amendment occurs upon or after a “Change in Control” (as defined in subparagraph 5(b) below), Participant’s Supplemental Pension must at least equal the benefits which would be paid under Section 9.1(c) of the Plan if there was a termination of the Plan at the time of such amendment.

(b)    In the event the Employer terminates the Plan or any portion thereof and such termination adversely affects the Disability Benefit or Death Benefits described in the Plan, Participant’s Disability Benefit and Death Benefits shall be calculated as of the date of termination of such benefit or the Plan as though the date of such termination was the date that Participant became disabled or died. Such Disability Benefit and Death Benefits shall become payable, however, only upon Participant’s disability or death occurring in accordance with the terms of the Plan or any portion thereof as in effect immediately prior to the date of its termination, except as otherwise permitted or required under Code Section 409A and the Treasury regulations issued thereunder.

(c)    In the event the Employer terminates the Plan or any portion thereof and such termination adversely affects Participant’s Supplemental Pension described in the Plan, Participant’s Supplemental Pension shall be the amount determined in accordance with Section 5.2 of the Plan except that

(i)    It shall be based upon Participant’s Compensation as of the date of the termination of the Plan;

(ii)    If payment of the Supplemental Pension begins before Participant has ten full years of Covered Employment, the reduction referred to in Section 5.2(a)(i)(A) of the Plan and for purposes of the calculation made in Section 5.2(a)(ii)(A) of the Plan shall not apply;

(iii)    If payment of the Supplemental Pension begins before Participant attains age 62, the reductions referred to in Section 5.2(b) of the Plan and for purposes of the calculation made in Section 5.2(a)(ii)(A) of the Plan shall not apply; and

(iv)    If Participant is not otherwise vested (A) in the case of a Pension Plan Participant, in his retirement benefits under the Pension Plan,

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and (B) in the case of an FACC Participant, in the FACC allocated to him under the RSP, the calculations made under Section 5.2(a)(i)(B) or Section 5.2(a)(ii)(B) of the Plan shall be made as if he were so vested.

(d)    If, at any time prior to a “Change in Control” (as defined in subparagraph 5(b) below), Participant incurs a Separation from Service by reason of Participant’s employment being terminated involuntarily by the Employer for any reason other than for Cause (as defined in subparagraph 4(e) below), or on account of Disability, or if Participant’s participation in the Plan is terminated by the Employer for any reason other than for Cause, Participant shall nevertheless be entitled to the benefits under the Plan that have accrued prior to Participant’s Separation from Service or the termination of Plan participation, the amount of such benefits to be calculated in the manner set forth in Section 5.2(c) of the Plan and payable at such time and form as otherwise provided for under the Plan; provided, however, that Participant’s right to a Supplemental Pension shall vest only if Participant has at least three years of Covered Employment and 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, as of the date of such termination.

(e)    As used in this Agreement, “Cause” for Separation from Service shall mean termination upon

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

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

For purposes of this subparagraph, no act, or failure to act, on Participant’s part shall be deemed “willful” if done, or omitted to be done, by 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, Participant shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to 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 Participant and an opportunity for Participant, together with Participant’s counsel, to be heard before the Board of Directors), finding that in the good faith opinion of the Board of Directors that Participant was guilty of conduct set forth above in subparagraph (i) or (ii) and specifying the particulars thereof in detail.

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5.    Change in Control.

(a)    Notwithstanding anything expressly or impliedly to the contrary contained in this Agreement or the Plan, if, at any time during the three (3)-year period immediately following a Change in Control of the Employer, Participant incurs a Separation from Service by reason of Participant’s employment being terminated involuntarily by the Employer for any reason other than for Cause (as defined in subparagraph 4(e) above), or he is demoted or reassigned to a position that causes him to cease to be an Eligible Employee, for any reason other than for Cause (as defined in subparagraph 4(e) above), Participant shall nevertheless be entitled to receive a Supplemental Pension at such time as he becomes entitled to receive a benefit under the Plan regardless of whether Participant has at least three years of Covered Employment or 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 termination, demotion, or reassignment. If a Participant’s incurs a Separation from Service by reason of Participant’s employment being terminated 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 from Service or termination either (i) 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 (ii) 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. Such Supplemental Pension shall be calculated in the same manner as set forth in subparagraph 4(c) above for benefits payable in the event of a termination of the Plan.

(b)    (i)    As used in this Agreement, except as provided herein, 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

5

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

6

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 subparagraph 5(b) 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 subparagraph 5(b) shall be in compliance with the requirements of said Code Section and said Regulations.

6.    Limitations. Except as otherwise provided in paragraph 5 of this Agreement, Participant agrees that nothing in this Agreement or the Plan shall entitle him, or be deemed to entitle him, to receive a Supplemental Pension under the Plan if:

(a)    he has not met the requirements for a Supplemental Pension as set forth in the Plan,

(b)    his employment with the Employer has not terminated, or

(c)    his employment with the Employer or participation in the Plan is terminated for Cause (as defined in subparagraph 4(e) above).

7.    Amendment or Termination. No amendment or termination of the Plan by the Employer shall constitute an amendment or termination of this Agreement. This Agreement may be amended or modified only by the written agreement of the parties hereto, and will terminate only upon the occurrence of the earlier of the following events: (a) the execution of a written agreement to terminate this Agreement signed by all of the parties hereto, (b) the satisfaction of all of the Employer’s obligations to Participant under the Plan and this Agreement, (c) the termination by Participant of Participant’s employment with the Employer by resignation effective prior to Participant being eligible to Retire, or (d) the termination for Cause of Participant’s employment

7

with the Employer. Notwithstanding any of the terms and conditions of this Participation Agreement or Section 9.1 of the Plan to the contrary, the Board of Directors reserves the right, in its sole discretion, to amend the Plan and/or this Participation Agreement in any manner it deems necessary or desirable in order to comply with or otherwise address issues resulting from Code Section 409A.

8.    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 under this Agreement and/or the Plan to Participant, regardless of whether Participant is then eligible to Retire or to receive an unreduced Supplemental Pension. The amount required to be funded by this paragraph 8 shall be calculated in accordance with paragraph 9 hereof. The Employer shall review the funding status of the trust or other funding arrangement established under this paragraph 8 on an annual basis and shall make 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.

9.    Calculation of Funding Obligations. The Employer shall calculate its funding obligations under this Agreement and the Plan solely by using the actuarial assumptions and methodology set forth in Exhibit C to the Plan. Upon and after a Change in Control of the Employer which occurs at a time when Participant is an Eligible Employee, the actuarial assumptions and methodology set forth in Exhibit C may be changed with respect to Participant or, if applicable, his Beneficiary, only with Participant’s, or, if applicable, his Beneficiary’s, written consent.

10.    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 Subsidiaries 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

8

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.

11.    Annual Statements. As soon as practicable after the end of each Plan Year, the Employer shall deliver to Participant or, if applicable, his Beneficiary, a statement containing (a) the present value of the Employer’s future benefit obligations to Participant, or, if applicable, his Beneficiary; (b) the actuarial assumptions used to calculate the present value of the Employer’s future benefit obligations under the Plan; 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.

12.    No Guarantee of Employment. Nothing contained in this Agreement shall be construed as a contract of employment between the Employer and Participant, or as a right of Participant to be continued in the employment of the Employer, or as a limitation of the right of the Employer to discharge Participant with or without cause.

13.    Legal Fees and Expenses. The Employer agrees to pay any and all legal fees and expenses incurred by Participant in seeking to obtain or enforce any right or benefit provided by this Agreement.

14.    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.

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15.    Agreement Binding on 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 this Agreement in the same manner and to the same extent as the Employer.

16.    Prior Agreements Superseded. The terms of this Agreement supersede the terms of all prior Participation Agreements between Participant and the Employer.

17.    Governing Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Texas.

IN WITNESS WHEREOF, the parties hereto have executed this Participation Agreement as of the date first written above.

PARTICIPANT:                ATMOS ENERGY CORPORATION:

By:

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EXHIBIT B

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).

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EXHIBIT C

ATMOS ENERGY CORPORATION

SUMMARY OF ACTUARIAL ASSUMPTIONS AND METHODS

FOR

DETERMINING SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN TRUST

ANNUAL FUNDING LIABILITIES

Actuarial Assumptions

Discount Rate                        8%

Mortality

Prior to Age 62                None

After Age 62                    Code Section 417(e)(3)

Applicable Mortality Table*

Salary Scale                        0%

Benefit Percentage                    60%

*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.

1

EX-10.13(B)

Exhibit 10.13(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 5, 2015, 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 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 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 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.

ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN            

    Kim R. Cocklin

    President and

Chief Executive Officer

1

EX-10.13(C)

Exhibit 10.13(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 5, 2015, 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.

1

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 2015 through 2017 (October 1, 2014 through September 30, 2017). 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-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 2015-2017
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.

2

(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.

(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

3

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 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

4

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.

5

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 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

    President and

Chief Executive Officer    

6

EX-12

Exhibit 12

Atmos Energy Corporation

Computation of Earnings to Fixed Charges

	Year Ended September 30
	2015		2014		2013		2012		2011
	(Dollars in thousands)
Income from continuing operations before provision for income taxes per statement of income	$	510,765	$	476,819	$	373,297	$	290,422	$	296,407
Add:
Portion of rents representative of the interest factor	12,383		12,231		12,442		12,623		13,229
Interest on debt & amortization of debt expense	116,241		129,295		128,385		141,174		150,763
Income as adjusted	$	639,389	$	618,345	$	514,124	$	444,219	$	460,399
Fixed charges:
Interest on debt & amortization of debt expense (1)	$	116,241	$	129,295	$	128,385	$	141,174	$	150,763
Capitalized interest (2)	2,260		1,522		1,895		2,642		1,690
Rents	37,150		36,693		37,326		37,868		39,686
Portion of rents representative of the interest factor (3)	12,383		12,231		12,442		12,623		13,229
Fixed charges (1)+(2)+(3)	$	130,884	$	143,048	$	142,722	$	156,439	$	165,682
Ratio of earnings to fixed charges	4.89		4.32		3.60		2.84		2.78

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 subsidiary of 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-3ASR, No. 333-187606; 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; and Form S-8, No. 333-199301) of Atmos Energy Corporation and in the related Prospectuses of our reports dated November 6, 2015, 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, 2015.

/s/ ERNST & YOUNG LLP

Dallas, Texas

November 6, 2015

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 6, 2015

/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 6, 2015

/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, 2015, 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 6, 2015

/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, 2015, 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 6, 2015

/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

Commitments and Contingencies (Table)

12 Months Ended

Sep. 30, 2015

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, 2015 are as follows (in thousands):

2016	$	7,843
2017	3,522
2018	1,966
2019	426
2020	398
Thereafter	1,101
	$	15,256

XML

Retirement and Post-Retirement Employee Benefit Plans Net Periodic Cost (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 02, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 16,231	$ 15,345	$ 17,754
Interest cost		21,850	22,330	19,334
Expected return on assets		(25,744)	(23,601)	(22,955)
Amortization of prior service cost		(192)	(136)	(141)
Recognized actuarial loss		13,322	13,777	19,066
Net periodic pension cost		25,467	27,715	33,058
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		3,971	3,607	3,039
Interest cost		4,943	4,966	4,755
Amortization of transition asset		0	0	0
Amortization of prior service cost		0	0	0
Recognized actuarial loss		2,343	1,948	2,918
Settlements	$ 3,200	0	4,539	3,160
Net periodic pension cost		11,257	15,060	13,872
Effect on Net Periodic Cost Due To Discount Rate Change, Remaining Fiscal Year	$ (100)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		15,583	16,784	18,800
Interest cost		14,385	15,951	12,964
Expected return on assets		(6,431)	(5,167)	(3,988)
Amortization of transition asset		272	274	1,081
Amortization of prior service cost		(1,644)	(1,450)	(1,450)
Recognized actuarial loss		0	631	4,196
Net periodic pension cost		$ 22,165	$ 27,023	$ 31,603

XML

Segment Information (Details) $ in Thousands, customers in Millions		3 Months Ended										12 Months Ended
		Sep. 30, 2015 USD ($) customers regulated_gas_distributions_divisions state		Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)		Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 30, 2015 USD ($) customers regulated_gas_distributions_divisions state segment		Sep. 30, 2014 USD ($)		Sep. 30, 2013 USD ($)	Sep. 30, 2012 USD ($)
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		$ 656,902		$ 686,401	$ 1,540,068	$ 1,258,765	$ 789,034		$ 943,170	$ 1,964,854	$ 1,243,858	$ 4,142,136		$ 4,940,916		$ 3,875,460
Purchased gas cost												2,462,119		3,358,490		2,463,410
Gross profit		354,321		381,673	520,738	423,285	337,659		359,533	496,277	388,957	1,680,017		1,582,426		1,412,050
Operating expenses
Operation and maintenance												541,868		505,154		488,020
Depreciation and amortization												274,796		253,987		235,079
Taxes, other than income												231,958		211,936		187,072
Total operating expenses												1,048,622		971,077		910,171
Operating income		75,853		117,607	250,210	187,725	83,944		106,605	250,080	170,720	631,395		611,349		501,879
Miscellaneous income (expense), net												(4,389)		(5,235)		(197)
Interest charges												116,241		129,295		128,385
Income (loss) before income taxes												510,765		476,819		373,297
Income tax expense												195,690		187,002		142,599
Income (loss) from continuing operations												315,075		289,817		230,698
Income from discontinued operations, net of tax												0		0		7,202
Gain (loss) on sale of discontinued operations, net of tax												0		0		5,294
Net income		23,515		56,281	137,684	97,595	23,713		45,721	133,367	87,016	315,075		289,817		243,194
Capital expenditures												975,132		835,251		845,033
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues		656,902		686,401	1,540,068	1,258,765	789,034		943,170	1,964,854	1,243,858	4,142,136		4,940,916		3,875,460
ASSETS
Net property, plant and equipment	[1]	7,430,580					6,725,906					7,430,580		6,725,906
Investment in subsidaries		0					0					0		0
Current assets
Cash and cash equivalents		28,653					42,258					28,653		42,258		66,199	$ 64,239
Assets from risk management activities current		9,232					45,827					9,232		45,827
Other current assets		593,100					687,755					593,100		687,755
Intercompany receivables		0					0					0		0
Total current assets		630,985					775,840					630,985		775,840
Goodwill		742,702					742,029					742,702		742,029
Assets from risk management activities noncurrent		368					13,038					368		13,038
Deferred charges and other assets		288,310					337,891					288,310		337,891
Total assets		9,092,945					8,594,704					9,092,945		8,594,704
CAPITALIZATION AND LIABILITIES
Shareholders' equity		3,194,797					3,086,232					3,194,797		3,086,232		2,580,409	$ 2,359,243
Long-term debt		2,455,388					2,455,986					2,455,388		2,455,986
Total capitalization		5,650,185					5,542,218					5,650,185		5,542,218
Current liabilities
Short-term debt		457,927					196,695					457,927		196,695
Liabilities from risk management activities current		9,568					1,730					9,568		1,730
Other current liabilities		687,328					712,225					687,328		712,225
Intercompany payables		0					0					0		0
Total current liabilities		1,154,823					910,650					1,154,823		910,650
Deferred income taxes		1,411,315					1,286,616					1,411,315		1,286,616
Liabilities from risk management activities noncurrent		110,539					20,126					110,539		20,126
Regulatory cost of removal obligation		427,553					445,387					427,553		445,387
Pension and postretirement liabilities		287,373					340,963					287,373		340,963
Deferred credits and other liabilities		51,157					48,744					51,157		48,744
Total shareholders' equity and liabilities		$ 9,092,945					8,594,704					$ 9,092,945		8,594,704
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												$ 4,142,136		4,940,916		3,875,460
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												4,142,136		4,940,916		3,875,460
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 from external parties												2,757,585		3,056,212		2,394,418
Operating revenues		$ 369,656		416,794	1,130,613	846,772	409,014		517,707	1,290,960	843,865	2,763,835		3,061,546		2,399,493
Purchased gas cost												1,526,258		1,885,031		1,318,257
Gross profit												1,237,577		1,176,515		1,081,236
Operating expenses
Operation and maintenance												388,486		387,228		375,188
Depreciation and amortization												223,048		208,376		195,581
Taxes, other than income												205,894		196,343		167,374
Total operating expenses												817,428		791,947		738,143
Operating income												420,149		384,568		343,093
Miscellaneous income (expense), net												(377)		(381)		2,535
Interest charges												84,132		94,918		98,296
Income (loss) before income taxes												335,640		289,269		247,332
Income tax expense												130,827		117,684		96,476
Income (loss) from continuing operations																150,856
Income from discontinued operations, net of tax																7,202
Gain (loss) on sale of discontinued operations, net of tax																5,649
Net income												204,813		171,585		163,707
Capital expenditures												680,961		584,065		528,599
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												2,757,585		3,056,212		2,394,418
Operating revenues		369,656		416,794	1,130,613	846,772	409,014		517,707	1,290,960	843,865	2,763,835		3,061,546		2,399,493
ASSETS
Net property, plant and equipment		5,670,306					5,202,761					5,670,306		5,202,761
Investment in subsidaries		1,038,670					952,171					1,038,670		952,171
Current assets
Cash and cash equivalents		23,863					33,303					23,863		33,303
Assets from risk management activities current		378					23,102					378		23,102
Other current assets		426,270					490,408					426,270		490,408
Intercompany receivables		887,713					790,442					887,713		790,442
Total current assets		1,338,224					1,337,255					1,338,224		1,337,255
Goodwill		575,449					574,816					575,449		574,816
Assets from risk management activities noncurrent		368					13,038					368		13,038
Deferred charges and other assets		265,693					309,965					265,693		309,965
Total assets		8,888,710					8,390,006					8,888,710		8,390,006
CAPITALIZATION AND LIABILITIES
Shareholders' equity		3,194,797					3,086,232					3,194,797		3,086,232
Long-term debt		2,455,388					2,455,986					2,455,388		2,455,986
Total capitalization		5,650,185					5,542,218					5,650,185		5,542,218
Current liabilities
Short-term debt		782,927					522,695					782,927		522,695
Liabilities from risk management activities current		9,568					1,730					9,568		1,730
Other current liabilities		569,273					559,765					569,273		559,765
Intercompany payables		0					0					0		0
Total current liabilities		1,361,768					1,084,190					1,361,768		1,084,190
Deferred income taxes		1,008,091					913,260					1,008,091		913,260
Liabilities from risk management activities noncurrent		110,539					20,126					110,539		20,126
Regulatory cost of removal obligation		427,553					445,387					427,553		445,387
Pension and postretirement liabilities		287,373					340,963					287,373		340,963
Deferred credits and other liabilities		43,201					43,862					43,201		43,862
Total shareholders' equity and liabilities		8,888,710					8,390,006					8,888,710		8,390,006
Regulated Distribution Segment [Member] | Gas Sales Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												2,662,258		2,964,456		2,316,137
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												2,662,258		2,964,456		2,316,137
Regulated Distribution Segment [Member] | Gas Sales Revenues [Member] | Residential Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												1,761,689		1,933,099		1,512,495
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												1,761,689		1,933,099		1,512,495
Regulated Distribution Segment [Member] | Gas Sales Revenues [Member] | Commercial Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												772,187		876,042		661,930
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												772,187		876,042		661,930
Regulated Distribution Segment [Member] | Gas Sales Revenues [Member] | Industrial Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												74,981		90,536		81,155
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												74,981		90,536		81,155
Regulated Distribution Segment [Member] | Gas Sales Revenues [Member] | Public Authority and Other Customers [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												53,401		64,779		60,557
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												53,401		64,779		60,557
Regulated Distribution Segment [Member] | Gas Transportation Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												67,475		64,049		55,938
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												67,475		64,049		55,938
Regulated Distribution Segment [Member] | Other Gas Revenues [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												27,852		27,707		22,343
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												27,852		27,707		22,343
Regulated Distribution Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												2,757,585		3,056,212		2,394,418
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												2,757,585		3,056,212		2,394,418
Regulated Distribution Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												6,250		5,334		5,075
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												6,250		5,334		5,075
Regulated Pipeline Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												97,662		92,166		89,011
Operating revenues		97,807		97,008	91,730	83,567	86,314		87,189	73,615	71,341	370,112		318,459		268,900
Purchased gas cost												0		0		0
Gross profit												370,112		318,459		268,900
Operating expenses
Operation and maintenance												118,866		91,466		76,686
Depreciation and amortization												47,236		41,031		35,302
Taxes, other than income												22,743		13,143		17,059
Total operating expenses												188,845		145,640		129,047
Operating income												181,267		172,819		139,853
Miscellaneous income (expense), net												(1,243)		(3,181)		(2,285)
Interest charges												33,151		36,280		30,678
Income (loss) before income taxes												146,873		133,358		106,890
Income tax expense												52,211		47,167		38,630
Income (loss) from continuing operations																68,260
Income from discontinued operations, net of tax																0
Gain (loss) on sale of discontinued operations, net of tax																0
Net income												94,662		86,191		68,260
Capital expenditures												292,728		249,347		313,230
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												97,662		92,166		89,011
Operating revenues		97,807		97,008	91,730	83,567	86,314		87,189	73,615	71,341	370,112		318,459		268,900
ASSETS
Net property, plant and equipment		1,706,449					1,464,572					1,706,449		1,464,572
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		24,628					14,009					24,628		14,009
Intercompany receivables		0					0					0		0
Total current assets		24,628					14,009					24,628		14,009
Goodwill		132,542					132,502					132,542		132,502
Assets from risk management activities noncurrent		0					0					0		0
Deferred charges and other assets		17,288					21,826					17,288		21,826
Total assets		1,880,907					1,632,909					1,880,907		1,632,909
CAPITALIZATION AND LIABILITIES
Shareholders' equity		577,275					482,612					577,275		482,612
Long-term debt		0					0					0		0
Total capitalization		577,275					482,612					577,275		482,612
Current liabilities
Short-term debt		0					0					0		0
Liabilities from risk management activities current		0					0					0		0
Other current liabilities		29,780					24,790					29,780		24,790
Intercompany payables		867,409					763,635					867,409		763,635
Total current liabilities		897,189					788,425					897,189		788,425
Deferred income taxes		406,254					361,688					406,254		361,688
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		189					184					189		184
Total shareholders' equity and liabilities		1,880,907					1,632,909					1,880,907		1,632,909
Regulated Pipeline Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												97,662		92,166		89,011
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												97,662		92,166		89,011
Regulated Pipeline Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												272,450		226,293		179,889
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												272,450		226,293		179,889
Nonregulated Segment [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												1,286,889		1,792,538		1,392,031
Operating revenues		292,830		278,769	438,322	462,288	407,161		465,485	758,215	436,431	1,472,209		2,067,292		1,587,914
Purchased gas cost												1,399,349		1,979,337		1,524,583
Gross profit												72,860		87,955		63,331
Operating expenses
Operation and maintenance												35,048		26,963		37,569
Depreciation and amortization												4,512		4,580		4,196
Taxes, other than income												3,321		2,450		2,639
Total operating expenses												42,881		33,993		44,404
Operating income												29,979		53,962		18,927
Miscellaneous income (expense), net												(760)		2,216		2,316
Interest charges												967		1,986		2,168
Income (loss) before income taxes												28,252		54,192		19,075
Income tax expense												12,652		22,151		7,493
Income (loss) from continuing operations																11,582
Income from discontinued operations, net of tax																0
Gain (loss) on sale of discontinued operations, net of tax																(355)
Net income												15,600		32,041		11,227
Capital expenditures												1,443		1,839		3,204
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												1,286,889		1,792,538		1,392,031
Operating revenues		292,830		278,769	438,322	462,288	407,161		465,485	758,215	436,431	1,472,209		2,067,292		1,587,914
ASSETS
Net property, plant and equipment		53,825					58,573					53,825		58,573
Investment in subsidaries		(2,096)					(2,096)					(2,096)		(2,096)
Current assets
Cash and cash equivalents		4,790					8,955					4,790		8,955
Assets from risk management activities current		8,854	[2]				22,725	[3]				8,854	[2]	22,725	[3]
Other current assets		480,503					526,161					480,503		526,161
Intercompany receivables		0					0					0		0
Total current assets		494,147					557,841					494,147		557,841
Goodwill		34,711					34,711					34,711		34,711
Assets from risk management activities noncurrent		0					0					0		0
Deferred charges and other assets		5,329					6,100					5,329		6,100
Total assets		585,916					655,129					585,916		655,129
CAPITALIZATION AND LIABILITIES
Shareholders' equity		461,395					469,559					461,395		469,559
Long-term debt		0					0					0		0
Total capitalization		461,395					469,559					461,395		469,559
Current liabilities
Short-term debt		0					0					0		0
Liabilities from risk management activities current		0	[2]				0	[3]				0	[2]	0	[3]
Other current liabilities		99,480					142,397					99,480		142,397
Intercompany payables		20,304					26,807					20,304		26,807
Total current liabilities		119,784					169,204					119,784		169,204
Deferred income taxes		(3,030)					11,668					(3,030)		11,668
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		7,767					4,698					7,767		4,698
Total shareholders' equity and liabilities		585,916					655,129					585,916		655,129
Nonregulated Segment [Member] | Reportable Subsegments [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												1,286,889		1,792,538		1,392,031
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												1,286,889		1,792,538		1,392,031
Nonregulated Segment [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues from external parties												185,320		274,754		195,883
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												185,320		274,754		195,883
Intersegment Elimination [Member]
Segment Reporting Information Profit Loss [Abstract]
Operating revenues		(103,391)		(106,170)	(120,597)	(133,862)	(113,455)		(127,211)	(157,936)	(107,779)	(464,020)		(506,381)		(380,847)
Purchased gas cost												(463,488)		(505,878)		(379,430)
Gross profit												(532)		(503)		(1,417)
Operating expenses
Operation and maintenance												(532)		(503)		(1,423)
Depreciation and amortization												0		0		0
Taxes, other than income												0		0		0
Total operating expenses												(532)		(503)		(1,423)
Operating income												0		0		6
Miscellaneous income (expense), net												(2,009)		(3,889)		(2,763)
Interest charges												(2,009)		(3,889)		(2,757)
Income (loss) before income taxes												0		0		0
Income tax expense												0		0		0
Income (loss) from continuing operations																0
Income from discontinued operations, net of tax																0
Gain (loss) on sale of discontinued operations, net of tax																0
Net income												0		0		0
Capital expenditures												0		0		0
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues		(103,391)		$ (106,170)	$ (120,597)	$ (133,862)	(113,455)		$ (127,211)	$ (157,936)	$ (107,779)	(464,020)		(506,381)		(380,847)
ASSETS
Net property, plant and equipment		0					0					0		0
Investment in subsidaries		(1,036,574)					(950,075)					(1,036,574)		(950,075)
Current assets
Cash and cash equivalents		0					0					0		0
Assets from risk management activities current		0					0					0		0
Other current assets		(338,301)					(342,823)					(338,301)		(342,823)
Intercompany receivables		(887,713)					(790,442)					(887,713)		(790,442)
Total current assets		(1,226,014)					(1,133,265)					(1,226,014)		(1,133,265)
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		(2,262,588)					(2,083,340)					(2,262,588)		(2,083,340)
CAPITALIZATION AND LIABILITIES
Shareholders' equity		(1,038,670)					(952,171)					(1,038,670)		(952,171)
Long-term debt		0					0					0		0
Total capitalization		(1,038,670)					(952,171)					(1,038,670)		(952,171)
Current liabilities
Short-term debt		(325,000)					(326,000)					(325,000)		(326,000)
Liabilities from risk management activities current		0					0					0		0
Other current liabilities		(11,205)					(14,727)					(11,205)		(14,727)
Intercompany payables		(887,713)					(790,442)					(887,713)		(790,442)
Total current liabilities		(1,223,918)					(1,131,169)					(1,223,918)		(1,131,169)
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		$ (2,262,588)					$ (2,083,340)					(2,262,588)		(2,083,340)
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												(464,020)		(506,381)		(380,847)
Revenue from External Customers by Products and Services Table [Abstract]
Operating revenues from external parties												$ (464,020)		$ (506,381)		$ (380,847)

[1] Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

[2] Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

[3] Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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Accumulated Other Comprehensive Income Affected Line Item in the Statement of Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance	$ (541,868)	$ (505,154)	$ (488,020)
Interest charges	(116,241)	(129,295)	(128,385)
Purchased gas cost	(2,462,119)	(3,358,490)	(2,463,410)
Income (loss) before income taxes	510,765	476,819	373,297
Income Tax Expense (Benefit)	(195,690)	(187,002)	(142,599)
Income (loss) from continuing operations	315,075	289,817	$ 230,698
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income (loss) from continuing operations	(25,450)	3,211
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	850	1,252
Income (loss) before income taxes	850	1,252
Income Tax Expense (Benefit)	(310)	(457)
Income (loss) from continuing operations	540	795
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	(42,569)	4,135
Income Tax Expense (Benefit)	16,579	(1,719)
Income (loss) from continuing operations	(25,990)	2,416
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	(853)	(4,230)
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	$ (41,716)	$ 8,365

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Retirement and Post-Retirement Employee Benefit Plans Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Retirement Savings Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	65.00%
Defined Contribution Plan, Deferral Rate	4.00%
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	4.30%	4.50%
Defined Contribution Plan, Vesting Period	3 years
AEH 401K Profit-Sharing Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 1.1	$ 1.4	$ 1.1
Defined Contribution Plan, Vesting Period	3 years
Defined Contribution Plan, Employer Safe Harbor Contribution, Percent	4.00%
Retirement Savings Plan and Union 401K Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 11.5	$ 10.9	$ 10.4

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Nature of Business (Details) customers in Thousands	Sep. 30, 2015 customers regulated_gas_distributions_divisions	Sep. 30, 2013 customers
Schedule of Number of Customers, Discontinued Operations [Line Items]
Number Of Customers, Regulated Distribution	3,000
Number Of Divisions, Regulated Distribution | regulated_gas_distributions_divisions	6
Georgia, Illinois, Iowa and Missouri [Member]
Schedule of Number of Customers, Discontinued Operations [Line Items]
Number Of Customers, Regulated Distribution		148

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Earnings Per Share (Table)

12 Months Ended

Sep. 30, 2015

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:

	2015		2014		2013
	(In thousands, except per share data)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	315,075	$	289,817	$	230,698
Less: Income from continuing operations allocated to participating securities	626		711		775
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from continuing operations per share — Basic	$	3.09	$	2.96	$	2.54
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	—	$	12,496
Less: Income from discontinued operations allocated to participating securities	—		—		42
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from discontinued operations per share — Basic	$	—	$	—	$	0.14
Net income per share — Basic	$	3.09	$	2.96	$	2.68
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Effect of dilutive stock options and other shares	—		—		5
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,928
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from continuing operations per share — Diluted	$	3.09	$	2.96	$	2.50
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Effect of dilutive stock options and other shares	—		—		—
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from discontinued operations per share — Diluted	$	—	$	—	$	0.14
Net income per share — Diluted	$	3.09	$	2.96	$	2.64

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Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	$ 0	$ 0	$ 8,203
Discontinued Operation Income Loss From Discontinued Operation Disclosures Abstract
Operating revenues			37,962
Purchased gas cost			21,464
Gross profit			16,498
Operating expenses			5,858
Operating income			10,640
Discontinued Operations Miscellaneous Income Expense			548
Income from discontinued operations before income taxes			11,188
Income tax expense	0	0	3,986
Income (loss) from discontinued operations	0	0	7,202
Gain (loss) on sale of discontinued operations, net of tax	0	0	5,294
Net income (loss) from discontinued operations	$ 0	$ 0	12,496
Georgia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Cash Price Received from Disposal of Discontinued Operation			153,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax			$ 8,200

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Details of Selected Consolidated Balance Sheet Captions (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015		Sep. 30, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		$ 310,443		$ 367,392
Less: allowance for doubtful accounts		(15,283)		(23,992)
Net accounts receivable		295,160		343,400
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		9,232		45,827
Deferred gas cost		9,715		20,069
Taxes receivable		4,479		5,481
Prepaid expenses		27,734		25,039
Materials and supplies		12,587		5,704
Other		6,822		9,145
Total other current assets		70,569		111,265
Public Utilities, Property, Plant and Equipment [Abstract]
Production plant		131		4,821
Storage plant		286,011		275,579
Transmission plant		1,844,117		1,622,846
Distribution plant		6,019,001		5,522,794
General plant		769,311		735,223
Intangible plant		41,131		38,858
Property, plant and equipment		8,959,702		8,200,121
Construction in progress		280,398		247,579
Total property, plant and equipment and construction in progress		9,240,100		8,447,700
Less accumulated depreciation and amortization		(1,809,520)		(1,721,794)
Net property, plant and equipment	[1]	7,430,580		6,725,906
Plant acquisition adjustments		(68,100)		(76,400)
Goodwill [Line Items]
Goodwill, Beginning Balance		742,029
Goodwill, Other Changes	[2]	673
Goodwill, Ending Balance		742,702
Schedule of Other Noncurrent Assets [Abstract]
Marketable securities		74,200		79,613
Regulatory assets		182,573		230,240
Deferred financing costs		17,873		13,698
Assets from risk management activities noncurrent		368		13,038
Other		13,664		14,340
Total		288,678		350,929
Schedule of Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable		78,534		77,860
Accrued gas payable		119,825		179,425
Accrued liabilities		40,583		50,801
Total		238,942		308,086
Schedule of Other Current Liabilities [Abstract]
Customer deposits		100,232		82,085
Accrued employee costs		47,602		46,445
Deferred gas costs		28,100		35,063
Accrued interest		34,914		36,768
Liabilities from risk management activities current		9,568		1,730
Taxes payable		93,674		77,601
Pension and postretirement obligations		21,857		11,380
Regulatory cost of removal accrual		56,123		45,061
Current deferred tax liability		55,918		48,751
Other		9,966		20,985
Total		457,954		405,869
Schedule of Other Noncurrent Liabilities [Abstract]
Customer advances for construction		9,316		9,883
Regulatory liabilities		3,693		4,472
Asset retirement obligation		9,063		10,508
Liabilities from risk management activities noncurrent		110,539		20,126
Other		29,085		23,881
Total		161,696		68,870
Regulated Distribution Segment [Member]
Schedule of Other Current Assets [Abstract]
Assets from risk management activities current		378		23,102
Public Utilities, Property, Plant and Equipment [Abstract]
Net property, plant and equipment		5,670,306		5,202,761
Goodwill [Line Items]
Goodwill, Beginning Balance		574,816
Goodwill, Other Changes	[2]	633
Goodwill, Ending Balance		575,449
Schedule of Other Noncurrent Assets [Abstract]
Assets from risk management activities noncurrent		368		13,038
Schedule of Other Current Liabilities [Abstract]
Liabilities from risk management activities current		9,568		1,730
Schedule of Other Noncurrent Liabilities [Abstract]
Liabilities from risk management activities noncurrent		110,539		20,126
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		1,706,449		1,464,572
Goodwill [Line Items]
Goodwill, Beginning Balance		132,502
Goodwill, Other Changes	[2]	40
Goodwill, Ending Balance		132,542
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		8,854	[3]	22,725	[4]
Public Utilities, Property, Plant and Equipment [Abstract]
Net property, plant and equipment		53,825		58,573
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		204,585		262,937
Trade Accounts Receivable [Member] | Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		65,008		62,484
Other Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current		$ 40,850		$ 41,971

[1] Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

[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 2015.

[3] Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

[4] Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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Fair Value Measurements (Details) - USD ($) $ in Thousands		Sep. 30, 2015		Sep. 30, 2014
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		$ (82,509)	[1]	$ (46,298)	[2]
Derivative Asset		9,600		58,865
Hedged portion of gas stored underground		43,901		40,492
Available-for-sale Securities		74,200		79,613
Total assets		127,701		178,970
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(125,983)	[1]	(72,056)	[2]
Derivative Liability		120,107		21,856
Additional Fair Value Elements [Abstract]
Cash Held in Margin Accounts		43,500		25,800
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities		34,600		3,100
Cash Held In Margin Accounts Classified Current Risk Management Asset		8,900		22,700
Debt Instrument Carrying Amount		2,460,000		2,460,000
Debt Instrument Fair Value		2,669,323
Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		1,072		2,185
Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		40,619		44,014
Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities		32,509		33,414
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		746		36,140
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0	[1]	0	[2]
Derivative Liability		120,107		21,856
Additional Fair Value Elements [Abstract]
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities		0		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		(82,509)	[1]	(46,298)	[2]
Derivative Asset		8,854		22,725
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(125,983)	[1]	(72,056)	[2]
Derivative Liability		0		0
Additional Fair Value Elements [Abstract]
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities		34,620		3,033
Cash Held In Margin Accounts Classified Current Risk Management Asset		8,854		22,725
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		25
Hedged portion of gas stored underground		43,901		40,492
Available-for-sale Securities		40,619		44,014
Total assets		84,520		84,531
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		12
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		40,619		44,014
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		25
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement		0		12
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]	92,109		105,138
Hedged portion of gas stored underground	[3]	0		0
Available-for-sale Securities	[3]	33,581		35,599
Total assets	[3]	125,690		140,737
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	246,090		93,900
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]	1,072		2,185
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]	32,509		33,414
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]	746		36,140
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	120,107		21,856
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]	91,363		68,998
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	[3]	125,983		72,044
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, 2015 we had $43.5 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $8.9 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, 2014 we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $22.7 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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Concentration of Credit Risk

12 Months Ended

Sep. 30, 2015

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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Debt (Details) - USD ($)			12 Months Ended
	Oct. 15, 2014	Feb. 18, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Debt Instrument [Line Items]
Debt Instrument Carrying Amount			$ 2,460,000,000	$ 2,460,000,000
Debt Instrument Unamortized Discount			4,612,000	4,014,000
Long-term Debt, Excluding Current Maturities			2,455,388,000	2,455,986,000
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			$ 457,900,000	$ 196,700,000
Commercial Paper Weighted Average Interest Rate			0.42%	0.23%
Debt and Equity Securities Authorized for Issuance			$ 1,750,000,000
Debt And Equity Securities Available For Issuance			845,000,000
Stock Issued During Period, Shares, New Issues		9,200,000
Net proceeds from equity offering		$ 390,200,000	0	$ 390,205,000	$ 0
Long-term Debt, Fiscal Year Maturity [Abstract]
2016			0
2017			250,000,000
2018			0
2019			450,000,000
2020			0
Thereafter			1,760,000,000
Debt Instrument Carrying Amount			$ 2,460,000,000	$ 2,460,000,000
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			49.00%
Regulated Operation [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity			$ 1,300,000,000
Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature			1,500,000,000.0
Unregulated Operation [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			36,100,000
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%			4.95%
Debt Instrument, Maturity Date				Oct. 15, 2014
Debt Instrument Carrying Amount	$ 500,000,000		0	$ 500,000,000
Extinguishment of Debt, Amount	500,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument Carrying Amount	$ 500,000,000		$ 0	$ 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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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%
Debt Instrument, Maturity Date			Oct. 15, 2044
Debt Instrument Carrying Amount	$ 500,000,000		$ 500,000,000	0
Debt Instrument Interest Rate Effective Percentage	4.086%
Net Proceeds From Issuance of Debt	$ 494,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Debt Instrument Carrying Amount	$ 500,000,000		$ 500,000,000	$ 0
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
Long-term Debt, Fiscal Year Maturity [Abstract]
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
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 Maximum Borrowing Capacity			1,250,000,000.00
Line Of Credit Facility Amount Outstanding			0
Line of Credit Facility, Remaining Borrowing Capacity			792,100,000
Line of Credit Facility, Accordion Feature			250,000,000
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			325,000,000
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
Uncommitted Revolving Credit Facility [Member] | Minimum [Member] | Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.00%
Uncommitted Revolving Credit Facility [Member] | Maximum [Member] | Regulated Operation [Member] | Five Year Unsecured Revolving Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.25%
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

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Accumulated Other Comprehensive Income (Table)

12 Months Ended

Sep. 30, 2015

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, 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	)

	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2013	$	5,448		$	37,906		$	(4,476	)	$	38,878
Other comprehensive income (loss) before reclassifications	3,009			(58,973		)	7,904			(48,060		)
Amounts reclassified from accumulated other comprehensive income	(795		)	2,686			(5,102		)	(3,211		)
Net current-period other comprehensive income (loss)	2,214			(56,287		)	2,802			(51,271		)
September 30, 2014	$	7,662		$	(18,381	)	$	(1,674	)	$	(12,393	)

Reclassification out of Accumulated Other Comprehensive Income

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.

	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

	Fiscal Year Ended September 30, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	1,252		Operation and maintenance expense
	1,252			Total before tax
	(457		)	Tax expense
	$	795		Net of tax
Cash flow hedges
Interest rate agreements	$	(4,230	)	Interest charges
Commodity contracts	8,365			Purchased gas cost
	4,135			Total before tax
	(1,719		)	Tax expense
	$	2,416		Net of tax
Total reclassifications	$	3,211		Net of tax

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Valuation and Qualifying Accounts (Details) - Allowance For Doubtful Accounts Member - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period		$ 23,992	$ 20,624	$ 9,425
Charged to costs & expenses		15,082	19,491	14,484
Charged to other accounts		0	0	0
Valuation Allowances and Reserves, Deductions	[1]	23,791	16,123	3,285
Balance at end of period		$ 15,283	$ 23,992	$ 20,624

[1] Uncollectible accounts written off.

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Details of Selected Consolidated Balance Sheet Captions (Table)

12 Months Ended

Sep. 30, 2015

Details Of Selected Consolidated Balance Sheet Captions Disclosure [Abstract]

Accounts Receivables Detail Table

Accounts receivable was comprised of the following at September 30, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Billed accounts receivable	$	204,585		$	262,937
Unbilled revenue	65,008			62,484
Other accounts receivable	40,850			41,971
Total accounts receivable	310,443			367,392
Less: allowance for doubtful accounts	(15,283		)	(23,992		)
Net accounts receivable	$	295,160		$	343,400

Other Current Assets Detail Table

Other current assets as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Assets from risk management activities	$	9,232	$	45,827
Deferred gas costs	9,715		20,069
Taxes receivable	4,479		5,481
Prepaid expenses	27,734		25,039
Materials and supplies	12,587		5,704
Other	6,822		9,145
Total	$	70,569	$	111,265

Property, Plant and Equipment Detail Table

Property, plant and equipment was comprised of the following as of September 30, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Production plant	$	131		$	4,821
Storage plant	286,011			275,579
Transmission plant	1,844,117			1,622,846
Distribution plant	6,019,001			5,522,794
General plant	769,311			735,223
Intangible plant	41,131			38,858
	8,959,702			8,200,121
Construction in progress	280,398			247,579
	9,240,100			8,447,700
Less: accumulated depreciation and amortization	(1,809,520		)	(1,721,794		)
Net property, plant and equipment(1)	$	7,430,580		$	6,725,906

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

Goodwill Detail Table

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2015:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2014	$	574,816	$	132,502	$	34,711	$	742,029
Deferred tax adjustments on prior acquisitions(1)	633		40		—		673
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702

⁽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, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Marketable securities	$	74,200	$	79,613
Regulatory assets	182,573		230,240
Deferred financing costs	17,873		13,698
Assets from risk management activities	368		13,038
Other	13,664		14,340
Total	$	288,678	$	350,929

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Trade accounts payable	$	78,534	$	77,860
Accrued gas payable	119,825		179,425
Accrued liabilities	40,583		50,801
Total	$	238,942	$	308,086

Other Current Liabilities Detail Table

Other current liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer credit balances and deposits	$	100,232	$	82,085
Accrued employee costs	47,602		46,445
Deferred gas costs	28,100		35,063
Accrued interest	34,914		36,768
Liabilities from risk management activities	9,568		1,730
Taxes payable	93,674		77,601
Pension and postretirement obligations	21,857		11,380
Current deferred tax liability	55,918		48,751
Regulatory cost of removal accrual	56,123		45,061
Other	9,966		20,985
Total	$	457,954	$	405,869

Deferred Credits and Other Liabilities Detail Table

Deferred credits and other liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer advances for construction	$	9,316	$	9,883
Regulatory liabilities	3,693		4,472
Asset retirement obligation	9,063		10,508
Liabilities from risk management activities	110,539		20,126
Other	29,085		23,881
Total	$	161,696	$	68,870

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Retirement and Post-Retirement Employee Benefit Plans Fair Value Disclosures (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		$ 74,200	$ 79,613
Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		40,619	44,014
Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	[1]	33,581	35,599
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]
Investments, Fair Value Disclosure		448,544	432,109
Fair value of accounts receivable		2,400	2,700
Pension Plans, Defined Benefit [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		159,304	155,107
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		11,787	11,226
Pension Plans, Defined Benefit [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		33,312	33,266
Pension Plans, Defined Benefit [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		48,648	48,134
Pension Plans, Defined Benefit [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		93,081	91,792
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		14,359	12,520
Pension Plans, Defined Benefit [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		6,084	3,679
Pension Plans, Defined Benefit [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		28,973	25,734
Pension Plans, Defined Benefit [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		52,996	50,496
Pension Plans, Defined Benefit [Member] | Real Estate Investment [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure			155
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		246,543	239,624
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		159,304	155,107
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		33,312	33,266
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		48,648	48,134
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		5,279	3,117
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Real Estate Investment [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure			0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		202,001	192,330
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		11,787	11,226
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		93,081	91,792
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		14,359	12,520
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		805	562
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		28,973	25,734
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		52,996	50,496
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Real Estate Investment [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure			0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	155
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		0	0
Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Real Estate Investment [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure			155
Supplemental Employee Retirement Plan [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities		41,700	46,200
Other Postretirement Benefit Plans, Defined Benefit [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		138,009	134,821
Other Postretirement Benefit Plans, Defined Benefit [Member] | Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		3,486	434
Other Postretirement Benefit Plans, Defined Benefit [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		123,921	124,006
Other Postretirement Benefit Plans, Defined Benefit [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		10,602	10,381
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		134,523	134,387
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]
Investments, Fair Value Disclosure		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		123,921	124,006
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		10,602	10,381
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		3,486	434
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]
Investments, Fair Value Disclosure		3,486	434
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 2 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		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]
Investments, Fair Value Disclosure		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure		$ 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.

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Financial Instruments Fair Value Hedges and Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Effect of Fair Value Hedges on Results of Operations [Abstract]
Commodity contracts	$ 10,311	$ (792)	$ 2,165
Fair value adjustment for natural gas inventory designated as the hedged item	(9,768)	2,486	15,938
Total (increase) decrease in purchased gas cost	543	1,694	18,103
Fair Value Hedge Basis Ineffectiveness	811	(919)	(208)
Fair Value Hedge Timing Ineffectiveness	(268)	2,613	18,311
Cash Flow Hedge [Line Items]
Gain (loss) reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	(41,716)	8,365	(10,778)
Gain (loss) arising from ineffective portion of commodity contracts	(325)	198	97
Total impact on purchased gas cost	(42,041)	8,563	(10,681)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	(853)	(4,230)	(3,489)
Total Impact from Cash Flow Hedges	(42,894)	4,333	(14,170)
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	(853)	(4,230)	(3,489)
Total Impact from Cash Flow Hedges	(853)	(4,230)	(3,489)
Nonregulated Segment [Member]
Cash Flow Hedge [Line Items]
Gain (loss) reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	(41,716)	8,365	(10,778)
Gain (loss) arising from ineffective portion of commodity contracts	(325)	198	97
Total impact on purchased gas cost	(42,041)	8,563	(10,681)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense	0	0	0
Total Impact from Cash Flow Hedges	$ (42,041)	$ 8,563	$ (10,681)

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Income Taxes Tax Credit Carryforwards (Details) $ in Millions	12 Months Ended
	Sep. 30, 2015 USD ($)
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 0.8
State and Local Jurisdiction [Member] | Minimum [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2018
Domestic Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Amount	$ 10.1

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Regulatory Assets [Line Items]
Regulatory Assets		$ 192,339	$ 250,309
Regulatory Liabilities [Line Items]
Regulatory Liabilities		524,532	545,759
Regulatory Assets and Liabilities, Other Disclosures [Abstract]
Regulatory Asset - Future Recoverable Pension Costs		16,600	18,800
Property, Plant and Equipment [Line Items]
Interest Costs Capitalized		$ 2,300	$ 1,500	$ 1,900
Composite depreciation rate for regulated property, plant and equipment		3.30%	3.30%	3.30%
Other Information [Abstract]
Unrealized gain (loss) on open contracts		$ (2,400)	$ 9,600	$ 9,000
Asset Retirement Obligation		11,100	10,500
Asset Retirement Costs in Property, Plant and Equipment		4,800	5,900
Cash Held in Margin Accounts		43,500	25,800
Regulatory Cost Of Removal Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		483,676	490,448
Deferred Gas Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		28,100	35,063
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		9,063	10,508
Deferred Franchise Fees Liability [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		0	5,268
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities		3,693	4,472
Pension And Postretirement Benefit Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[1]	121,183	162,777
Infrastructure Mechanisms [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[2]	32,813	26,948
Deferred Gas Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		9,715	20,069
Recoverable Loss On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets		16,319	18,877
APT Annual Adjustment Mechanism Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets		1,002	8,479
Rate Case Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		1,533	3,757
Other [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 9,774	$ 9,402
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

[1] Includes $16.6 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.

[2] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY5MzVhMDg4NmFiZTQ4OWI4NGMwODRiNTY1ZWEzNjI5fFRleHRTZWxlY3Rpb246MkQxNzI1ODI3MDY5QTQ1MEUwNkM2NTMyQzUzODRCRTYM}

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CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (PARENTHETICALS) - $ / shares	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Statement of Stockholders' Equity [Abstract]
Cash dividends per share	$ 1.56	$ 1.48	$ 1.40

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Income Taxes Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Tax at statutory rate of 35%	$ 178,768	$ 166,887	$ 130,655
Common stock dividends deductible for tax reporting	(2,413)	(2,307)	(2,153)
State taxes (net of federal benefit)	12,869	11,636	11,559
Change in valuation allowance	4,998	6,969	1,085
Other, net	1,468	3,817	1,453
Income tax expense (benefit)	$ 195,690	$ 187,002	$ 142,599

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Fair Value Measurements (Table)

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014. 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, 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

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(3)			September 30, 2014
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	36,140	$	—	$	—		$	36,140
Nonregulated segment	25		68,998		—		(46,298		)	22,725
Total financial instruments	25		105,138		—		(46,298		)	58,865
Hedged portion of gas stored underground	40,492		—		—		—			40,492
Available-for-sale securities
Money market funds	—		2,185		—		—			2,185
Registered investment companies	44,014		—		—		—			44,014
Bonds	—		33,414		—		—			33,414
Total available-for-sale securities	44,014		35,599		—		—			79,613
Total assets	$	84,531	$	140,737	$	—	$	(46,298	)	$	178,970
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	21,856	$	—	$	—		$	21,856
Nonregulated segment	12		72,044		—		(72,056		)	—
Total liabilities	$	12	$	93,900	$	—	$	(72,056	)	$	21,856

⁽¹⁾  Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

⁽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 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⁾  This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2014 we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $22.7 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, 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
As of September 30, 2014
Domestic equity mutual funds	$	26,633	$	10,136	$	—		$	36,769
Foreign equity mutual funds	5,382		1,863		—			7,245
Bonds	33,266		161		(13		)	33,414
Money market funds	2,185		—		—			2,185
	$	67,466	$	12,160	$	(13	)	$	79,613

Other fair value measurements table

The following table presents the carrying value and fair value of our debt as of September 30, 2015:

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

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Summary of Significant Accounting Policies (Policy)

12 Months Ended

Sep. 30, 2015

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

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 $2.3 million, $1.5 million and $1.9 million was capitalized in 2015, 2014 and 2013.

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 3.3 percent, for each of the fiscal years ended September 30, 2015, 2014 and 2013.

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, 2015 and 2014, we had asset retirement obligations of $11.1 million and $10.5 million. Additionally, we had $4.8 million and $5.9 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, 2015 and 2014, 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 12.

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, 2015, 2014 and 2013, we included unrealized gains (losses) on open contracts of $(2.4) million, $9.6 million and $9.0 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, 2015 and 2014, the Company netted $43.5 million and $25.8 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.

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 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 utilize models and other valuation methods to determine fair value when external sources are not available. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.

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 current and 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 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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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Sep. 30, 2015

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2015

			Additions
	Balance at beginning of period		Charged to cost & expenses		Charged to other accounts		Deductions			Balance at end of period
			(In thousands)
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
2013
Allowance for doubtful accounts	$	9,425	$	14,484	$	—	$	3,285	(1)	$	20,624

⁽¹⁾  Uncollectible accounts written off.

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Stock and Other Compensation Plans (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Stock Based Compensation Expense	$ 27,500,000	$ 25,500,000	$ 17,800,000
Authorized Shares	8,700,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available	308,582
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Nonvested at beginning of year-Shares	988,637	1,052,844	1,262,582
Nonvested at beginning of year-Weighted Average	$ 42.22	$ 36.20	$ 32.46
Granted-Shares	444,543	464,438	473,775
Granted-Weighted Average	$ 50.50	$ 45.05	$ 40.48
Vested-Shares	(551,688)	(524,532)	(657,795)
Vested-Weighted Average	$ 39.28	$ 32.67	$ 32.20
Forfeited-Shares	(3,388)	(4,113)	(25,718)
Forfeited-Weighted Average	$ 48.55	$ 39.00	$ 33.42
Nonvested at end of year-Shares	878,104	988,637	1,052,844
Nonvested at end of year-Weighted Average	$ 48.24	$ 42.22	$ 36.20
Unrecognized Compensation Cost	$ 10,200,000
Weighted Average Recognized Period	1 year 6 months
Fair Value Restricted Stock Vested	$ 21,700,000	$ 17,100,000	$ 21,200,000
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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Discontinued Operations (Table)

12 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued operations income statement detail table

The following table presents statement of income data related to discontinued operations in our Georgia service area for the year ended September 30, 2013.

	Year Ended September 30, 2013
	(In thousands)
Operating revenues	$	37,962
Purchased gas cost	21,464
Gross profit	16,498
Operating expenses	5,858
Operating income	10,640
Other nonoperating income	548
Income from discontinued operations before income taxes	11,188
Income tax expense	3,986
Income from discontinued operations	7,202
Gain on sale of discontinued operations, net of tax	5,294
Net income from discontinued operations	$	12,496

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Nature of Business (Table)

12 Months Ended

Sep. 30, 2015

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, 2015

Accounting Policies [Abstract]

Schedule Of Regulatory Assets And Liabilities

Significant regulatory assets and liabilities as of September 30, 2015 and 2014 included the following:

	September 30
	2015		2014
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	121,183	$	162,777
Infrastructure Mechanisms(2)	32,813		26,948
Deferred gas costs	9,715		20,069
Recoverable loss on reacquired debt	16,319		18,877
APT annual adjustment mechanism	1,002		8,479
Rate case costs	1,533		3,757
Other	9,774		9,402
	$	192,339	$	250,309
Regulatory liabilities:
Regulatory cost of removal obligation	$	483,676	$	490,448
Deferred gas costs	28,100		35,063
Asset retirement obligation	9,063		10,508
Deferred franchise fees	—		5,268
Other	3,693		4,472
	$	524,532	$	545,759

^[1],[2]

[1] Includes $16.6 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.

[2] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY5MzVhMDg4NmFiZTQ4OWI4NGMwODRiNTY1ZWEzNjI5fFRleHRTZWxlY3Rpb246MkQxNzI1ODI3MDY5QTQ1MEUwNkM2NTMyQzUzODRCRTYM}

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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, 2012		90,239,900
Shareholders' equity, beginning balance at Sep. 30, 2012	$ 2,359,243	$ 451	$ 1,745,467	$ (47,607)	$ 660,932
Net income	243,194				243,194
Other comprehensive income (loss)	86,485			86,485
Repurchase of equity awards, shares		(133,449)
Repurchase of equity awards, amount	(5,150)	$ 0	(5,150)
Cash dividends	(128,115)				(128,115)
Common stock issued:
Direct stock purchase plan, shares		0
Direct stock purchase plan, amount	(50)	$ 0	(50)
1998 Long-term incentive plan, shares		531,672
1998 Long-term incentive plan, amount	8,788	$ 2	9,530		(744)
Employee stock-based compensation	15,934		15,934
Outside directors stock-for-fee plan, shares		2,088
Outside directors stock-for-fee-plan, amount	80		80
Common stock shares outstanding, ending balance at Sep. 30, 2013		90,640,211
Shareholders' equity, ending 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
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
Retirement savings plan, shares		398,047
Retirement savings plan, amount	20,326	$ 2	20,324
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

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Segment Information (Table)

12 Months Ended

Sep. 30, 2015

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, 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	$	680,961		$	292,728		$	1,443		$	—		$	975,132

	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	$	584,065		$	249,347		$	1,839	$	—		$	835,251

	Year Ended September 30, 2013
	Regulated Distribution		Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,394,418	$	89,011		$	1,392,031		$	—		$	3,875,460
Intersegment revenues	5,075		179,889			195,883			(380,847		)	—
	2,399,493		268,900			1,587,914			(380,847		)	3,875,460
Purchased gas cost	1,318,257		—			1,524,583			(379,430		)	2,463,410
Gross profit	1,081,236		268,900			63,331			(1,417		)	1,412,050
Operating expenses
Operation and maintenance	375,188		76,686			37,569			(1,423		)	488,020
Depreciation and amortization	195,581		35,302			4,196			—			235,079
Taxes, other than income	167,374		17,059			2,639			—			187,072
Total operating expenses	738,143		129,047			44,404			(1,423		)	910,171
Operating income	343,093		139,853			18,927			6			501,879
Miscellaneous income (expense)	2,535		(2,285		)	2,316			(2,763		)	(197		)
Interest charges	98,296		30,678			2,168			(2,757		)	128,385
Income from continuing operations before income taxes	247,332		106,890			19,075			—			373,297
Income tax expense	96,476		38,630			7,493			—			142,599
Income from continuing operations	150,856		68,260			11,582			—			230,698
Income from discontinued operations, net of tax	7,202		—			—			—			7,202
Gain (loss) on sale of discontinued operations, net of tax	5,649		—			(355		)	—			5,294
Net income	$	163,707	$	68,260		$	11,227		$	—		$	243,194
Capital expenditures	$	528,599	$	313,230		$	3,204		$	—		$	845,033

Revenue from External Customers by Products and Services

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

	2015		2014		2013
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,761,689	$	1,933,099	$	1,512,495
Commercial	772,187		876,042		661,930
Industrial	74,981		90,536		81,155
Public authority and other	53,401		64,779		60,557
Total gas sales revenues	2,662,258		2,964,456		2,316,137
Transportation revenues	67,475		64,049		55,938
Other gas revenues	27,852		27,707		22,343
Total regulated distribution revenues	2,757,585		3,056,212		2,394,418
Regulated pipeline revenues	97,662		92,166		89,011
Nonregulated revenues	1,286,889		1,792,538		1,392,031
Total operating revenues	$	4,142,136	$	4,940,916	$	3,875,460

Schedule of segment reporting balance sheet information, by segment

Balance sheet information at September 30, 2015 and 2014 by segment is presented in the following tables.

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

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

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Income Taxes (Table)

12 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of income tax expense from continuing operations for 2015, 2014 and 2013 were as follows:

	2015			2014			2013
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	7,251			5,527			8,178
Deferred
Federal	175,897			169,106			124,836
State	12,548			12,375			9,605
Investment tax credits	(6		)	(6		)	(20		)
	$	195,690		$	187,002		$	142,599

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 2015, 2014 and 2013 are set forth below:

	2015			2014			2013
	(In thousands)
Tax at statutory rate of 35%	$	178,768		$	166,887		$	130,655
Common stock dividends deductible for tax reporting	(2,413		)	(2,307		)	(2,153		)
State taxes (net of federal benefit)	12,869			11,636			11,559
Change in valuation allowance	4,998			6,969			1,085
Other, net	1,468			3,817			1,453
Income tax expense	$	195,690		$	187,002		$	142,599

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, 2015 and 2014 are presented below:

	2015			2014
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	121,619		$	116,157
Interest rate agreements	51,067			10,565
Net operating loss carryforwards	313,224			236,626
Charitable and other credit carryforwards	22,281			21,614
Other	36,695			28,849
Total deferred tax assets	544,886			413,811
Valuation allowance	(10,872		)	(6,969		)
Net deferred tax assets	534,014			406,842
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(1,890,886		)	(1,655,894		)
Pension funding	(35,247		)	(17,890		)
Gas cost adjustments	(43,634		)	(31,252		)
Other	(31,480		)	(37,173		)
Total deferred tax liabilities	(2,001,247		)	(1,742,209		)
Net deferred tax liabilities	$	(1,467,233	)	$	(1,335,367	)
Deferred credits for rate regulated entities	$	412		$	(109	)

Schedule of Unrecognized Tax Benefits Roll Forward

The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2015			2014
	(In thousands)
Unrecognized tax benefits - beginning balance	$	12,629		$	4,158
Increase resulting from prior period tax positions	1,009			3,846
Increase resulting from current period tax positions	3,431			4,625
Unrecognized tax benefits - ending balance	17,069			12,629
Accrued interest and penalties	820			411
Gross unrecognized tax benefits	17,889			13,040
Less: deferred federal and state income tax benefits	(6,261		)	(4,564		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	11,628		$	8,476

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Retirement and Post-Retirement Employee Benefit Plans Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 434,767	$ 396,887
Actual return on plan assets	8,661	35,289
Employer contributions	38,000	27,110
Benefits paid	(30,496)	(24,519)
Fair value of plan assets at end of year	450,932	434,767
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	0	0
Employer contributions	4,551	21,902
Benefits paid	(4,551)	(5,085)
Settlements	0	(16,817)
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	134,821	106,413
Actual return on plan assets	(8,851)	14,003
Employer contributions	19,984	23,550
Plan participants' contributions	4,563	4,435
Benefits paid	(12,508)	(13,580)
Fair value of plan assets at end of year	$ 138,009	$ 134,821

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Fair Value Measurements Available-For-Sale Securities (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 66,399	$ 67,466
Gross Unrealized Gain	8,343	12,160
Gross Unrealized Loss	(542)	(13)
Fair value	74,200	79,613
Available-for-sale Securities, Other Disclosure Items [Abstract]
Available-for-sale Securities, Supplemental Executive Benefit Plans	41,700	46,200
Equity Funds Domestic [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	27,643	26,633
Gross Unrealized Gain	7,332	10,136
Gross Unrealized Loss	(456)	0
Fair value	34,519	36,769
Equity Funds Foreign [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	5,261	5,382
Gross Unrealized Gain	905	1,863
Gross Unrealized Loss	(66)	0
Fair value	6,100	7,245
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	32,423	33,266
Gross Unrealized Gain	106	161
Gross Unrealized Loss	(20)	(13)
Fair value	32,509	33,414
Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,072	2,185
Gross Unrealized Gain	0	0
Gross Unrealized Loss	0	0
Fair value	$ 1,072	$ 2,185

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
ASSETS
Property, plant and equipment		$ 8,959,702	$ 8,200,121
Construction in progress		280,398	247,579
Total property, plant and equipment and construction in progress		9,240,100	8,447,700
Less accumulated depreciation and amortization		1,809,520	1,721,794
Net property, plant and equipment	[1]	7,430,580	6,725,906
Current assets
Cash and cash equivalents		28,653	42,258
Accounts receivable, less allowance for doubtful accounts of $15,283 in 2015 and $23,992 in 2014		295,160	343,400
Gas stored underground		236,603	278,917
Other current assets		70,569	111,265
Total current assets		630,985	775,840
Goodwill		742,702	742,029
Deferred charges and other assets		288,678	350,929
Total assets		9,092,945	8,594,704
Shareholders' equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2015 — 101,478,818 shares, 2014 — 100,388,092 shares		507	502
Additional paid-in capital		2,230,591	2,180,151
Accumulated other comprehensive loss		(109,330)	(12,393)
Retained earnings		1,073,029	917,972
Shareholders' equity		3,194,797	3,086,232
Long-term debt		2,455,388	2,455,986
Total capitalization		5,650,185	5,542,218
Current liabilities
Accounts payable and accrued liabilities		238,942	308,086
Other current liabilities		457,954	405,869
Short-term debt		457,927	196,695
Total current liabilities		1,154,823	910,650
Deferred income taxes		1,411,315	1,286,616
Regulatory cost of removal obligation		427,553	445,387
Pension and postretirement liabilities		287,373	340,963
Deferred credits and other liabilities		161,696	68,870
Total shareholders' equity and liabilities		$ 9,092,945	$ 8,594,704

[1] Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

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Selected Quarterly Financial Data (Table)

12 Months Ended

Sep. 30, 2015

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 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

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2014:
Operating revenues
Regulated distribution	$	843,865		$	1,290,960		$	517,707		$	409,014
Regulated pipeline	71,341			73,615			87,189			86,314
Nonregulated	436,431			758,215			465,485			407,161
Intersegment eliminations	(107,779		)	(157,936		)	(127,211		)	(113,455		)
	1,243,858			1,964,854			943,170			789,034
Gross profit	388,957			496,277			359,533			337,659
Operating income	170,720			250,080			106,605			83,944
Net income	87,016			133,367			45,721			23,713
Net income per share — basic	$	0.95		$	1.38		$	0.45		$	0.23
Net income per share — diluted	$	0.95		$	1.38		$	0.45		$	0.23

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Net income		$ 315,075	$ 289,817	$ 243,194
Other comprehensive income (loss), net of tax [Abstract]
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(1,559), $1,199 and $(186)		(2,713)	2,214	(213)
Schedule of Other Comprehensive Income (Loss), Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	[1]	(94,224)	(53,485)
Total other comprehensive income (loss)		(96,937)	(51,271)	86,485
Total comprehensive income		218,138	238,546	329,679
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		(70,461)	(56,287)	82,179
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		$ (23,763)	$ 2,802	$ 4,519

[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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Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2015 USD ($) $ / Mcf MMcf	Sep. 30, 2014 USD ($)	Sep. 30, 2013 USD ($)
Estimated Contractual Demand Fees [Abstract]
2016	$ 7,843
2017	3,522
2018	1,966
2019	426
2020	398
Thereafter	1,101
Total Estimated Contractual Demand Fees	15,256
Mid-Tex Division [Member]
Long Term Purchase Commitment [Line Items]
Significant Purchase Commitment, Amount	113,300	$ 140,900	$ 89,000
Nonregulated Segment [Member]
Long Term Purchase Commitment [Line Items]
Significant Purchase Commitment, Amount	$ 1,141,300	$ 1,687,500	$ 1,246,100
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	36,600
Long Term Purchase Commitment Minimum Quantity Required One To Three Years | MMcf	26,800
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	101,900
Long Term Purchase Commitment Minimum Quantity Required One To Three Years | MMcf	16,000
Long Term Purchase Commitment Minimum Quantity Required After Three Years | MMcf	500
Inventories Under Fixed Price Contracts [Member] | Nonregulated Segment [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year | MMcf	3,000
Purchase Commitment Amount Minimum | $ / Mcf	2.32
Purchase Commitment Amount Maximum | $ / Mcf	3.23

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Retirement and Post-Retirement Employee Benefit Plans (Table)

12 Months Ended

Sep. 30, 2015

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 Plans			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537
September 30, 2014
Unrecognized transition obligation	$	—		$	—	$	354		$	354
Unrecognized prior service credit	(1,927		)	—		(6,168		)	(8,095		)
Unrecognized actuarial loss	109,767			34,447		7,531			151,745
	$	107,840		$	34,447	$	1,717		$	144,004

Schedule of Allocation of Plan Assets

The following table presents asset allocation information for the Master Trust as of September 30, 2015 and 2014.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2015		2014
Domestic equities	35%-55%	41.3	%	44.9	%
International equities	10%-20%	14.9	%	15.3	%
Fixed income	5%-30%	11.0	%	9.7	%
Company stock	0%-15%	15.2	%	12.9	%
Other assets	0%-20%	17.6	%	17.2	%

The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2015 and 2014.

	Actual Allocation September 30
Security Class	2015		2014
Diversified investment funds	97.5	%	99.7	%
Cash and cash equivalents	2.5	%	0.3	%

Schedule of Employee Pension Plans Investments at Fair Value

In addition to the assets shown below, the Master Trust had net accounts receivable of $2.4 million and $2.7 million at September 30, 2015 and 2014 which materially approximates fair value due to the short-term nature of these assets.

	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:
Domestic funds	33,312		—		—		33,312
International funds	48,648		—		—		48,648
Common/collective trusts — domestic funds	—		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

	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	155,107	$	—	$	—	$	155,107
Money market funds	—		11,226		—		11,226
Registered investment companies:
Domestic funds	33,266		—		—		33,266
International funds	48,134		—		—		48,134
Common/collective trusts — domestic funds	—		91,792		—		91,792
Government securities:
Mortgage-backed securities	—		12,520		—		12,520
U.S. treasuries	3,117		562		—		3,679
Corporate bonds	—		25,734		—		25,734
Limited partnerships	—		50,496		—		50,496
Real estate	—		—		155		155
Total investments at fair value	$	239,624	$	192,330	$	155	$	432,109

Schedule of Expected 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 2015 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2016	$	15,498	$	2,382	$	—	$	17,880
2017	11,245		2,677		—		13,922
2018	12,185		2,980		—		15,165
2019	12,755		3,324		—		16,079
2020	13,995		3,766		—		17,761
2021-2025	86,519		26,363		—		112,882

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 Plans		Supplemental Plans
	(In thousands)
2016	$	30,909	$	21,857
2017	31,805		13,901
2018	33,086		12,807
2019	34,712		6,808
2020	36,128		4,454
2021-2025	201,857		47,047

Schedule of Postretirement Benefit Plans Investments at Fair Value

	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:
Domestic funds	123,921		—		—		123,921
International funds	10,602		—		—		10,602
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	434	$	—	$	434
Registered investment companies:
Domestic funds	124,006		—		—		124,006
International funds	10,381		—		—		10,381
Total investments at fair value	$	134,387	$	434	$	—	$	134,821

Schedule of Assumptions Used [Table Text Block]

Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.25	%	7.25	%	7.25	%	7.75	%

The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2014, 2013 and 2012. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%	(1)
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

⁽¹⁾ The discount rate for the supplemental plans increased from 4.04% to 4.21% effective April 1, 2013 due to a settlement loss recorded in fiscal 2013.

The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2014, 2013 and 2012. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Expected return on plan assets	4.45	%	4.60	%	4.60	%	4.60	%	4.70	%
Initial trend rate	7.50	%	7.50	%	7.50	%	8.00	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2021		2020		2020		2020		2019

Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]

The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	485,921		$	466,182
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	493,594		$	455,799
Service cost	16,231			15,345
Interest cost	21,850			22,330
Actuarial (gain) loss	7,420			26,611
Benefits paid	(30,496		)	(24,519		)
Plan amendments	—			(1,972		)
Benefit obligation at end of year	508,599			493,594
Change in plan assets:
Fair value of plan assets at beginning of year	434,767			396,887
Actual return on plan assets	8,661			35,289
Employer contributions	38,000			27,110
Benefits paid	(30,496		)	(24,519		)
Fair value of plan assets at end of year	450,932			434,767
Reconciliation:
Funded status	(57,667		)	(58,827		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Net amount recognized	$	(57,667	)	$	(58,827	)

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	118,835		$	106,276
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	113,219		$	117,080
Service cost	3,971			3,607
Interest cost	4,943			4,966
Actuarial (gain) loss	4,811			9,468
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Benefit obligation at end of year	122,393			113,219
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,551			21,902
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(122,393		)	(113,219		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(122,393	)	$	(113,219	)

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	315,118		$	312,148
Service cost	15,583			16,784
Interest cost	14,385			15,951
Plan participants’ contributions	4,563			4,435
Actuarial (gain) loss	(69,962		)	(18,963		)
Benefits paid	(12,508		)	(13,580		)
Plan amendments	—			(1,657		)
Benefit obligation at end of year	267,179			315,118
Change in plan assets:
Fair value of plan assets at beginning of year	134,821			106,413
Actual return on plan assets	(8,851		)	14,003
Employer contributions	19,984			23,550
Plan participants’ contributions	4,563			4,435
Benefits paid	(12,508		)	(13,580		)
Fair value of plan assets at end of year	138,009			134,821
Reconciliation:
Funded status	(129,170		)	(180,297		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(129,170	)	$	(180,297	)

Schedule of Net Benefit Costs [Table Text Block]

Net periodic postretirement cost for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	15,583		$	16,784		$	18,800
Interest cost	14,385			15,951			12,964
Expected return on assets	(6,431		)	(5,167		)	(3,988		)
Amortization of transition obligation	272			274			1,081
Amortization of prior service credit	(1,644		)	(1,450		)	(1,450		)
Recognized actuarial loss	—			631			4,196
Net periodic postretirement cost	$	22,165		$	27,023		$	31,603

Net periodic pension cost for the Plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,231		$	15,345		$	17,754
Interest cost	21,850			22,330			19,334
Expected return on assets	(25,744		)	(23,601		)	(22,955		)
Amortization of prior service credit	(192		)	(136		)	(141		)
Recognized actuarial loss	13,322			13,777			19,066
Net periodic pension cost	$	25,467		$	27,715		$	33,058

Net periodic pension cost for the supplemental plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015		2014		2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	3,971	$	3,607	$	3,039
Interest cost	4,943		4,966		4,755
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,343		1,948		2,918
Settlements	—		4,539		3,160
Net periodic pension cost	$	11,257	$	15,060	$	13,872

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	$	4,288	$	(3,426	)
Effect on postretirement benefit obligation	$	39,572	$	(32,440	)

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Financial Instruments Descriptions (Details) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2014 USD ($)	Sep. 30, 2015 USD ($) $ / Mcf MMcf	Sep. 30, 2014 USD ($)	Sep. 30, 2013 USD ($)
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		37.00%
Hedge Volume Of Actual Heating Season Gas | MMcf		28,200
Weighted Average Cost Of Actual Heating Season Gas | $ / Mcf		4.34
Minimum Length Of Time Hedged In Cash Flow Hedge		1 month
Maximum Length of Time Hedged in Cash Flow Hedge		49 months
Net Open Positions | MMcf		1,000
Gain (Loss) On Hedge Ineffectiveness		$ 0.2	$ 1.9	$ 18.2
Regulated Segments Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate		37.00%
Nonregulated Segment Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate		39.00%
Gain (Loss) On Derivative Instruments Not Designated Hedges Net Pretax		$ 15.5	$ (5.0)	$ 3.0
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		250.0
Interest Rate Hedges, Senior Notes 2019 Issuance [Member]
Derivative [Line Items]
Derivative, Notional Amount		450.0
Anticipated Debt Issuance, Amount		$ 450.0

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Financial Instruments

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014:

	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2015
Assets from risk management activities, current(1)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(1)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(1)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)
September 30, 2014
Assets from risk management activities, current(2)	$	23,102		$	22,725	$	45,827
Assets from risk management activities, noncurrent	13,038			—		13,038
Liabilities from risk management activities, current(2)	(1,730		)	—		(1,730		)
Liabilities from risk management activities, noncurrent(2)	(20,126		)	—		(20,126		)
Net assets	$	14,284		$	22,725	$	37,009

⁽¹⁾  Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

⁽²⁾  Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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 2014-2015 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 37 percent, or approximately 28.2 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $4.34 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 49 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, 2015, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 1.0 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 the anticipated issuance of $250 million 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 Treasury lock 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 Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for the settled Treasury locks extend through fiscal 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, 2015, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of September 30, 2015, we had net long/(short) commodity contracts outstanding in the following quantities:

Contract Type	Hedge Designation	Regulated Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(18,378	)
	Cash Flow	—	56,368
	Not designated	24,849	58,513
		24,849	96,503

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, 2015 and 2014. 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, 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		$	—

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

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of 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, 2015, 2014 and 2013, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $0.2 million, $1.9 million and $18.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges

The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our consolidated income statement for the years ended September 30, 2015, 2014 and 2013 is presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Commodity contracts	$	10,311		$	(792	)	$	2,165
Fair value adjustment for natural gas inventory designated as the hedged item	(9,768		)	2,486			15,938
Total decrease in purchased gas cost	$	543		$	1,694		$	18,103
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	811		$	(919	)	$	(208	)
Timing ineffectiveness	(268		)	2,613			18,311
	$	543		$	1,694		$	18,103

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, 2015, 2014 and 2013 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	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

	Fiscal Year Ended September 30, 2013
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(10,778	)	$	(10,778	)
Gain arising from ineffective portion of commodity contracts	—			97			97
Total impact on purchased gas cost	—			(10,681		)	(10,681		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(3,489		)	—			(3,489		)
Total impact from cash flow hedges	$	(3,489	)	$	(10,681	)	$	(14,170	)

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, 2015 and 2014. 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
	2015			2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(71,003	)	$	(58,973	)
Forward commodity contracts	(49,211		)	7,904
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	542			2,686
Forward commodity contracts	25,448			(5,102		)
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(94,224	)	$	(53,485	)

⁽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, 2015. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 and fiscal 2014 as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2016	$	(347	)	$	(19,484	)	$	(19,831	)
2017	(447		)	(5,044		)	(5,491		)
2018	(649		)	(819		)	(1,468		)
2019	(673		)	(85		)	(758		)
2020	(698		)	(5		)	(703		)
Thereafter	(15,836		)	—			(15,836		)
Total(1)	$	(18,650	)	$	(25,437	)	$	(44,087	)

⁽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, 2015, 2014 and 2013 was an increase (decrease) in purchased gas cost of $15.5 million, $(5.0) million and $3.0 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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Stock and Other Compensation Plans (Table)

12 Months Ended

Sep. 30, 2015

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, 2015, 2014 and 2013:

	2015				2014				2013
	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	988,637		$	42.22	1,052,844		$	36.20	1,262,582		$	32.46
Granted	444,543		50.50		464,438		45.05		473,775		40.48
Vested	(551,688	)	39.28		(524,532	)	32.67		(657,795	)	32.20
Forfeited	(3,388	)	48.55		(4,113	)	39.00		(25,718	)	33.42
Nonvested at end of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20

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Fair Value Measurements

12 Months Ended

Sep. 30, 2015

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 6.

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, 2015 and 2014. 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, 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

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)(1)		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral(3)			September 30, 2014
	(In thousands)
Assets:
Financial instruments
Regulated distribution segment	$	—	$	36,140	$	—	$	—		$	36,140
Nonregulated segment	25		68,998		—		(46,298		)	22,725
Total financial instruments	25		105,138		—		(46,298		)	58,865
Hedged portion of gas stored underground	40,492		—		—		—			40,492
Available-for-sale securities
Money market funds	—		2,185		—		—			2,185
Registered investment companies	44,014		—		—		—			44,014
Bonds	—		33,414		—		—			33,414
Total available-for-sale securities	44,014		35,599		—		—			79,613
Total assets	$	84,531	$	140,737	$	—	$	(46,298	)	$	178,970
Liabilities:
Financial instruments
Regulated distribution segment	$	—	$	21,856	$	—	$	—		$	21,856
Nonregulated segment	12		72,044		—		(72,056		)	—
Total liabilities	$	12	$	93,900	$	—	$	(72,056	)	$	21,856

⁽¹⁾  Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

⁽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 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⁾  This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2014 we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting agreements and the remaining $22.7 million is classified as current risk management assets.

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

	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of 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
As of September 30, 2014
Domestic equity mutual funds	$	26,633	$	10,136	$	—		$	36,769
Foreign equity mutual funds	5,382		1,863		—			7,245
Bonds	33,266		161		(13		)	33,414
Money market funds	2,185		—		—			2,185
	$	67,466	$	12,160	$	(13	)	$	79,613

At September 30, 2015 and 2014, our available-for-sale securities included $41.7 million and $46.2 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 6. At September 30, 2015 we maintained investments in bonds that have contractual maturity dates ranging from October 2015 through September 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, 2015:

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

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Financial Instruments Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Other Comprehensive Income [Abstract]
Interest rate agreements fair value		$ (71,003)	$ (58,973)
Forward commodity contracts fair value		(49,211)	7,904
Interest rate agreements		542	2,686
Forward commodity contracts		25,448	(5,102)
Total other comprehensive income (loss) from hedging, net of tax	[1]	(94,224)	(53,485)
Expected Earnings [Line Items]
2016		(19,831)
2017		(5,491)
2018		(1,468)
2019		(758)
2020		(703)
Thereafter		(15,836)
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	(44,087)
Interest Rate Contract [Member]
Other Comprehensive Income [Abstract]
Total other comprehensive income (loss) from hedging, net of tax		(70,461)	(56,287)	$ 82,179
Expected Earnings [Line Items]
2016		(347)
2017		(447)
2018		(649)
2019		(673)
2020		(698)
Thereafter		(15,836)
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	(18,650)
Commodity Contract [Member]
Other Comprehensive Income [Abstract]
Total other comprehensive income (loss) from hedging, net of tax		(23,763)	$ 2,802	$ 4,519
Expected Earnings [Line Items]
2016		(19,484)
2017		(5,044)
2018		(819)
2019		(85)
2020		(5)
Thereafter		0
Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total	[2]	$ (25,437)

[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.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (PARENTHETICAL) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent, Parenthetical Disclosures [Abstract]
Unrealized holding gains (losses) on available-for-sale securities, tax	$ (1,559)	$ 1,199	$ (186)
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	(40,501)	(32,353)	47,236
Commodity Contract [Member]
Schedule of Other Comprehensive Income (Loss), Tax, Cash Flow Hedges [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	$ (15,193)	$ 1,791	$ 2,889

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CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 15,283	$ 23,992
Common Stock, Stated Value Per Share	$ 0.005	$ 0.005
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	101,478,818	100,388,092

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Stock and Other Compensation Plans

12 Months Ended

Sep. 30, 2015

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 expense was $27.5 million, $25.5 million and $17.8 million for the fiscal years ended September 30, 2015, 2014 and 2013, primarily related to restricted stock costs.

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, 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. As of September 30, 2015, 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 308,582 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. The associated expense is recognized ratably over the vesting period.

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, 2015, 2014 and 2013:

	2015				2014				2013
	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	988,637		$	42.22	1,052,844		$	36.20	1,262,582		$	32.46
Granted	444,543		50.50		464,438		45.05		473,775		40.48
Vested	(551,688	)	39.28		(524,532	)	32.67		(657,795	)	32.20
Forfeited	(3,388	)	48.55		(4,113	)	39.00		(25,718	)	33.42
Nonvested at end of year	878,104		$	48.24	988,637		$	42.22	1,052,844		$	36.20

As of September 30, 2015, there was $10.2 million of total unrecognized compensation cost related to nonvested restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.5 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2015, 2014 and 2013 was $21.7 million, $17.1 million and $21.2 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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Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2015	Oct. 30, 2015	Mar. 31, 2015
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, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock Shares Outstanding		101,506,645
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 5,500,632,050

XML

Details of Selected Consolidated Balance Sheet Captions

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Billed accounts receivable	$	204,585		$	262,937
Unbilled revenue	65,008			62,484
Other accounts receivable	40,850			41,971
Total accounts receivable	310,443			367,392
Less: allowance for doubtful accounts	(15,283		)	(23,992		)
Net accounts receivable	$	295,160		$	343,400

Other current assets

Other current assets as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Assets from risk management activities	$	9,232	$	45,827
Deferred gas costs	9,715		20,069
Taxes receivable	4,479		5,481
Prepaid expenses	27,734		25,039
Materials and supplies	12,587		5,704
Other	6,822		9,145
Total	$	70,569	$	111,265

Property, plant and equipment

Property, plant and equipment was comprised of the following as of September 30, 2015 and 2014:

	September 30
	2015			2014
	(In thousands)
Production plant	$	131		$	4,821
Storage plant	286,011			275,579
Transmission plant	1,844,117			1,622,846
Distribution plant	6,019,001			5,522,794
General plant	769,311			735,223
Intangible plant	41,131			38,858
	8,959,702			8,200,121
Construction in progress	280,398			247,579
	9,240,100			8,447,700
Less: accumulated depreciation and amortization	(1,809,520		)	(1,721,794		)
Net property, plant and equipment(1)	$	7,430,580		$	6,725,906

⁽¹⁾   Net property, plant and equipment includes plant acquisition adjustments of $(68.1) million and $(76.4) million at September 30, 2015 and 2014.

Goodwill

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2015:

	Regulated Distribution		Regulated Pipeline		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2014	$	574,816	$	132,502	$	34,711	$	742,029
Deferred tax adjustments on prior acquisitions(1)	633		40		—		673
Balance as of September 30, 2015	$	575,449	$	132,542	$	34,711	$	742,702

⁽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 2015.

Deferred charges and other assets

Deferred charges and other assets as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Marketable securities	$	74,200	$	79,613
Regulatory assets	182,573		230,240
Deferred financing costs	17,873		13,698
Assets from risk management activities	368		13,038
Other	13,664		14,340
Total	$	288,678	$	350,929

Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Trade accounts payable	$	78,534	$	77,860
Accrued gas payable	119,825		179,425
Accrued liabilities	40,583		50,801
Total	$	238,942	$	308,086

Other current liabilities

Other current liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer credit balances and deposits	$	100,232	$	82,085
Accrued employee costs	47,602		46,445
Deferred gas costs	28,100		35,063
Accrued interest	34,914		36,768
Liabilities from risk management activities	9,568		1,730
Taxes payable	93,674		77,601
Pension and postretirement obligations	21,857		11,380
Current deferred tax liability	55,918		48,751
Regulatory cost of removal accrual	56,123		45,061
Other	9,966		20,985
Total	$	457,954	$	405,869

Deferred credits and other liabilities

Deferred credits and other liabilities as of September 30, 2015 and 2014 were comprised of the following accounts.

	September 30
	2015		2014
	(In thousands)
Customer advances for construction	$	9,316	$	9,883
Regulatory liabilities	3,693		4,472
Asset retirement obligation	9,063		10,508
Liabilities from risk management activities	110,539		20,126
Other	29,085		23,881
Total	$	161,696	$	68,870

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Operating revenues
Operating revenues	$ 656,902	$ 686,401	$ 1,540,068	$ 1,258,765	$ 789,034	$ 943,170	$ 1,964,854	$ 1,243,858	$ 4,142,136	$ 4,940,916	$ 3,875,460
Purchased gas cost
Purchased gas cost									2,462,119	3,358,490	2,463,410
Gross profit	354,321	381,673	520,738	423,285	337,659	359,533	496,277	388,957	1,680,017	1,582,426	1,412,050
Operating expenses
Operation and maintenance									541,868	505,154	488,020
Depreciation and amortization									274,796	253,987	235,079
Taxes, other than income									231,958	211,936	187,072
Total operating expenses									1,048,622	971,077	910,171
Operating income	75,853	117,607	250,210	187,725	83,944	106,605	250,080	170,720	631,395	611,349	501,879
Miscellaneous income (expense), net									(4,389)	(5,235)	(197)
Interest charges									116,241	129,295	128,385
Income from continuing operations before income taxes									510,765	476,819	373,297
Income tax expense									195,690	187,002	142,599
Income from continuing operations									315,075	289,817	230,698
Income from discontinued operations, net of tax ($0, $0 and $3,986)									0	0	7,202
Gain on sale of discontinued operations, net of tax ($0, $0 and $2,909)									0	0	5,294
Net income	$ 23,515	$ 56,281	$ 137,684	$ 97,595	$ 23,713	$ 45,721	$ 133,367	$ 87,016	$ 315,075	$ 289,817	$ 243,194
Income per share from continuing operations - basic (usd per share)									$ 3.09	$ 2.96	$ 2.54
Income per share from discontinued operations - basic (usd per share)									0.00	0.00	0.14
Net income per share — basic (usd per share)	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	3.09	2.96	2.68
Income per share from continuing operations - diluted (usd per share)									3.09	2.96	2.50
Income per share from discontinued operations - diluted (usd per share)									0.00	0.00	0.14
Net income per share — diluted (usd per share)	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	$ 3.09	$ 2.96	$ 2.64
Weighted average shares outstanding:
Basic (shares)									101,892	97,606	90,533
Diluted (shares)									101,892	97,608	91,711
Intersegment Elimination [Member]
Operating revenues
Operating revenues									$ (464,020)	$ (506,381)	$ (380,847)
Purchased gas cost
Purchased gas cost									(463,488)	(505,878)	(379,430)
Regulated Distribution Segment [Member]
Operating revenues
Operating revenues	$ 369,656	$ 416,794	$ 1,130,613	$ 846,772	$ 409,014	$ 517,707	$ 1,290,960	$ 843,865	2,763,835	3,061,546	2,399,493
Purchased gas cost
Purchased gas cost									1,526,258	1,885,031	1,318,257
Gross profit									1,237,577	1,176,515	1,081,236
Operating expenses
Operation and maintenance									388,486	387,228	375,188
Depreciation and amortization									223,048	208,376	195,581
Taxes, other than income									205,894	196,343	167,374
Total operating expenses									817,428	791,947	738,143
Operating income									420,149	384,568	343,093
Miscellaneous income (expense), net									(377)	(381)	2,535
Interest charges									84,132	94,918	98,296
Income from continuing operations before income taxes									335,640	289,269	247,332
Income tax expense									130,827	117,684	96,476
Income from continuing operations											150,856
Income from discontinued operations, net of tax ($0, $0 and $3,986)											7,202
Gain on sale of discontinued operations, net of tax ($0, $0 and $2,909)											5,649
Net income									204,813	171,585	163,707
Regulated Pipeline Segment [Member]
Operating revenues
Operating revenues	97,807	97,008	91,730	83,567	86,314	87,189	73,615	71,341	370,112	318,459	268,900
Purchased gas cost
Purchased gas cost									0	0	0
Gross profit									370,112	318,459	268,900
Operating expenses
Operation and maintenance									118,866	91,466	76,686
Depreciation and amortization									47,236	41,031	35,302
Taxes, other than income									22,743	13,143	17,059
Total operating expenses									188,845	145,640	129,047
Operating income									181,267	172,819	139,853
Miscellaneous income (expense), net									(1,243)	(3,181)	(2,285)
Interest charges									33,151	36,280	30,678
Income from continuing operations before income taxes									146,873	133,358	106,890
Income tax expense									52,211	47,167	38,630
Income from continuing operations											68,260
Income from discontinued operations, net of tax ($0, $0 and $3,986)											0
Gain on sale of discontinued operations, net of tax ($0, $0 and $2,909)											0
Net income									94,662	86,191	68,260
Nonregulated Segment [Member]
Operating revenues
Operating revenues	$ 292,830	$ 278,769	$ 438,322	$ 462,288	$ 407,161	$ 465,485	$ 758,215	$ 436,431	1,472,209	2,067,292	1,587,914
Purchased gas cost
Purchased gas cost									1,399,349	1,979,337	1,524,583
Gross profit									72,860	87,955	63,331
Operating expenses
Operation and maintenance									35,048	26,963	37,569
Depreciation and amortization									4,512	4,580	4,196
Taxes, other than income									3,321	2,450	2,639
Total operating expenses									42,881	33,993	44,404
Operating income									29,979	53,962	18,927
Miscellaneous income (expense), net									(760)	2,216	2,316
Interest charges									967	1,986	2,168
Income from continuing operations before income taxes									28,252	54,192	19,075
Income tax expense									12,652	22,151	7,493
Income from continuing operations											11,582
Income from discontinued operations, net of tax ($0, $0 and $3,986)											0
Gain on sale of discontinued operations, net of tax ($0, $0 and $2,909)											(355)
Net income									$ 15,600	$ 32,041	$ 11,227

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Significant Accounting Policies

12 Months Ended

Sep. 30, 2015

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

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, 2015 and 2014 included the following:

	September 30
	2015		2014
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs(1)	$	121,183	$	162,777
Infrastructure Mechanisms(2)	32,813		26,948
Deferred gas costs	9,715		20,069
Recoverable loss on reacquired debt	16,319		18,877
APT annual adjustment mechanism	1,002		8,479
Rate case costs	1,533		3,757
Other	9,774		9,402
	$	192,339	$	250,309
Regulatory liabilities:
Regulatory cost of removal obligation	$	483,676	$	490,448
Deferred gas costs	28,100		35,063
Asset retirement obligation	9,063		10,508
Deferred franchise fees	—		5,268
Other	3,693		4,472
	$	524,532	$	545,759

⁽¹⁾ Includes $16.6 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.

⁽²⁾ Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest costs along with depreciation and other taxes, 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 $2.3 million, $1.5 million and $1.9 million was capitalized in 2015, 2014 and 2013.

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 3.3 percent, for each of the fiscal years ended September 30, 2015, 2014 and 2013.

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, 2015 and 2014, we had asset retirement obligations of $11.1 million and $10.5 million. Additionally, we had $4.8 million and $5.9 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, 2015 and 2014, 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 12.

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, 2015, 2014 and 2013, we included unrealized gains (losses) on open contracts of $(2.4) million, $9.6 million and $9.0 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, 2015 and 2014, the Company netted $43.5 million and $25.8 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.

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 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 utilize models and other valuation methods to determine fair value when external sources are not available. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.

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 current and 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 disclosed in Note 6 regarding the new mortality tables adopted for our pension plans and the approval of the merger of the AEH 401(k) Plan with the Retirement Savings Plan, 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. On July 9, 2015, the FASB voted to approve a deferral of the effective date of the new standard by one year. With the one-year extension, the new standard is currently scheduled to become effective for us beginning on October 1, 2018 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

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

In 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. We anticipate the adoption of this standard will not have a material impact on our financial position, results of operations and cash flows.

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Nature of Business

12 Months Ended

Sep. 30, 2015

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.

During fiscal 2013 and fiscal 2012, we sold our regulated distribution operations serving approximately 148,000 customers in Georgia, Illinois, Iowa and Missouri.

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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Accumulated Other Comprehensive Income

12 Months Ended

Sep. 30, 2015

Equity [Abstract]

Accumulated Other Comprehensive Income

Accumulated Other Comprehensive Income

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, 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	)

	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2013	$	5,448		$	37,906		$	(4,476	)	$	38,878
Other comprehensive income (loss) before reclassifications	3,009			(58,973		)	7,904			(48,060		)
Amounts reclassified from accumulated other comprehensive income	(795		)	2,686			(5,102		)	(3,211		)
Net current-period other comprehensive income (loss)	2,214			(56,287		)	2,802			(51,271		)
September 30, 2014	$	7,662		$	(18,381	)	$	(1,674	)	$	(12,393	)

The following tables detail reclassifications out of AOCI for the fiscal years ended September 30, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.

	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

	Fiscal Year Ended September 30, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	1,252		Operation and maintenance expense
	1,252			Total before tax
	(457		)	Tax expense
	$	795		Net of tax
Cash flow hedges
Interest rate agreements	$	(4,230	)	Interest charges
Commodity contracts	8,365			Purchased gas cost
	4,135			Total before tax
	(1,719		)	Tax expense
	$	2,416		Net of tax
Total reclassifications	$	3,211		Net of tax

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Leases

12 Months Ended

Sep. 30, 2015

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 19 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, 2015 were as follows:

	Operating Leases
	(In thousands)
2016	$	16,475
2017	16,639
2018	16,490
2019	15,207
2020	14,251
Thereafter	61,651
Total minimum lease payments	$	140,713

Consolidated lease and rental expense amounted to $32.5 million, $31.7 million and $32.4 million for fiscal 2015, 2014 and 2013.

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Debt

12 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt

Debt

Long-term debt

Long-term debt at September 30, 2015 and 2014 consisted of the following:

	2015		2014
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	—	$	500,000
Unsecured 6.35% Senior Notes, due 2017	250,000		250,000
Unsecured 8.50% Senior Notes, due 2019	450,000		450,000
Unsecured 5.95% Senior Notes, due 2034	200,000		200,000
Unsecured 5.50% Senior Notes, due 2041	400,000		400,000
Unsecured 4.15% Senior Notes, due 2043	500,000		500,000
Unsecured 4.125% Senior Notes, due 2044	500,000		—
Medium term 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	4,612		4,014
	$	2,455,388	$	2,455,986

On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps discussed in Note 12. The net proceeds of approximately $494 million were used to repay our $500 million4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt

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

We currently finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility, with a total availability from third-party lenders of approximately $1.3 billion of working capital funding. At September 30, 2015 and 2014, there was $457.9 million and $196.7 million outstanding under our commercial paper program with weighted average interest rates of 0.42% and 0.23%, 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 that provide approximately $1.3 billion of working capital funding. The first facility is a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 billion. On September 25, 2015, we terminated our existing $1.25 billion credit facility and entered into a new five-year $1.25 billion credit facility with substantially the same terms. The new facility also retains the $250 million accordion feature, which allows for an increase in the total committed loan amount to $1.5 billion. The credit facility 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, 2015, there were no borrowings under this facility, but we had $457.9 million of commercial paper outstanding leaving $792.1 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, 2015. At September 30, 2015, there were no borrowings outstanding under this facility.

The third facility which was renewed on September 30, 2015 for $10 million is a 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, 2015, 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, 2015, 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 $1.25 billion 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, 2015, our total-debt-to-total-capitalization ratio, as defined, was 49 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, 2015. We intend to seek renewal of this facility during the first quarter of fiscal 2016. There was $325.0 million outstanding under this facility at September 30, 2015.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility and one committed $15 million 364-day bilateral credit facility that expire in December 2015. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $36.1 million at September 30, 2015.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015. We intend to seek renewal of this facility during the first quarter of fiscal 2016. There were no borrowings outstanding under this facility at September 30, 2015.

Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013, that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, which generated net proceeds of $390.2 million. After giving effect to this issuance and the aforementioned $500 million senior note issuance completed in October 2014, $845 million of securities remained available for issuance under the shelf registration statement until March 28, 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, 2015. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

Maturities of long-term debt at September 30, 2015 were as follows (in thousands):

2016	$	—
2017	250,000
2018	—
2019	450,000
2020	—
Thereafter	1,760,000
	$	2,460,000

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Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Current income taxes
Federal	$ 0	$ 0	$ 0
State	7,251	5,527	8,178
Deferred income taxes
Federal	175,897	169,106	124,836
State	12,548	12,375	9,605
Investment tax credits	(6)	(6)	(20)
Income tax expense	195,690	187,002	142,599
Deferred tax assets
Employee benefit plans	121,619	116,157
Interest rate agreements	51,067	10,565
Tax net operating loss carryforwards	313,224	236,626
Tax credit carryforward	22,281	21,614
Other	36,695	28,849
Total deferred tax assets	544,886	413,811
Valuation allowance	(10,872)	(6,969)
Net deferred tax assets	534,014	406,842
Deferred tax liabilities
Difference in net book value and net tax value of assets	(1,890,886)	(1,655,894)
Pension funding	(35,247)	(17,890)
Gas Cost Adjustments	(43,634)	(31,252)
Other	(31,480)	(37,173)
Total deferred tax liabilities	(2,001,247)	(1,742,209)
Net deferred tax liabilities	(1,467,233)	(1,335,367)
Deferred credits for rate regulated entities	412	(109)
Deferred Tax Assets, Charitable Contribution Carryforwards [Abstract]
Deferred Tax Assets, Charitable Contribution Carryforwards	$ 11,400
Charitable Contribution Carryforwards, Expiration Date, Minimum	Dec. 31, 2015
Charitable Contribution Carryforwards, Expiration Date, Maximum	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	$ 12,629	4,158
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	1,009	3,846
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	3,431	4,625
Unrecognized Tax Benefits, Ending Balance	17,069	12,629	$ 4,158
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	820	411
Unrecognized Tax Benefits, Gross	17,889	13,040
Unrecognized Tax Benefits, Deferred Federal and State Income Tax Benefits	(6,261)	(4,564)
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	11,628	8,476
Valuation Allowance, Tax Credit Carryforward [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Charged to Cost and Expense	4,400	$ 7,000
Valuation Allowances and Reserves, Deductions	1,100
Valuation Allowance, Operating Loss Carryforwards [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Charged to Cost and Expense	600
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	14,900
Operating Loss Carryforwards, Federal Tax Effects	$ 8,000
State and Local Jurisdiction [Member] | Minimum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2016
State and Local Jurisdiction [Member] | Maximum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2030
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 307,300
Domestic Tax Authority [Member] | Minimum [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2029

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Segment Information

12 Months Ended

Sep. 30, 2015

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 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, 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	$	680,961		$	292,728		$	1,443		$	—		$	975,132

	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	$	584,065		$	249,347		$	1,839	$	—		$	835,251

	Year Ended September 30, 2013
	Regulated Distribution		Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,394,418	$	89,011		$	1,392,031		$	—		$	3,875,460
Intersegment revenues	5,075		179,889			195,883			(380,847		)	—
	2,399,493		268,900			1,587,914			(380,847		)	3,875,460
Purchased gas cost	1,318,257		—			1,524,583			(379,430		)	2,463,410
Gross profit	1,081,236		268,900			63,331			(1,417		)	1,412,050
Operating expenses
Operation and maintenance	375,188		76,686			37,569			(1,423		)	488,020
Depreciation and amortization	195,581		35,302			4,196			—			235,079
Taxes, other than income	167,374		17,059			2,639			—			187,072
Total operating expenses	738,143		129,047			44,404			(1,423		)	910,171
Operating income	343,093		139,853			18,927			6			501,879
Miscellaneous income (expense)	2,535		(2,285		)	2,316			(2,763		)	(197		)
Interest charges	98,296		30,678			2,168			(2,757		)	128,385
Income from continuing operations before income taxes	247,332		106,890			19,075			—			373,297
Income tax expense	96,476		38,630			7,493			—			142,599
Income from continuing operations	150,856		68,260			11,582			—			230,698
Income from discontinued operations, net of tax	7,202		—			—			—			7,202
Gain (loss) on sale of discontinued operations, net of tax	5,649		—			(355		)	—			5,294
Net income	$	163,707	$	68,260		$	11,227		$	—		$	243,194
Capital expenditures	$	528,599	$	313,230		$	3,204		$	—		$	845,033

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

	2015		2014		2013
	(In thousands)
Regulated distribution revenues:
Gas sales revenues:
Residential	$	1,761,689	$	1,933,099	$	1,512,495
Commercial	772,187		876,042		661,930
Industrial	74,981		90,536		81,155
Public authority and other	53,401		64,779		60,557
Total gas sales revenues	2,662,258		2,964,456		2,316,137
Transportation revenues	67,475		64,049		55,938
Other gas revenues	27,852		27,707		22,343
Total regulated distribution revenues	2,757,585		3,056,212		2,394,418
Regulated pipeline revenues	97,662		92,166		89,011
Nonregulated revenues	1,286,889		1,792,538		1,392,031
Total operating revenues	$	4,142,136	$	4,940,916	$	3,875,460

Balance sheet information at September 30, 2015 and 2014 by segment is presented in the following tables.

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

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

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Earnings Per Share

12 Months Ended

Sep. 30, 2015

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:

	2015		2014		2013
	(In thousands, except per share data)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	315,075	$	289,817	$	230,698
Less: Income from continuing operations allocated to participating securities	626		711		775
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from continuing operations per share — Basic	$	3.09	$	2.96	$	2.54
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	—	$	12,496
Less: Income from discontinued operations allocated to participating securities	—		—		42
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Income from discontinued operations per share — Basic	$	—	$	—	$	0.14
Net income per share — Basic	$	3.09	$	2.96	$	2.68
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,923
Effect of dilutive stock options and other shares	—		—		5
Income from continuing operations available to common shareholders	$	314,449	$	289,106	$	229,928
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from continuing operations per share — Diluted	$	3.09	$	2.96	$	2.50
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Effect of dilutive stock options and other shares	—		—		—
Income from discontinued operations available to common shareholders	$	—	$	—	$	12,454
Basic weighted average shares outstanding	101,892		97,606		90,533
Additional dilutive stock options and other shares	—		2		1,178
Diluted weighted average shares outstanding	101,892		97,608		91,711
Income from discontinued operations per share — Diluted	$	—	$	—	$	0.14
Net income per share — Diluted	$	3.09	$	2.96	$	2.64

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the fiscal year ended September 30, 2013. As of September 30, 2015 and 2014 there were no outstanding options.

2014 Equity Offering

On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 1,200,000 shares under our existing shelf registration statement. The offering was priced at $44.00 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 our Board of Directors approved a program authorizing the repurchase of up to five million shares of common stock over a 5-year period. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the Company. The program may be terminated or limited at any time. Shares may be repurchased in the open market or in privately negotiated transactions in amounts the Company deems appropriate. As of September 30, 2015, a total of 387,991 shares had been repurchased for an aggregate value of $12.5 million, with no shares repurchased since the first quarter of fiscal 2012. The share repurchase program is scheduled to end on September 30, 2016.

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Retirement and Post-retirement Employee Benefit Plans

12 Months Ended

Sep. 30, 2015

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 defined contribution plans 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 Plans			Supplemental Executive Retirement Plans		Postretirement Plans			Total
	(In thousands)
September 30, 2015
Unrecognized transition obligation	$	—		$	—	$	82		$	82
Unrecognized prior service credit	(1,735		)	—		(4,524		)	(6,259		)
Unrecognized actuarial loss	120,948			36,915		(47,149		)	110,714
	$	119,213		$	36,915	$	(51,591	)	$	104,537
September 30, 2014
Unrecognized transition obligation	$	—		$	—	$	354		$	354
Unrecognized prior service credit	(1,927		)	—		(6,168		)	(8,095		)
Unrecognized actuarial loss	109,767			34,447		7,531			151,745
	$	107,840		$	34,447	$	1,717		$	144,004

Defined Benefit Plans

Employee Pension Plans

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. 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).

The Plan also provides for an additional annual allocation based upon a participant’s age as of January 1, 1999 for those participants who were participants in the prior pension plans. The Plan credited this additional allocation each year through December 31, 2008. In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. A special grandfathered benefit also applied through December 31, 2008, for participants who were at least age 50 as of January 1, 1999 and who were participants in one of the prior plans on December 31, 1998. 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. In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Plan to new participants effective October 1, 2010. Additionally, employees participating in the Plan as of October 1, 2010 were allowed to make a one-time election to migrate from the Plan into our defined contribution plan, which was enhanced, effective January 1, 2011.

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 2015 and 2014 we contributed $38.0 million and $27.1 million in cash to the Plans to achieve a desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at September 30, 2015, the current funded position of the Plans and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2016. 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, 2015 and 2014.

	Targeted Allocation  Range	Actual Allocation September 30
Security Class		2015		2014
Domestic equities	35%-55%	41.3	%	44.9	%
International equities	10%-20%	14.9	%	15.3	%
Fixed income	5%-30%	11.0	%	9.7	%
Company stock	0%-15%	15.2	%	12.9	%
Other assets	0%-20%	17.6	%	17.2	%

At September 30, 2015 and 2014, the Plan held 1,169,700 shares of our common stock, which represented 15.2 percent of total Plan assets and 12.9 percent of total Master Trust assets. These shares generated dividend income for the Plan of approximately $1.8 million and $1.7 million during fiscal 2015 and 2014.

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 Plans were determined as of September 30, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the Plans were determined as of September 30, 2014, 2013 and 2012. In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. On October 8, 2015, the Society of Actuaries issued an additional report related to mortality tables and the mortality improvement scale.  As of September 30, 2015, we updated our assumed mortality rates to incorporate both new sets of mortality tables issued by the Society of Actuaries.

Additional assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%
Expected return on plan assets	7.00	%	7.25	%	7.25	%	7.25	%	7.75	%

The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	485,921		$	466,182
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	493,594		$	455,799
Service cost	16,231			15,345
Interest cost	21,850			22,330
Actuarial (gain) loss	7,420			26,611
Benefits paid	(30,496		)	(24,519		)
Plan amendments	—			(1,972		)
Benefit obligation at end of year	508,599			493,594
Change in plan assets:
Fair value of plan assets at beginning of year	434,767			396,887
Actual return on plan assets	8,661			35,289
Employer contributions	38,000			27,110
Benefits paid	(30,496		)	(24,519		)
Fair value of plan assets at end of year	450,932			434,767
Reconciliation:
Funded status	(57,667		)	(58,827		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Net amount recognized	$	(57,667	)	$	(58,827	)

Net periodic pension cost for the Plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	16,231		$	15,345		$	17,754
Interest cost	21,850			22,330			19,334
Expected return on assets	(25,744		)	(23,601		)	(22,955		)
Amortization of prior service credit	(192		)	(136		)	(141		)
Recognized actuarial loss	13,322			13,777			19,066
Net periodic pension cost	$	25,467		$	27,715		$	33,058

The following table sets forth by level, within the fair value hierarchy, the Master Trust's assets at fair value as of September 30, 2015 and 2014. 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 Master Trust are fully described in Note 2. In addition to the assets shown below, the Master Trust had net accounts receivable of $2.4 million and $2.7 million at September 30, 2015 and 2014 which materially approximates fair value due to the short-term nature of these assets.

	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:
Domestic funds	33,312		—		—		33,312
International funds	48,648		—		—		48,648
Common/collective trusts — domestic funds	—		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

	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks	$	155,107	$	—	$	—	$	155,107
Money market funds	—		11,226		—		11,226
Registered investment companies:
Domestic funds	33,266		—		—		33,266
International funds	48,134		—		—		48,134
Common/collective trusts — domestic funds	—		91,792		—		91,792
Government securities:
Mortgage-backed securities	—		12,520		—		12,520
U.S. treasuries	3,117		562		—		3,679
Corporate bonds	—		25,734		—		25,734
Limited partnerships	—		50,496		—		50,496
Real estate	—		—		155		155
Total investments at fair value	$	239,624	$	192,330	$	155	$	432,109

During 2015, the Company determined that a 2014 investment in the registered investment companies - domestic funds should have been classified as common/collective trusts - domestic funds. The amount has been recast in the above table.

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.

On April 1, 2013, due to the retirement of certain executives, we recognized a settlement loss of $3.2 million associated with the supplemental plans and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which reduced our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year.

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, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2014, 2013 and 2012. These assumptions are presented in the following table:

	Pension Liability				Pension Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%	(1)
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

⁽¹⁾ The discount rate for the supplemental plans increased from 4.04% to 4.21% effective April 1, 2013 due to a settlement loss recorded in fiscal 2013.

The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Accumulated benefit obligation	$	118,835		$	106,276
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	113,219		$	117,080
Service cost	3,971			3,607
Interest cost	4,943			4,966
Actuarial (gain) loss	4,811			9,468
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Benefit obligation at end of year	122,393			113,219
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	4,551			21,902
Benefits paid	(4,551		)	(5,085		)
Settlements	—			(16,817		)
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(122,393		)	(113,219		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(122,393	)	$	(113,219	)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2015 and 2014, assets held in the rabbi trusts consisted of available-for-sale securities of $41.7 million and $46.2 million, which are included in our fair value disclosures in Note 14.

Net periodic pension cost for the supplemental plans for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the following components:

	Fiscal Year Ended September 30
	2015		2014		2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	3,971	$	3,607	$	3,039
Interest cost	4,943		4,966		4,755
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,343		1,948		2,918
Settlements	—		4,539		3,160
Net periodic pension cost	$	11,257	$	15,060	$	13,872

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 Plans		Supplemental Plans
	(In thousands)
2016	$	30,909	$	21,857
2017	31,805		13,901
2018	33,086		12,807
2019	34,712		6,808
2020	36,128		4,454
2021-2025	201,857		47,047

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.

As of September 30, 2009, the Board of Directors approved a change to the cost sharing methodology for employees who had not met the participation requirements by that date for the Atmos Retiree Medical Plan. Starting on January 1, 2015, the contribution rates that apply to all non-grandfathered participants are determined using a cost sharing methodology by which Atmos Energy will limit its contribution to a three percent cost increase in claims and administrative costs each year. If medical costs covered by the Atmos Retiree Medical Plan increase more than three percent annually, participants will be 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 $30 million and $40 million to our postretirement benefits plan during fiscal 2016.

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, 2015 and 2014.

	Actual Allocation September 30
Security Class	2015		2014
Diversified investment funds	97.5	%	99.7	%
Cash and cash equivalents	2.5	%	0.3	%

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, 2015 and 2014 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2014, 2013 and 2012. The assumptions are presented in the following table:

	Postretirement Liability				Postretirement Cost
	2015		2014		2015		2014		2013
Discount rate	4.55	%	4.43	%	4.43	%	4.95	%	4.04	%
Expected return on plan assets	4.45	%	4.60	%	4.60	%	4.60	%	4.70	%
Initial trend rate	7.50	%	7.50	%	7.50	%	8.00	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2021		2020		2020		2020		2019

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2015 and 2014:

	2015			2014
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	315,118		$	312,148
Service cost	15,583			16,784
Interest cost	14,385			15,951
Plan participants’ contributions	4,563			4,435
Actuarial (gain) loss	(69,962		)	(18,963		)
Benefits paid	(12,508		)	(13,580		)
Plan amendments	—			(1,657		)
Benefit obligation at end of year	267,179			315,118
Change in plan assets:
Fair value of plan assets at beginning of year	134,821			106,413
Actual return on plan assets	(8,851		)	14,003
Employer contributions	19,984			23,550
Plan participants’ contributions	4,563			4,435
Benefits paid	(12,508		)	(13,580		)
Fair value of plan assets at end of year	138,009			134,821
Reconciliation:
Funded status	(129,170		)	(180,297		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(129,170	)	$	(180,297	)

Net periodic postretirement cost for fiscal 2015, 2014 and 2013 is recorded as operating expense and included the components presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	15,583		$	16,784		$	18,800
Interest cost	14,385			15,951			12,964
Expected return on assets	(6,431		)	(5,167		)	(3,988		)
Amortization of transition obligation	272			274			1,081
Amortization of prior service credit	(1,644		)	(1,450		)	(1,450		)
Recognized actuarial loss	—			631			4,196
Net periodic postretirement cost	$	22,165		$	27,023		$	31,603

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	$	4,288	$	(3,426	)
Effect on postretirement benefit obligation	$	39,572	$	(32,440	)

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, 2015 and 2014. 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, 2015
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,486	$	—	$	3,486
Registered investment companies:
Domestic funds	123,921		—		—		123,921
International funds	10,602		—		—		10,602
Total investments at fair value	$	134,523	$	3,486	$	—	$	138,009

	Assets at Fair Value as of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	434	$	—	$	434
Registered investment companies:
Domestic funds	124,006		—		—		124,006
International funds	10,381		—		—		10,381
Total investments at fair value	$	134,387	$	434	$	—	$	134,821

During 2015, the Company determined that a 2014 investment in the registered investment companies - international funds should have been classified as registered investment companies - domestic funds. The amount has been recast in the above table.

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 2015 include contributions to our postretirement plan trusts.

	Company Payments		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2016	$	15,498	$	2,382	$	—	$	17,880
2017	11,245		2,677		—		13,922
2018	12,185		2,980		—		15,165
2019	12,755		3,324		—		16,079
2020	13,995		3,766		—		17,761
2021-2025	86,519		26,363		—		112,882

Defined Contribution Plans

As of September 30, 2015, we maintained two defined contribution benefit plans: the Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) and the Atmos Energy Holdings, LLC 401K Profit-Sharing Plan (the AEH 401K Profit-Sharing Plan).

The Retirement Savings Plan covers substantially all employees in our regulated operations 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, 2014, we also maintained the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401K 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 401K Plan were eligible to participate in the Retirement Savings Plan. Participants who did not actively elect to participate in the Retirement Savings Plan were automatically enrolled in the Retirement Savings Plan at a salary reduction level of four percent, which they had the choice to opt out of within 30 days. In addition, participants could have elected to transfer their funds from the Union 401K Plan to the Retirement Savings Plan. Effective January 1, 2015, all remaining participants became participants in the Retirement Savings Plan. Following this transfer, the Union 401K Plan was terminated.

Matching contributions to the Retirement Savings Plan and the Union 401K Plan are expensed as incurred and amounted to $11.5 million, $10.9 million and $10.4 millionfor fiscal years2015,2014and2013. 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 2015, 2014 or 2013. At September 30, 2015 and 2014, the Retirement Savings Plan held 4.3 percent and 4.5 percent of our outstanding common stock.

The AEH 401K Profit-Sharing Plan covers substantially all AEH employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Participants may elect a salary reduction up to a maximum of 75 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. The Company may elect to make safe harbor contributions up to four percent of the employee’s salary which vest immediately. The Company may also make discretionary profit sharing contributions to the AEH 401K Profit-Sharing Plan. Participants become fully vested in the discretionary profit-sharing contributions after three years of service. Participants are also permitted to take out loans against their accounts subject to certain restrictions. Discretionary contributions to the AEH 401K Profit-Sharing Plan are expensed as incurred and amounted to $1.1 million, $1.4 million and $1.1 million for fiscal years 2015, 2014 and 2013.

On November 4, 2015, the Atmos Energy Corporation Board of Directors voted to approve the merger of the assets and liabilities of the AEH 401K Profit-Sharing Plan with the Retirement Savings Plan, effective January 1, 2016 to improve administrative efficiency and reduce total costs.

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Financial Instruments Balance Sheet Location (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Derivatives, Fair Value [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 8,900	$ 22,700
Derivative Asset	9,600	58,865
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	34,600	3,100
Derivative Liability	(120,107)	(21,856)
Regulated Distribution Segment [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	746	36,140
Derivative Asset, Contract Netting	0	0
Derivative Asset, Net of Contract Netting	746	36,140
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Asset	746	36,140
Derivative Liability, Fair Value, Gross Liability	(120,107)	(21,856)
Derivative Liability, Contract Netting	0	0
Derivative Liability, Net of Contract Netting	(120,107)	(21,856)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	(120,107)	(21,856)
Regulated Distribution Segment [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	34,477
Derivative Liability, Fair Value, Gross Liability	(110,539)	(19,835)
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		21,869
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	12,608
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		0
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	(110,539)	(19,835)
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	746	1,663
Derivative Liability, Fair Value, Gross Liability	(9,568)	(2,021)
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	378	1,233
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	368	430
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	(9,568)	(1,730)
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	(291)
Nonregulated Segment [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	91,363	69,023
Derivative Asset, Contract Netting	(91,363)	(69,023)
Derivative Asset, Net of Contract Netting	0	0
Derivative, Collateral, Right to Reclaim Cash	8,854	22,725
Derivative Asset	8,854	22,725
Derivative Liability, Fair Value, Gross Liability	(125,983)	(72,056)
Derivative Liability, Contract Netting	91,363	69,023
Derivative Liability, Net of Contract Netting	(34,620)	(3,033)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	34,620	3,033
Derivative Liability	0	0
Nonregulated Segment [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	11,806	9,669
Derivative Liability, Fair Value, Gross Liability	(45,985)	(9,541)
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	11,680	8,912
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	126	757
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	(36,067)	(7,082)
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	(9,918)	(2,459)
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	79,557	59,354
Derivative Liability, Fair Value, Gross Liability	(79,998)	(62,515)
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	65,239	43,677
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	14,318	15,677
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	(65,780)	(47,729)
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	$ (14,218)	$ (14,786)

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Financial Instruments Commodity Contract Volumes (Details)	Sep. 30, 2015 MMcf
Regulated Distribution Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	24,849
Regulated Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	24,849
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	96,503
Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	58,513
Nonregulated Segment [Member] | Fair Value Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	(18,378)
Nonregulated Segment [Member] | Cash Flow Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	56,368

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Financial Instruments Financial Instruments at Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2015		Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Current	$ 9,232		$ 45,827
Derivative Asset, Noncurrent	368		13,038
Derivative Liability, Current	(9,568)		(1,730)
Derivative Liability, Noncurrent	(110,539)		(20,126)
Derivative Assets (Liabilities), at Fair Value, Net	(110,507)		37,009
Cash Held in Margin Accounts	43,500		25,800
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities	34,600		3,100
Cash Held In Margin Accounts Classified Current Risk Management Asset	8,900		22,700
Regulated Distribution Segment [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Current	378		23,102
Derivative Asset, Noncurrent	368		13,038
Derivative Liability, Current	(9,568)		(1,730)
Derivative Liability, Noncurrent	(110,539)		(20,126)
Derivative Assets (Liabilities), at Fair Value, Net	(119,361)		14,284
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities	0		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	8,854	[1]	22,725	[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	8,854		22,725
Cash Held In Margin Accounts Used to Offset Risk Management Liabilities	34,620		3,033
Cash Held In Margin Accounts Classified Current Risk Management Asset	$ 8,854		$ 22,725

[1] Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

[2] Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

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Debt (Table)

12 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt instrument table

Long-term debt at September 30, 2015 and 2014 consisted of the following:

	2015		2014
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	—	$	500,000
Unsecured 6.35% Senior Notes, due 2017	250,000		250,000
Unsecured 8.50% Senior Notes, due 2019	450,000		450,000
Unsecured 5.95% Senior Notes, due 2034	200,000		200,000
Unsecured 5.50% Senior Notes, due 2041	400,000		400,000
Unsecured 4.15% Senior Notes, due 2043	500,000		500,000
Unsecured 4.125% Senior Notes, due 2044	500,000		—
Medium term 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	4,612		4,014
	$	2,455,388	$	2,455,986

Debt maturity schedule

Maturities of long-term debt at September 30, 2015 were as follows (in thousands):

2016	$	—
2017	250,000
2018	—
2019	450,000
2020	—
Thereafter	1,760,000
	$	2,460,000

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Retirement and Post-Retirement Employee Benefit Plans Defined Benefit Plans Disclosure (Details) - USD ($) $ in Thousands					6 Months Ended		12 Months Ended
	Nov. 04, 2015	Oct. 08, 2015	Oct. 02, 2013	Apr. 02, 2013	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]
Unrecognized transition obligation							$ 82	$ 354
Unrecognized prior service cost							(6,259)	(8,095)
Unrecognized actuarial loss							110,714	151,745
Total unrecognized in net periodic cost							$ 104,537	144,004
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided							15 years
Subsequent Event, AEH 401K Merger [Member]
Subsequent Event [Line Items]
Subsequent Event, Date	Nov. 04, 2015
Subsequent Event, Description	the Atmos Energy Corporation Board of Directors voted to approve the merger of the assets and liabilities of the AEH 401K Profit-Sharing Plan with the Retirement Savings Plan, effective January 1, 2016 to improve administrative efficiency and reduce total costs.
Subsequent Event, Mortality Tables Update [Member]
Subsequent Event [Line Items]
Subsequent Event, Date		Oct. 08, 2015
Subsequent Event, Description		the Society of Actuaries issued an additional report related to mortality tables and the mortality improvement scale.  As of September 30, 2015, we updated our assumed mortality rates to incorporate both new sets of mortality tables issued by the Society of Actuaries.
Pension Plans, Defined Benefit [Member]
Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]
Unrecognized transition obligation							$ 0	0
Unrecognized prior service cost							(1,735)	(1,927)
Unrecognized actuarial loss							120,948	109,767
Total unrecognized in net periodic cost							$ 119,213	$ 107,840
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount rate							4.43%	4.95%	4.04%
Rate of compensation increase							3.50%	3.50%	3.50%
Expected return on plan assets							7.25%	7.25%	7.75%
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract
Discount rate							4.55%	4.43%
Rate of compensation increase							3.50%	3.50%
Expected return on plan assets							7.00%	7.25%
Accumulated benefit obligation							$ 485,921	$ 466,182
Defined Benefit Plan Change In Benefit Obligation Roll Forward
Benefit obligation at beginning of year			$ 455,799				493,594	455,799
Service cost							16,231	15,345	$ 17,754
Interest cost							21,850	22,330	19,334
Actuarial (gain) loss							7,420	26,611
Benefits paid							(30,496)	(24,519)
Plan amendments							0	(1,972)
Benefit obligation at end of year					$ 455,799		508,599	493,594	$ 455,799
Funded Status of Plan Reconciliation
Funded status							(57,667)	(58,827)
Unrecognized prior service cost							0	0
Unrecognized net loss							0	0
Net amount recognized							(57,667)	$ (58,827)
Estimated Future Benefits Payment, Total
Expected future benefit payments in year one, total							30,909
Expected future benefit payments in year two, total							31,805
Expected future benefit payments in year three, total							33,086
Expected future benefit payments in year four, total							34,712
Expected future benefit payments in year five, total							36,128
Expected future benefit payments in five fiscal years thereafter, total							$ 201,857
Pension Plans, Defined Benefit [Member] | Minimum [Member]
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
Defined Benefit Plan, Investment Performance Review Period							3 years
Pension Plans, Defined Benefit [Member] | Maximum [Member]
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
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							41.30%	44.90%
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							14.90%	15.30%
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							11.00%	9.70%
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							15.20%	12.90%
Number of shares of Atmos Energy common stock in Master Trust							1,169,700	1,169,700
Amount of dividend income from Atmos Energy common stock in Master Trust							$ 1,800	$ 1,700
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							17.60%	17.20%
Pension Account Plan, Defined Benefit [Member]
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
Defined Benefit Plan, Vesting Period							3 years
Supplemental Employee Retirement Plan [Member]
Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]
Unrecognized transition obligation							$ 0	$ 0
Unrecognized prior service cost							0	0
Unrecognized actuarial loss							36,915	34,447
Total unrecognized in net periodic cost							$ 36,915	$ 34,447
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount rate				4.21%	4.21%	4.04%	4.43%	4.95%	4.04%	[1]
Rate of compensation increase							3.50%	3.50%	3.50%
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract
Discount rate							4.55%	4.43%
Rate of compensation increase							3.50%	3.50%
Accumulated benefit obligation							$ 118,835	$ 106,276
Defined Benefit Plan Change In Benefit Obligation Roll Forward
Benefit obligation at beginning of year			117,080				113,219	117,080
Service cost							3,971	3,607	$ 3,039
Interest cost							4,943	4,966	4,755
Actuarial (gain) loss							4,811	9,468
Benefits paid							(4,551)	(5,085)
Settlements							0	(16,817)
Benefit obligation at end of year					$ 117,080		122,393	113,219	117,080
Funded Status of Plan Reconciliation
Funded status							(122,393)	(113,219)
Unrecognized prior service cost							0	0
Unrecognized net loss							0	0
Net amount recognized							(122,393)	$ (113,219)
Estimated Future Benefits Payment, Total
Expected future benefit payments in year one, total							21,857
Expected future benefit payments in year two, total							13,901
Expected future benefit payments in year three, total							12,807
Expected future benefit payments in year four, total							6,808
Expected future benefit payments in year five, total							4,454
Expected future benefit payments in five fiscal years thereafter, total							47,047
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
Defined Benefit Plan, Description of Settlements and Curtailments								On April 1, 2013, due to the retirement of certain executives, we recognized a settlement loss of $3.2 million associated with the supplemental plans and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which reduced our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year.
Settlements				$ 3,200			$ 0	$ 4,539	$ 3,160
Supplemental Executive Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Change In Benefit Obligation Roll Forward
Benefits paid			(16,800)
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
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]
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
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%
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
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]
Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]
Unrecognized transition obligation							$ 82	354
Unrecognized prior service cost							(4,524)	(6,168)
Unrecognized actuarial loss							(47,149)	7,531
Total unrecognized in net periodic cost							$ (51,591)	$ 1,717
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract
Discount rate							4.43%	4.95%	4.04%
Expected return on plan assets							4.60%	4.60%	4.70%
Initial Trend							7.50%	8.00%	8.00%
Ultimate trend rate							5.00%	5.00%	5.00%
Ultimate trend rate reached in					2019		2020	2020	2019
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract
Discount rate							4.55%	4.43%
Expected return on plan assets							4.45%	4.60%
Initial trend rate							7.50%	7.50%
Ultimate trend rate							5.00%	5.00%
Ultimate trend reached in							2021	2020
Defined Benefit Plan Change In Benefit Obligation Roll Forward
Benefit obligation at beginning of year			$ 312,148				$ 315,118	$ 312,148
Service cost							15,583	16,784	$ 18,800
Interest cost							14,385	15,951	12,964
Plan participants' contributions							4,563	4,435
Actuarial (gain) loss							(69,962)	(18,963)
Benefits paid							(12,508)	(13,580)
Plan amendments							0	(1,657)
Benefit obligation at end of year					$ 312,148		267,179	315,118	$ 312,148
Funded Status of Plan Reconciliation
Funded status							(129,170)	(180,297)
Unrecognized prior service cost							0	0
Unrecognized transition obligation							0	0
Unrecognized net loss							0	0
Net amount recognized							(129,170)	$ (180,297)
Estimated company benefit payments
2006							15,498
2007							11,245
Estimated company benefit payments in year three							12,185
Estimated company benefit payments in year four							12,755
Estimated company benefit payments in year five							13,995
Estimated company benefit payments in five fiscal years thereafter							86,519
Estimated retiree benefit payments
Estimated retiree benefit payments in year one							2,382
Estimated retiree benefit payments in year two							2,677
Estimated retiree benefit payments in year three							2,980
Estimated retiree benefit payments in year four							3,324
Estimated retiree benefit payments in year five							3,766
Estimated retiree benefit payments in five fiscal years thereafter							26,363
Disclosure Of Expected Gross Prescription Drug Subsidy Receipts Abstract
Prescription drug subsidy receipts in year one							0
Prescription drug subsidy receipts in year two							0
Prescription drug subsidy receipts in year three							0
Prescription drug subsidy receipts in year four							0
Prescription drug subsidy receipts in year five							0
Prescription drug subsidy receipts in five fiscal years thereafter							0
Estimated Future Benefits Payment, Total
Expected future benefit payments in year one, total							17,880
Expected future benefit payments in year two, total							13,922
Expected future benefit payments in year three, total							15,165
Expected future benefit payments in year four, total							16,079
Expected future benefit payments in year five, total							17,761
Expected future benefit payments in five fiscal years thereafter, total							112,882
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							4,288
Effect of One Percentage Point Decrease on Service and Interest Cost Components							(3,426)
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation							39,572
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation							$ (32,440)
Defined Benefit Plan, Employer Claims Paid							80.00%
Defined Benefit Plan, Employee Paid Claims							20.00%
Defined Benefit Plan, Percent Limit on Future Contributions							3.00%
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							$ 30,000
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							$ 40,000
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							97.50%	99.70%
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
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							2.50%	0.30%

[1] (1)The discount rate for the supplemental plans increased from 4.04% to 4.21% effective April 1, 2013 due to a settlement loss recorded in fiscal 2013.

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Income Taxes

12 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The components of income tax expense from continuing operations for 2015, 2014 and 2013 were as follows:

	2015			2014			2013
	(In thousands)
Current
Federal	$	—		$	—		$	—
State	7,251			5,527			8,178
Deferred
Federal	175,897			169,106			124,836
State	12,548			12,375			9,605
Investment tax credits	(6		)	(6		)	(20		)
	$	195,690		$	187,002		$	142,599

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2015, 2014 and 2013 are set forth below:

	2015			2014			2013
	(In thousands)
Tax at statutory rate of 35%	$	178,768		$	166,887		$	130,655
Common stock dividends deductible for tax reporting	(2,413		)	(2,307		)	(2,153		)
State taxes (net of federal benefit)	12,869			11,636			11,559
Change in valuation allowance	4,998			6,969			1,085
Other, net	1,468			3,817			1,453
Income tax expense	$	195,690		$	187,002		$	142,599

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, 2015 and 2014 are presented below:

	2015			2014
	(In thousands)
Deferred tax assets:
Employee benefit plans	$	121,619		$	116,157
Interest rate agreements	51,067			10,565
Net operating loss carryforwards	313,224			236,626
Charitable and other credit carryforwards	22,281			21,614
Other	36,695			28,849
Total deferred tax assets	544,886			413,811
Valuation allowance	(10,872		)	(6,969		)
Net deferred tax assets	534,014			406,842
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(1,890,886		)	(1,655,894		)
Pension funding	(35,247		)	(17,890		)
Gas cost adjustments	(43,634		)	(31,252		)
Other	(31,480		)	(37,173		)
Total deferred tax liabilities	(2,001,247		)	(1,742,209		)
Net deferred tax liabilities	$	(1,467,233	)	$	(1,335,367	)
Deferred credits for rate regulated entities	$	412		$	(109	)

At September 30, 2015, we had $307.3 million of federal net operating loss carryforwards, which includes the impact of stock based compensation. 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 $11.4 million in charitable contribution carryforwards to offset taxable income. The Company’s charitable contribution carryforwards expire in 2015 - 2020. We believe it is more likely than not that the benefit from certain charitable contribution carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for charitable contribution carryforwards, a valuation allowance of $4.4 million and $7.0 million was established for the years ended September 30, 2015 and 2014. In addition, $1.1 million of deferred tax assets expired for which a valuation allowance had previously been recorded during the year ended September 30, 2015.

For state taxable income, the Company has $14.9 million of state net operating loss carryforwards (net of $8.0 million of federal effects) and $0.8 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 2016 and 2030. We believe it is more likely than not that a portion of the benefit from certain state net operating loss carryfowards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset for these carryforwards, a valuation allowance of $0.6 million (net of federal effects) was established for the year ended September 30, 2015. The state tax credits will begin to expire in 2018.

At September 30, 2015, we had recorded liabilities associated with unrecognized tax benefits totaling $17.1 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:

	2015			2014
	(In thousands)
Unrecognized tax benefits - beginning balance	$	12,629		$	4,158
Increase resulting from prior period tax positions	1,009			3,846
Increase resulting from current period tax positions	3,431			4,625
Unrecognized tax benefits - ending balance	17,069			12,629
Accrued interest and penalties	820			411
Gross unrecognized tax benefits	17,889			13,040
Less: deferred federal and state income tax benefits	(6,261		)	(4,564		)
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$	11,628		$	8,476

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.

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Discontinued Operations

12 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

Discontinued Operations

On April 1, 2013, we completed the sale of substantially all of our regulated distribution assets and certain related nonregulated assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million, pursuant to an asset purchase agreement executed on August 8, 2012. In connection with the sale, we recognized a pre-tax gain of approximately $8.2 million.

As required under generally accepted accounting principles, the operating results of our Georgia operations for the year ended September 30, 2013 have been aggregated and reported on the consolidated statements of income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.

The following table presents statement of income data related to discontinued operations in our Georgia service area for the year ended September 30, 2013.

	Year Ended September 30, 2013
	(In thousands)
Operating revenues	$	37,962
Purchased gas cost	21,464
Gross profit	16,498
Operating expenses	5,858
Operating income	10,640
Other nonoperating income	548
Income from discontinued operations before income taxes	11,188
Income tax expense	3,986
Income from discontinued operations	7,202
Gain on sale of discontinued operations, net of tax	5,294
Net income from discontinued operations	$	12,496

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended			48 Months Ended
	Feb. 18, 2014	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2015
Basic Earnings per Share from Continuing Operations
Income from continuing operations										$ 315,075	$ 289,817	$ 230,698
Less: Income from continuing operations allocated to participating securities										626	711	775
Income from continuing operations available to common shareholders										$ 314,449	$ 289,106	$ 229,923
Basic weighted average shares outstanding (shares)										101,892,000	97,606,000	90,533,000
Income per share from continuing operations - basic (usd per share)										$ 3.09	$ 2.96	$ 2.54
Basic Earnings per Share from Discontinued Operations
Income from discontinued operations										$ 0	$ 0	$ 12,496
Less: Income from discontinued operations allocated to participating securities										0	0	42
Income from discontinued operations available to common shareholders										$ 0	$ 0	$ 12,454
Income (loss) from discontinued operations per share - Basic (usd per share)										$ 0.00	$ 0.00	$ 0.14
Net income per share — basic (usd per share)		$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	$ 3.09	$ 2.96	$ 2.68
Diluted Earnings per Share from Continuing Operations
Effect of dilutive stock options and other shares										$ 0	$ 0	$ 5
Income (loss) from continuing operations available to common shareholders										$ 314,449	$ 289,106	$ 229,928
Additional dilutive stock options and other shares										0	2,000	1,178,000
Diluted weighted average shares outstanding (shares)										101,892,000	97,608,000	91,711,000
Income per share from continuing operations - diluted (usd per share)										$ 3.09	$ 2.96	$ 2.50
Diluted Earnings per Share from Discontinued Operations
Effect of dilutive stock options and other shares										$ 0	$ 0	$ 0
Income from discontinued operations available to common shareholders										$ 0	$ 0	$ 12,454
Additional dilutive stock options and other shares										0	2,000	1,178,000
Diluted weighted average shares outstanding										101,892,000	97,608,000	91,711,000
Income per share from discontinued operations - diluted (usd per share)										$ 0.00	$ 0.00	$ 0.14
Net income per share — diluted (usd per share)		$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	$ 3.09	$ 2.96	$ 2.64
Earnings Per Share Diluted Other Disclosures Abstract
Anti-dilutive stock options excluded from computation of diluted earnings per share												0
Stock Issued During Period, Shares, New Issues	9,200,000
Shares Issued At Overallotment Option	1,200,000
Net proceeds from equity offering	$ 390,200									$ 0	$ 390,205	$ 0
Share Price	$ 44.00
Stock Repurchase Program [Abstract]
Stock Repurchased During Period, Shares													387,991
Stock Repurchased During Period, Value													$ 12,500
Summary Of Stock Option Activity [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number		0				0				0	0		0

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Financial Instruments (Table)

12 Months Ended

Sep. 30, 2015

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, 2015 and 2014:

	Regulated Distribution			Nonregulated		Total
	(In thousands)
September 30, 2015
Assets from risk management activities, current(1)	$	378		$	8,854	$	9,232
Assets from risk management activities, noncurrent	368			—		368
Liabilities from risk management activities, current(1)	(9,568		)	—		(9,568		)
Liabilities from risk management activities, noncurrent(1)	(110,539		)	—		(110,539		)
Net assets (liabilities)	$	(119,361	)	$	8,854	$	(110,507	)
September 30, 2014
Assets from risk management activities, current(2)	$	23,102		$	22,725	$	45,827
Assets from risk management activities, noncurrent	13,038			—		13,038
Liabilities from risk management activities, current(2)	(1,730		)	—		(1,730		)
Liabilities from risk management activities, noncurrent(2)	(20,126		)	—		(20,126		)
Net assets	$	14,284		$	22,725	$	37,009

⁽¹⁾  Includes $43.5 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $34.6 million was used to offset current and noncurent risk management liabilities under master netting arrangements and the remaining $8.9 million is classified as current risk management assets.

⁽²⁾  Includes $25.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.

Outstanding commodity contracts volumes table

As of September 30, 2015, we had net long/(short) commodity contracts outstanding in the following quantities:

Contract Type	Hedge Designation	Regulated Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(18,378	)
	Cash Flow	—	56,368
	Not designated	24,849	58,513
		24,849	96,503

Financial instruments on the balance sheet

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

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of September 30, 2015 and 2014. 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, 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, 2015, 2014 and 2013 is presented below.

	Fiscal Year Ended September 30
	2015			2014			2013
	(In thousands)
Commodity contracts	$	10,311		$	(792	)	$	2,165
Fair value adjustment for natural gas inventory designated as the hedged item	(9,768		)	2,486			15,938
Total decrease in purchased gas cost	$	543		$	1,694		$	18,103
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	811		$	(919	)	$	(208	)
Timing ineffectiveness	(268		)	2,613			18,311
	$	543		$	1,694		$	18,103

Cash flow hedges table

The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2015, 2014 and 2013 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

	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

	Fiscal Year Ended September 30, 2013
	Regulated Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(10,778	)	$	(10,778	)
Gain arising from ineffective portion of commodity contracts	—			97			97
Total impact on purchased gas cost	—			(10,681		)	(10,681		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(3,489		)	—			(3,489		)
Total impact from cash flow hedges	$	(3,489	)	$	(10,681	)	$	(14,170	)

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, 2015 and 2014. 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
	2015			2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(71,003	)	$	(58,973	)
Forward commodity contracts	(49,211		)	7,904
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	542			2,686
Forward commodity contracts	25,448			(5,102		)
Total other comprehensive income (loss) from hedging, net of tax(1)	$	(94,224	)	$	(53,485	)

⁽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, 2015. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 and fiscal 2014 as those financial instruments have not yet settled.

	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2016	$	(347	)	$	(19,484	)	$	(19,831	)
2017	(447		)	(5,044		)	(5,491		)
2018	(649		)	(819		)	(1,468		)
2019	(673		)	(85		)	(758		)
2020	(698		)	(5		)	(703		)
Thereafter	(15,836		)	—			(15,836		)
Total(1)	$	(18,650	)	$	(25,437	)	$	(44,087	)

⁽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 INCOME (PARENTHETICALS) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Statement [Abstract]
Discontinued Operation Tax Effect Of Income Loss From Discontinued Operation During Phase Out Period	$ 0	$ 0	$ 3,986
Discontinued Operation, Tax Effect of Income (Loss) from Disposal of Discontinued Operation	$ 0	$ 0	$ 2,909

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 315,075	$ 289,817	$ 243,194
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of discontinued operations	0	0	(8,203)
Depreciation and amortization:
Charged to depreciation and amortization	274,796	253,987	236,928
Charged to other accounts	1,209	969	679
Deferred income taxes	192,886	189,952	141,336
Stock-based compensation	27,491	25,531	17,814
Debt financing costs	5,922	9,409	8,480
Other	(850)	(428)	(2,887)
Changes in assets and liabilities:
(Increase) decreased in accounts receivable	48,240	(41,408)	(73,669)
Decrease in gas stored underground	33,234	(31,996)	31,979
(Increase) decrease in other current assets	(11,951)	(24,411)	15,644
(Increase) decrease in deferred charges and other assets	58,256	30,662	111,069
Increase (decrease) in account payable and accrued liabilities	(52,660)	55,041	31,912
Increase (decrease) in other current liabilities	896	2,413	(44,491)
Increase (decrease) in deferred credits and other liabilities	(56,025)	(19,552)	(96,658)
Net cash provided by operating activities	836,519	739,986	613,127
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures	(975,132)	(835,251)	(845,033)
Proceeds from the sale of discontinued operations	0	0	153,023
Other, net	377	(2,325)	(4,904)
Net cash used in investing activities	(974,755)	(837,576)	(696,914)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt	254,780	(165,865)	(208,070)
Net proceeds from issuance of long-term debt	493,538	0	493,793
Net proceeds from equity offering	0	390,205	0
Settlement of Treasury lock agreement	13,364	0	(66,626)
Repayment of long-term debt	(500,000)	0	(131)
Cash dividends paid	(160,018)	(146,248)	(128,115)
Repurchase of equity awards	(7,985)	(8,717)	(5,150)
Issuance of common stock	30,952	4,274	46
Net cash provided by (used in) financing activities	124,631	73,649	85,747
Net increase (decrease) in cash and cash equivalents	(13,605)	(23,941)	1,960
Cash and cash equivalents at beginning of period	42,258	66,199	64,239
Cash and cash equivalents at end of period	28,653	42,258	66,199
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest	151,334	156,606	148,461
Income taxes	$ 1,802	$ (610)	$ 10,008

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Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2016	$ 16,475
2017	16,639
2018	16,490
2019	15,207
2020	14,251
Operating Leases, Thereafter	61,651
Total Operating Lease Payments	140,713
Lease and Rental Expense	$ 32,500	$ 31,700	$ 32,400
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	19 years

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Accumulated Other Comprehensive Income Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance	$ 3,086,232	$ 2,580,409	$ 2,359,243
Net current-period other comprehensive income (loss)	(96,937)	(51,271)	86,485
Shareholders' equity, ending balance	3,194,797	3,086,232	2,580,409
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance	7,662	5,448
Other comprehensive income before reclassifications	(2,173)	3,009
Amounts reclassified from accumulated other comprehensive income	(540)	(795)
Net current-period other comprehensive income (loss)	(2,713)	2,214
Shareholders' equity, ending balance	4,949	7,662	5,448
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	(18,381)	37,906
Other comprehensive income before reclassifications	(71,003)	(58,973)
Amounts reclassified from accumulated other comprehensive income	542	2,686
Net current-period other comprehensive income (loss)	(70,461)	(56,287)
Shareholders' equity, ending balance	(88,842)	(18,381)	37,906
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	(1,674)	(4,476)
Other comprehensive income before reclassifications	(49,211)	7,904
Amounts reclassified from accumulated other comprehensive income	25,448	(5,102)
Net current-period other comprehensive income (loss)	(23,763)	2,802
Shareholders' equity, ending balance	(25,437)	(1,674)	(4,476)
Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shareholders' equity, beginning balance	(12,393)	38,878	(47,607)
Other comprehensive income before reclassifications	(122,387)	(48,060)
Amounts reclassified from accumulated other comprehensive income	25,450	(3,211)
Net current-period other comprehensive income (loss)	(96,937)	(51,271)	86,485
Shareholders' equity, ending balance	$ (109,330)	$ (12,393)	$ 38,878

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Selected Quarterly Financial Data

12 Months Ended

Sep. 30, 2015

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 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

	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2014:
Operating revenues
Regulated distribution	$	843,865		$	1,290,960		$	517,707		$	409,014
Regulated pipeline	71,341			73,615			87,189			86,314
Nonregulated	436,431			758,215			465,485			407,161
Intersegment eliminations	(107,779		)	(157,936		)	(127,211		)	(113,455		)
	1,243,858			1,964,854			943,170			789,034
Gross profit	388,957			496,277			359,533			337,659
Operating income	170,720			250,080			106,605			83,944
Net income	87,016			133,367			45,721			23,713
Net income per share — basic	$	0.95		$	1.38		$	0.45		$	0.23
Net income per share — diluted	$	0.95		$	1.38		$	0.45		$	0.23

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Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues by Segment [Line Items]
Operating revenues	$ 656,902	$ 686,401	$ 1,540,068	$ 1,258,765	$ 789,034	$ 943,170	$ 1,964,854	$ 1,243,858	$ 4,142,136	$ 4,940,916	$ 3,875,460
Selected Quarterly Financial Information [Abstract]
Gross profit	354,321	381,673	520,738	423,285	337,659	359,533	496,277	388,957	1,680,017	1,582,426	1,412,050
Operating income	75,853	117,607	250,210	187,725	83,944	106,605	250,080	170,720	631,395	611,349	501,879
Income (loss) from continuing operations									315,075	289,817	230,698
Income from discontinued operations, net of tax									0	0	7,202
Gain (loss) on sale of discontinued operations, net of tax									0	0	5,294
Net income	$ 23,515	$ 56,281	$ 137,684	$ 97,595	$ 23,713	$ 45,721	$ 133,367	$ 87,016	$ 315,075	$ 289,817	$ 243,194
Income per share from continuing operations - basic (usd per share)									$ 3.09	$ 2.96	$ 2.54
Income per share from discontinued operations - basic (usd per share)									0.00	0.00	0.14
Net income per share — basic (usd per share)	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	3.09	2.96	2.68
Income per share from continuing operations - diluted (usd per share)									3.09	2.96	2.50
Income per share from discontinued operations - diluted (usd per share)									0.00	0.00	0.14
Net income per share — diluted (usd per share)	$ 0.23	$ 0.55	$ 1.35	$ 0.96	$ 0.23	$ 0.45	$ 1.38	$ 0.95	$ 3.09	$ 2.96	$ 2.64
Regulated Distribution Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	$ 369,656	$ 416,794	$ 1,130,613	$ 846,772	$ 409,014	$ 517,707	$ 1,290,960	$ 843,865	$ 2,763,835	$ 3,061,546	$ 2,399,493
Selected Quarterly Financial Information [Abstract]
Gross profit									1,237,577	1,176,515	1,081,236
Operating income									420,149	384,568	343,093
Income (loss) from continuing operations											150,856
Income from discontinued operations, net of tax											7,202
Gain (loss) on sale of discontinued operations, net of tax											5,649
Net income									204,813	171,585	163,707
Regulated Pipeline Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	97,807	97,008	91,730	83,567	86,314	87,189	73,615	71,341	370,112	318,459	268,900
Selected Quarterly Financial Information [Abstract]
Gross profit									370,112	318,459	268,900
Operating income									181,267	172,819	139,853
Income (loss) from continuing operations											68,260
Income from discontinued operations, net of tax											0
Gain (loss) on sale of discontinued operations, net of tax											0
Net income									94,662	86,191	68,260
Nonregulated Segment [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	292,830	278,769	438,322	462,288	407,161	465,485	758,215	436,431	1,472,209	2,067,292	1,587,914
Selected Quarterly Financial Information [Abstract]
Gross profit									72,860	87,955	63,331
Operating income									29,979	53,962	18,927
Income (loss) from continuing operations											11,582
Income from discontinued operations, net of tax											0
Gain (loss) on sale of discontinued operations, net of tax											(355)
Net income									15,600	32,041	11,227
Intersegment Elimination [Member]
Operating Revenues by Segment [Line Items]
Operating revenues	$ (103,391)	$ (106,170)	$ (120,597)	$ (133,862)	$ (113,455)	$ (127,211)	$ (157,936)	$ (107,779)	(464,020)	(506,381)	(380,847)
Selected Quarterly Financial Information [Abstract]
Gross profit									(532)	(503)	(1,417)
Operating income									0	0	6
Income (loss) from continuing operations											0
Income from discontinued operations, net of tax											0
Gain (loss) on sale of discontinued operations, net of tax											0
Net income									$ 0	$ 0	$ 0

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Leases (Table)

12 Months Ended

Sep. 30, 2015

Leases [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

The related future minimum lease payments at September 30, 2015 were as follows:

	Operating Leases
	(In thousands)
2016	$	16,475
2017	16,639
2018	16,490
2019	15,207
2020	14,251
Thereafter	61,651
Total minimum lease payments	$	140,713

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Commitments and Contingencies

12 Months Ended

Sep. 30, 2015

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 distribution hubs. At September 30, 2015, we were committed to purchase 36.6 Bcf within one year and 26.8 Bcf within one to three years under indexed contracts. Purchases under these contracts totaled $113.3 million, $140.9 million and $89.0 million for 2015, 2014, 2013.

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, 2015, we were committed to purchase 101.9 Bcf within one year, 16.0 Bcf within one to three years and 0.5 Bcf after three years under indexed contracts. We are committed to purchase 3.0 Bcf within one year under fixed price contracts with prices ranging from $2.32 to $3.23 per Mcf. Purchases under these contracts totaled $1,141.3 million, $1,687.5 million and $1,246.1 million for 2015, 2014 and 2013.

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, 2015 are as follows (in thousands):

2016	$	7,843
2017	3,522
2018	1,966
2019	426
2020	398
Thereafter	1,101
	$	15,256

Regulatory Matters

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 related reporting and disclosure obligations.