ATMOS ENERGY CORP Form 10-K Annual Report Filed 2013-11-13

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended September 30, 2013

¨ 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 Class on 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 þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2013, was $3,816,801,052.

As of November 8, 2013, the registrant had 90,912,251 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 5, 2014 are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS




		Page
Glossary of Key Terms		3

	Part I
Item 1.	Business	4
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	18
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	103
Item 9A.	Controls and Procedures	103
Item 9B.	Other Information	105

	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	105
Item 11.	Executive Compensation	106
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	106
Item 13.	Certain Relationships and Related Transactions, and Director Independence	106
Item 14.	Principal Accountant Fees and Services	106

	Part IV
Item 15.	Exhibits and Financial Statement Schedules	108

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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
ISRS	Infrastructure System Replacement 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 440 of the 441 incorporated cities, 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 Services, 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 transmission and storage 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.

Over the last two fiscal years, we have sold our natural gas distribution operations in four states to streamline our regulated operations. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers, and in August 2012, we completed the sale of our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers.

Through our nonregulated businesses, we 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.

Our overall strategy is to:


•	deliver superior shareholder value,


•	improve the quality and consistency of earnings growth, while operating our business exceptionally well


•	invest in our people and infrastructure


•	enhance our culture.

We have delivered excellent shareholder value by growing our earnings and increasing our dividends for over 25 consecutive years. Over the last five 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 natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,


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


•	The nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

These operating segments are described in greater detail below.

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Natural Gas Distribution Segment Overview

Our natural gas 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. See Note 16 in the consolidated financial statements for a description of the completed sales of our Missouri, Illinois, Iowa and Georgia service areas. 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, 2013, we held 998 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. We believe that we will 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	1,560,409
Kentucky/Mid-States	Kentucky	230	179,708
	Tennessee		123,590
	Virginia		20,358
Louisiana	Louisiana	300	342,187
West Texas	Amarillo, Lubbock, Midland	80	293,802
Mississippi	Mississippi	110	255,730
Colorado-Kansas	Colorado	170	99,654
	Kansas		136,542

Our natural gas distribution business is a seasonal business. Gas sales to residential and commercial customers are greater during the winter months than during the remainder of the year. The volumes of gas sales during the winter months will vary with the temperatures during these months. Historically, this generally has resulted in higher operating revenues and net income during the period from October through March of each fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal year. However, rate design changes implemented during the first quarter of fiscal 2013 in our Mid-Tex and West Texas Divisions should change this trend. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design allows our rates to be more closely aligned with the natural gas distribution industry standard rate design. In addition, we anticipate these divisions, which represent approximately 50 percent of the operating income for our natural gas distribution segment, will earn their operating income more ratably over the fiscal year as they are now less dependent on customer consumption.

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 natural gas distribution operating revenues fluctuate with the cost of gas that we purchase, natural gas 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 introduced performance-based ratemaking adjustments to provide incentives to natural gas 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.

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Regulatory authorities have approved weather normalization adjustments (WNA) for approximately 97 percent of residential and commercial margins in our service areas as a part of our rates. WNA minimizes the effect of weather that is above or below normal by allowing us to increase customers’ bills to offset the effect of lower gas usage when weather is warmer than normal and decrease customers’ bills to offset the effect of higher gas usage when weather is colder than normal.

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



Division	Jurisdiction	Effective Date of Last Rate/GRIP Action	Rate Base (thousands)⁽¹⁾	Authorized Rate of Return⁽¹⁾	Authorized Debt/ Equity Ratio	Authorized Return on Equity⁽¹⁾
Atmos Pipeline — Texas	Texas	05/01/2011	$807,733	9.36%	50/50	11.80%
Atmos Pipeline — Texas — GRIP	Texas	05/07/2013	979,324	9.36%	N/A	11.80%
Colorado-Kansas	Colorado	01/04/2010	86,189	8.57%	50/50	10.25%
	Kansas	09/01/2012	160,075	(2)	(2)	(2)
Kentucky/Mid-States	Kentucky	06/01/2010	221,340⁽³⁾	(2)	(2)	(2)
	Tennessee	11/08/2012	201,359	8.28%	49/51	10.10%
	Virginia	11/23/2009	36,861	8.48%	51/49	9.50% - 10.50%
Louisiana	Trans LA	04/01/2013	105,527	7.94%	52/48	10.00% - 10.80%
	LGS	07/01/2013	298,642	8.08%	52/48	10.40%
Mid-Tex Cities	Texas	12/04/2012	1,512,986⁽⁴⁾	8.57%	48/52	10.50%
Mid-Tex — Dallas	Texas	06/01/2013	1,619,429⁽⁴⁾	8.35%	48/52	10.10%
Mississippi	Mississippi	11/01/2012	287,646	8.04%	49/51	9.64%
West Texas⁽⁵⁾	Texas	10/01/2012	271,590	(2)	(2)	(2)



Division	Jurisdiction	Bad Debt Rider⁽⁶⁾	Annual Rate Mechanism	Infrastructure Mechanism	Performance- Based Rate Program⁽⁷⁾	WNA Period
Atmos Pipeline — Texas	Texas	No	No	Yes	N/A	N/A
Colorado-Kansas	Colorado	Yes⁽⁸⁾	No	Yes	No	N/A
	Kansas	Yes	No	Yes	No	October-May
Kentucky/Mid-States	Kentucky	Yes	No	Yes	Yes	November-April
	Tennessee	Yes	No	No	Yes	October-April
	Virginia	Yes	No	Yes	No	January-December
Louisiana	Trans LA	No	Yes	No	No	December-March
	LGS	No	Yes	No	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	No	Yes	November-April
West Texas⁽⁵⁾	Texas	Yes	No	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⁾	A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.


⁽³⁾	Kentucky rate base consists of $184.7 million included in the June 2010 rate case and $36.6 million included in the October 2012 PRP surcharge. A total of $36.6 million of the Kentucky rate base amount was granted in the annual PRP filing with an effective date of October 1, 2012, an authorized rate of return of 8.74 percent and an authorized return on equity of 10.50 percent.


⁽⁴⁾	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.

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⁽⁵⁾	On October 2, 2012, a rate case settlement was approved by the Texas Railroad Commission (RRC) that combined the former Amarillo, Lubbock and West Texas jurisdictions into a single “West Texas” jurisdiction.


⁽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 natural gas 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 Commission Staff have agreed to roll the recovery of the gas portion of uncollectible accounts back into base rates as part of the current rate proceeding.

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 2013 were Anadarko Energy Services Company, BP Energy Company, ConocoPhillips Company, Devon Gas Services, L.P., Enterprise Products Operating LLC, Iberdrola Energy Services, LLC, Sequent Energy Management, L.P., Targa Gas Marketing LLC, Tenaska Marketing Ventures, Texla Energy Management, Inc. and Atmos Energy Marketing, LLC, our natural gas marketing subsidiary.

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 natural gas distribution operations in fiscal 2013 was on January 15, 2013, when sales to customers reached approximately 3.1 Bcf.

Currently, our natural gas 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 Transmission and Storage Segment Overview

Our regulated transmission and storage segment consists of the regulated 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 Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. It 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 in the pipeline industry including parking and lending arrangements and sales of excess gas. This segment represents approximately 30 percent of our consolidated operations.

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

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Nonregulated Segment Overview

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


•	Annual ratemaking mechanisms in place in four states that provide for an annual rate review and adjustment to rates for approximately 69 percent of our natural gas distribution gross margin.


•	Accelerated recovery of capital for approximately 74 percent of our natural gas distribution gross margin.


•	Enhanced rate design 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 natural gas distribution gross margin.


•	The ability to recover the gas cost portion of bad debts for approximately 75 percent of our natural gas distribution gross margin.

Although substantial progress has been made in recent years by improving rate design across Atmos Energy’s operating areas, we will continue to seek improvements in rate design to address cost variations that are related to pass-through energy costs beyond our control. Further, potential changes in federal energy policy 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, 2013, 2012 and 2011 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 $98.1 million, $30.7 million and $72.4 million, became effective in fiscal 2013, 2012 and 2011, as summarized below:



	Annual Increase to Operating Income For the Fiscal Year Ended September 30
Rate Action	2013		2012		2011
	(In thousands)
Infrastructure programs	$	30,936	$	19,172	$	15,033
Annual rate filing mechanisms	9,152		7,044		35,216
Rate case filings	56,700		4,309		20,502
Other ratemaking activity	1,322		167		1,675
	$	98,110	$	30,692	$	72,426

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Additionally, the following ratemaking efforts were initiated during fiscal 2013 but had not been completed as of September 30, 2013:




Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)

Colorado-Kansas	Rate Case⁽¹⁾	Colorado	$	10,891
Kentucky/Mid-States	Rate Case	Kentucky	13,133
	PRP⁽²⁾	Kentucky	2,493
	PRP⁽²⁾	Virginia	213
Mid-Tex Division	GRIP⁽³⁾	Railroad Commission - Environs	768
	RRM⁽⁴⁾	Mid-Tex Cities	17,077
Mississippi	Stable Rate Filing⁽⁵⁾	Mississippi	—
			$	44,575


⁽¹⁾	This rate case seeks a multi-year step increase in annual operating income of $4.5 million on January 1, 2014, $2.9 million on July 1, 2014 and $3.5 million on July 1, 2015.


⁽²⁾	The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure. The Kentucky and Virginia PRPs were implemented on October 1, 2013.


⁽³⁾	The Gas Reliability Infrastructure Program (GRIP) surcharge relates to replacing aging infrastructure as well as other changes in net plant. The surcharge is calculated on a system-wide basis, but is only filed with the Railroad Commission for unincorporated areas served by the Mid-Tex Division.


⁽⁴⁾	The Rate Review Mechanism (RRM) is an annual rate filing mechanism that allows us to refresh our rates on a periodic basis without filing a formal rate case. The current RRM program was approved by the Mid-Tex Cities in the summer of 2013. The first filing under the mechanism was made in July of 2013 and has been settled for $12.5 million to be implemented on November 1, 2013.


⁽⁵⁾	The Stable Rate Filing shows no deficiency, thus no change in operating income is anticipated from the current year filing.

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Our recent ratemaking activity is discussed in greater detail below.

Infrastructure Programs

As discussed above in “Natural Gas Distribution Segment Overview” and “Regulated Transmission and Storage Segment Overview,” infrastructure programs such as GRIP allow our regulated divisions the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. We currently have infrastructure programs in Texas, Kansas, Kentucky and Virginia. The following table summarizes our infrastructure program filings with effective dates during the fiscal years ended September 30, 2013, 2012 and 2011:



Division	Period End	Incremental Net Utility Plant Investment		Increase in Annual Operating Income		Effective Date
		(In thousands)		(In thousands)
2013 Infrastructure Programs:
Atmos Pipeline — Texas	12/2012	$	156,440	$	26,730	05/07/2013
Colorado-Kansas — Kansas	09/2012	5,376		601		01/09/2013
Kentucky/Mid-States — Georgia⁽¹⁾⁽²⁾	09/2011	6,519		1,079		10/01/2012
Kentucky/Mid-States — Kentucky⁽²⁾	09/2013	19,296		2,425		10/01/2012
Kentucky/Mid-States — Virginia	09/2013	756		101		10/01/2012
Total 2013 Infrastructure Programs		$	188,387	$	30,936
2012 Infrastructure Programs:
Mid-Tex Unincorporated (Environs)⁽³⁾	12/2011	$	145,671	$	744	06/26/2012
Atmos Pipeline — Texas	12/2011	87,210		14,684		04/10/2012
Kentucky/Mid-States — Georgia⁽¹⁾⁽²⁾	09/2010	7,160		1,215		10/01/2011
Kentucky/Mid-States — Kentucky⁽²⁾	09/2012	17,347		2,529		10/01/2011
Total 2012 Infrastructure Programs		$	257,388	$	19,172
2011 Infrastructure Programs:
Atmos Pipeline — Texas	12/2010	$	72,980	$	12,605	07/26/2011
Mid-Tex/Environs	12/2010	107,840		576		06/27/2011
West Texas/Lubbock & WT Cities Environs	12/2010	17,677		343		06/01/2011
Kentucky/Mid-States — Kentucky ⁽²⁾	09/2011	3,329		468		06/01/2011
Kentucky/Mid-States — Missouri⁽⁴⁾	09/2010	2,367		277		02/14/2011
Kentucky/Mid-States — Georgia⁽¹⁾⁽²⁾	09/2009	5,359		764		10/01/2010
Total 2011 Infrastructure Programs		$	209,552	$	15,033


⁽¹⁾	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.


⁽²⁾	The Pipeline Replacement Program (PRP) surcharge relates to a long-term program to replace aging infrastructure.


⁽³⁾	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.


⁽⁴⁾	Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

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Annual Rate Filing Mechanisms

As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in a portion of our Texas divisions. These mechanisms are referred to as Dallas annual rate review (DARR) and rate review mechanisms (RRM) in our Mid-Tex Division, stable rate filings in the Mississippi Division and the rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms:



Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
			(In thousands)
2013 Filings:
Louisiana	LGS	12/31/2012	$	908		07/01/2013
Mid-Tex	City of Dallas	9/30/2012	1,800			06/01/2013
Louisiana	TransLa	9/30/2012	2,260			04/01/2013
Kentucky/Mid-States	Georgia⁽¹⁾	9/30/2013	743			02/01/2013
Mississippi	Mississippi	6/30/2012	3,441			11/01/2012
Total 2013 Filings			$	9,152
2012 Filings:
Louisiana	LGS	12/31/2011	$	2,324		07/01/2012
Mid-Tex	Dallas	9/30/2011	1,204			06/01/2012
Louisiana	Trans La	9/30/2011	11			04/01/2012
Kentucky/Mid-States	Georgia⁽¹⁾	9/30/2011	(818		)	02/01/2012
Mississippi	Mississippi	6/30/2011	4,323			01/11/2012
Total 2012 Filings			$	7,044
2011 Filings:
Mid-Tex	Mid-Tex Cities	12/31/2010	$	5,126		09/27/2011
Mid-Tex	Dallas	12/31/2010	1,084			09/27/2011
West Texas	Lubbock	12/31/2010	319			09/08/2011
West Texas	Amarillo	12/31/2010	(492		)	08/01/2011
Louisiana	LGS	12/31/2010	4,109			07/01/2011
Mid-Tex	Dallas	12/31/2010	1,598			07/01/2011
Louisiana	TransLa	9/30/2010	350			04/01/2011
Mid-Tex	Mid-Tex Cities	12/31/2009	23,122			10/01/2010
Total 2011 Filings			$	35,216


⁽¹⁾	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.

From 2008 through fiscal 2011, the Mid-Tex Division had an annual rate review mechanism (RRM) for approximately 80 percent of its customers, which allowed it to update rates annually without the necessity of filing a general rate case. In fiscal 2013, a new RRM was approved for these customers.

Since June 2011, the Mid-Tex Division has operated under a Dallas Annual Rate Review Mechanism (DARR) that provides the ability for it to annually update rates for its City of Dallas customers without the necessity of filing a general rate case. The first rates were implemented under the DARR in June 2012.

During fiscal 2011, the RRC’s Division of Public Safety issued a new rule requiring natural gas distribution companies with operations in Texas to develop and implement a risk-based program for the renewal or replacement of distribution facilities, including steel service lines. The rule allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule until the expenses are included in rates, including the recording of interest on the deferred expenses.

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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)
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
2012 Rate Case Filings:
Colorado-Kansas	Kansas	$	3,764	09/01/2012
West Texas — Environs	Texas	545		11/08/2011
Total 2012 Rate Case Filings		$	4,309
2011 Rate Case Filings:
West Texas — Amarillo Environs	Texas	$	78	07/26/2011
Atmos Pipeline — Texas	Texas	20,424		05/01/2011
Total 2011 Rate Case Filings		$	20,502

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2013, 2012 and 2011:



Division	Jurisdiction	Rate Activity	Increase in Annual Operating Income		Effective Date
			(In thousands)
2013 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	$	1,322	02/01/2013
Total 2013 Other Rate Activity			$	1,322
2012 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	$	167	01/14/2012
Total 2012 Other Rate Activity			$	167
2011 Other Rate Activity:
West Texas	Triangle	Special Contract	$	641	07/01/2011
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	685		01/01/2011
Colorado-Kansas	Colorado	AMI⁽²⁾	349		12/01/2010
Total 2011 Other Rate Activity			$	1,675


⁽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.


⁽²⁾	Automated Meter Infrastructure (AMI) relates to a pilot program in the Weld County area of our Colorado service area.

Other Regulation

Each of our natural gas distribution divisions and our regulated transmission and storage 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 distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time

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

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, 2013, we had 4,720 employees, consisting of 4,611 employees in our regulated operations and 109 employees in our nonregulated operations.

Available Information

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

Shareholder Relations

Atmos Energy Corporation

P.O. Box 650205

Dallas, Texas 75265-0205

972-855-3729

Corporate Governance

In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer during fiscal 2013, Kim R. Cocklin, certified to the New York Stock Exchange that he was not aware of any

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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 Services, 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 natural gas distribution and regulated transmission and storage segments are subject to regulatory oversight from various state and local regulatory authorities in the eight states that we serve. 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, a regulated entity often needs 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. 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.” 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.

The continuation of recent economic conditions could adversely affect our customers and negatively impact our financial results.

The slowdown in the U.S. economy in the last several years, together with increased mortgage defaults and significant decreases in the values of homes and investment assets, has adversely affected the financial resources of many domestic households. It is unclear whether the administrative and legislative responses to these conditions will be successful in continuing to improve economic conditions, including the continued lowering of current high unemployment rates across the U.S. As a result, our customers may seek to use even less gas and it may become more difficult for them to pay their gas bills. This may slow collections and lead to higher than normal levels of accounts receivable. This in turn could increase our financing requirements and bad debt expense. Additionally, our industrial customers may seek alternative energy sources, which could result in lower sales volumes.

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

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 natural gas 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.

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 market liquidity, commodity price volatility caused by market supply and demand dynamics and counterparty creditworthiness and interest rate risk. Our regulated operations are generally insulated from commodity price risk through its purchased gas cost mechanisms. 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.

Although our nonregulated operations represent approximately five percent of our consolidated results, commodity price volatility experienced in this business segment could lead to some 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. Any significant tightening of the credit markets could cause more of our counterparties to fail to perform than expected. In addition, adverse changes in the creditworthiness of our counterparties could limit the level of trading activities with these parties and increase the risk that these parties may not perform under a contract. These circumstances could also increase our capital requirements.

Although we manage our business to maintain no open positions related to our physical storage, there are times when limited net open positions may occur on a short-term basis. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner before the open positions can be closed. The determination of our net open position as of the end of any particular trading day 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 such day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. Further, if the local physical markets do not move consistently with the NYMEX futures market upon which most of our commodity derivative financial instruments are valued, we could experience increased volatility in the financial results of our nonregulated segment.

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

Over 50 percent of our natural gas distribution customers and most of our pipeline and storage 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 and regulatory decisions by state and local regulatory authorities in Texas.

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Our operations are subject to increased competition.

In residential and commercial customer markets, our natural gas 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 transmission and storage operations historically have faced limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, in the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

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

Adverse weather conditions could affect our operations or financial results.

We have weather-normalized rates for over 95 percent of our residential and commercial meters in our natural gas 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 natural gas distribution and regulated transmission and storage 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 regulated transmission and storage operations.

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

We must continually build additional capacity in our natural gas distribution system to enable us to serve any growth in the number of our customers. The cost of adding this capacity may be affected by a number of factors, including the general state of the economy and weather. In addition, although we should ultimately recover the cost of the expenditures through rates, we must make significant capital expenditures to comply with rules issued by the RRC’s Division of Public Safety that require natural gas distribution companies to develop and implement risk-based programs for the renewal or replacement of distribution facilities, including steel service lines. Our cash flows from operations generally are sufficient to supply funding for all our capital expenditures, including the financing of the costs of new construction along with capital expenditures necessary to maintain our existing natural gas system. Due to the timing of these cash flows and capital expenditures, we often must fund at least a portion of these costs through borrowing funds from third-party lenders, the cost and availability of which is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit our ability to connect new customers to our system due to constraints on 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 and 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. Although the HCR is not expected to have a direct material impact when a number of its more significant provisions become effective in 2014, the impact of costs incurred by the insurance industry arising from the implementation of HCR on 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 could increase the costs of our

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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; and (ii) various actuarial calculations and assumptions, which may differ materially from actual results due primarily to changing market and economic conditions and higher or lower withdrawal rates.

The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, depending on the timing of the recovery, if any, of such costs through our rates.

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 are facing 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 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.

Our business may be subject in the future to additional regulatory and financial risks associated with global warming and climate change.

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

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

Our natural gas distribution and pipeline and storage 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

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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 insurance, 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. We use such systems to manage our natural gas 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.

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 be 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, 2013, in our natural gas distribution segment, we owned an aggregate of 67,146 miles of underground distribution and transmission mains throughout our gas 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 transmission and storage segment we owned 5,628 miles of gas transmission and gathering lines as well as 110 miles of gas transmission and gathering lines through our nonregulated segment.

Storage Assets

We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities at September 30, 2013:

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State	Usable Capacity (Mcf)	Cushion Gas (Mcf)⁽¹⁾	Total Capacity (Mcf)	Maximum Daily Delivery Capability (Mcf)
Natural Gas 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	2,211,894	2,442,917	4,654,811	48,000
Total	9,893,590	11,065,200	20,958,790	198,100
Regulated Transmission and Storage Segment — Texas	46,143,226	15,878,025	62,021,251	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	59,914,299	30,484,198	90,398,497	1,556,600


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

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Additionally, we contract for storage service in underground storage facilities on many of the interstate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2013:



Segment	Division/Company	Maximum Storage Quantity (MMBtu)	Maximum Daily Withdrawal Quantity (MDWQ)⁽¹⁾
Natural Gas Distribution Segment
	Colorado-Kansas Division	4,261,909	108,489
	Kentucky/Mid-States Division	11,081,603	344,706
	Louisiana Division	2,736,539	161,393
	Mid-Tex Division	1,000,000	75,000
	Mississippi Division	3,695,429	162,402
	West Texas Division	3,375,000	106,000
Total		26,150,480	957,990
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		35,851,349	1,276,434


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

Offices

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



ITEM 3.	Legal Proceedings.

See Note 10 to the consolidated financial statements.



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 2013 and 2012 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:

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	Fiscal 2013						Fiscal 2012
	High		Low		Dividends Paid		High		Low		Dividends Paid
Quarter ended:
December 31	$	36.86	$	33.20	$	0.35	$	35.40	$	30.97	$	0.345
March 31	42.69		35.11		0.35		33.15		30.60		0.345
June 30	44.87		38.59		0.35		35.07		30.91		0.345
September 30	45.19		39.40		0.35		36.94		34.94		0.345
					$	1.40					$	1.38

Dividends are payable at the discretion of our Board of Directors out of legally available funds. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. The number of record holders of our common stock on October 31, 2013 was 16,746. 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 2013 that were not registered under the Securities Act of 1933, as amended.

Performance Graph

The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the S&P 500 Stock Index and the cumulative total return of a customized peer company group, the Comparison Company Index. The Comparison Company Index is comprised of natural gas distribution companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2008 in our common stock, the S&P 500 Index and in the common stock of the companies in the Comparison Company Index, as well as a reinvestment of dividends paid on such investments throughout the period.

Comparison of Five-Year Cumulative Total Return

among Atmos Energy Corporation, S&P 500 Index

and Comparison Company Index

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	Cumulative Total Return
	9/30/2008	9/30/2009	9/30/2010	9/30/2011	9/30/2012	9/30/2013
Atmos Energy Corporation	100.00	111.68	121.63	140.75	161.81	199.54
S&P 500	100.00	93.09	102.55	103.72	135.05	161.17
Peer Group	100.00	98.11	130.03	153.00	184.92	217.15

The Comparison Company Index contains 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 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.

The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2013.



	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	7,930	$	25.96	1,403,439
Total equity compensation plans approved by security holders	7,930	25.96		1,403,439
Equity compensation plans not approved by security holders	—	—		—
Total	7,930	$	25.96	1,403,439

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 2013. At September 30, 2013, 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
	2013		2012⁽¹⁾		2011⁽¹⁾		2010		2009⁽¹⁾
	(In thousands, except per share data)
Results of Operations
Operating revenues	$	3,886,257	$	3,438,483	$	4,286,435	$	4,661,060	$	4,793,248
Gross profit	$	1,412,050	$	1,323,739	$	1,300,820	$	1,314,136	$	1,297,682
Income from continuing operations	$	230,698	$	192,196	$	189,588	$	189,851	$	175,026
Net income	$	243,194	$	216,717	$	207,601	$	205,839	$	190,978
Diluted income per share from continuing operations	$	2.50	$	2.10	$	2.07	$	2.03	$	1.90
Diluted net income per share	$	2.64	$	2.37	$	2.27	$	2.20	$	2.07
Cash dividends declared per share	$	1.40	$	1.38	$	1.36	$	1.34	$	1.32
Financial Condition
Net property, plant and equipment⁽²⁾	$	6,030,655	$	5,475,604	$	5,147,918	$	4,793,075	$	4,439,103
Total assets	$	7,940,401	$	7,495,675	$	7,282,871	$	6,763,791	$	6,367,083
Capitalization:
Shareholders’ equity	$	2,580,409	$	2,359,243	$	2,255,421	$	2,178,348	$	2,176,761
Long-term debt (excluding current maturities)	2,455,671		1,956,305		2,206,117		1,809,551		2,169,400
Total capitalization	$	5,036,080	$	4,315,548	$	4,461,538	$	3,987,899	$	4,346,161

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⁽¹⁾	Financial results for fiscal years 2012, 2011 and 2009 include a $5.3 million, $30.3 million and a $5.4 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.



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 market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our gas distribution business; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the inherent hazards and risks involved in operating our gas distribution business; 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

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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.



Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Regulation	Our natural gas distribution and regulated transmission and storage 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 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 Assessing the probability of the recoverability of deferred costs
Unbilled Revenue	We follow the revenue accrual method of accounting for natural gas 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 Projected timing of future cash disbursements Health care cost experience trends Participant demographic information Actuarial mortality assumptions Impact of legislation
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 fair value of our financial instruments is subject to potentially significant volatility based on numerous considerations including, but not limited to changes in commodity prices, interest rates, maturity and settlement of these financial instruments. 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 is involved in the distribution, marketing and transportation of natural gas. Accordingly, our results of operations are impacted by the demand for natural gas, particularly during the winter heating season, and the volatility of the natural gas markets. Historically, this has generally resulted in higher operating revenues and net income during the period from October through March of each fiscal year and lower operating revenues and either lower net income or net losses during the period from April through September of each fiscal year. As a result of the seasonality of the natural gas industry, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 54 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. However, we believe rate design changes implemented during the first quarter of fiscal 2013 in our Mid-Tex and West Texas Divisions should continue to cause this pattern to change. The rate design approved in these regulatory proceedings includes an increase to the customer base charge and a decrease in the consumption charge applied to customer usage. The effect of this change in rate design should result in a more equal distribution of operating income earned over the fiscal year for approximately 50 percent of our natural gas distribution segment.

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

During fiscal 2013, we earned $243.2 million, or $2.64 per diluted share, which represents a twelve percent increase in net income and diluted net income per share over fiscal 2012, primarily due to recent improvements in rate designs in our natural gas distribution and regulated transmission and storage segments combined with a two percent year-over-year increase in consolidated natural gas distribution throughput due to colder weather.

We completed the sale of our Georgia natural gas distribution operations on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million pursuant to a purchase agreement executed on August 8, 2012. In connection with the sale, we recognized a net of tax gain of $5.3 million. Accordingly, the results of operations for this service area are shown in discontinued operations for all periods presented. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these three service areas was completed in August 2012.

We also took several steps during the year ended September 30, 2013 to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. In August 2013, we amended our revolving credit agreement primarily to increase the term through August 2018. We also terminated Atmos Energy Marketing’s $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.

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On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.

Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2013, 2012 and 2011.



	For the Fiscal Year Ended September 30
	2013			2012			2011
	(In thousands, except per share data)
Operating revenues	$	3,886,257		$	3,438,483		$	4,286,435
Gross profit	1,412,050			1,323,739			1,300,820
Operating expenses	910,171			877,499			874,834
Operating income	501,879			446,240			425,986
Miscellaneous income (expense)	(197		)	(14,644		)	21,184
Interest charges	128,385			141,174			150,763
Income from continuing operations before income taxes	373,297			290,422			296,407
Income tax expense	142,599			98,226			106,819
Income from continuing operations	230,698			192,196			189,588
Income from discontinued operations, net of tax	7,202			18,172			18,013
Gain on sale of discontinued operations, net of tax	5,294			6,349			—
Net income	$	243,194		$	216,717		$	207,601
Diluted net income per share from continuing operations	$	2.50		$	2.10		$	2.07
Diluted net income per share from discontinued operations	$	0.14		$	0.27		$	0.20
Diluted net income per share	$	2.64		$	2.37		$	2.27

Regulated operations contributed 95 percent, 97 percent and 104 percent to our consolidated net income from continuing operations for fiscal years 2013, 2012 and 2011. 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
	2013		2012		2011
	(In thousands)
Natural gas distribution segment	$	150,856	$	123,848	$	144,705
Regulated transmission and storage segment	68,260		63,059		52,415
Nonregulated segment	11,582		5,289		(7,532		)
Net income from continuing operations	230,698		192,196		189,588
Net income from discontinued operations	12,496		24,521		18,013
Net income	$	243,194	$	216,717	$	207,601

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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
	2013		2012		2011
	(In thousands, except per share data)
Regulated operations	$	219,116	$	186,907	$	197,120
Nonregulated operations	11,582		5,289		(7,532		)
Net income from continuing operations	230,698		192,196		189,588
Net income from discontinued operations	12,496		24,521		18,013
Net income	$	243,194	$	216,717	$	207,601
Diluted EPS from continuing regulated operations	$	2.38	$	2.04	$	2.15
Diluted EPS from nonregulated operations	0.12		0.06		(0.08		)
Diluted EPS from continuing operations	2.50		2.10		2.07
Diluted EPS from discontinued operations	0.14		0.27		0.20
Consolidated diluted EPS	$	2.64	$	2.37	$	2.27

We reported net income of $243.2 million, or $2.64 per diluted share for the year ended September 30, 2013, compared with net income of $216.7 million or $2.37 per diluted share in the prior year. Income from continuing operations was $230.7 million, or $2.50 per diluted share compared with $192.2 million, or $2.10 per diluted share in the prior-year period. Income from discontinued operations was $12.5 million or $0.14 per diluted share for the year, which includes the gain on sale of substantially all our assets in Georgia of $5.3 million, compared with $24.5 million or $0.27 per diluted share in the prior year. Unrealized gains in our nonregulated operations during the current year increased net income by $5.3 million or $0.05 per diluted share compared with net losses recorded in the prior year of $5.0 million, or $0.05 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In fiscal 2012, net income included the net positive impact of several one-time items totaling $10.3 million, or $0.11 per diluted share related to the pre-tax items, which are discussed in further detail below. In fiscal 2013, net income includes an $8.2 million ($5.3 million, net of tax), or $0.06 per diluted share, favorable impact related to the gain recorded in association with the April 1, 2013 completion of the sale of our Georgia assets.

We reported net income of $216.7 million, or $2.37 per diluted share for the year ended September 30, 2012, compared with net income of $207.6 million or $2.27 per diluted share in fiscal 2011. Income from continuing operations was $192.2 million, or $2.10 per diluted share compared with $189.6 million, or $2.07 per diluted share in fiscal 2011. Income from discontinued operations was $24.5 million or $0.27 per diluted share for the year, which includes the gain on sale of substantially all our assets in Missouri, Illinois and Iowa of $6.3 million, compared with $18.0 million or $0.20 per diluted share in fiscal 2011. Unrealized losses in our nonregulated operations during fiscal 2012 reduced net income by $5.0 million or $0.05 per diluted share compared with net losses recorded in fiscal 2011 of $6.6 million, or $0.07 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In fiscal 2011, net income included the net positive impact of several one-time items totaling $3.2 million, or $0.03 per diluted share related to pre-tax items. In fiscal 2012, net income included the net positive impact of several one-time items totaling $10.3 million, or $0.11 per diluted share related to the following amounts:


•	$13.6 million positive impact of a deferred tax rate adjustment.


•	$10.0 million ($6.3 million, net of tax) unfavorable impact related to a one-time donation to a donor advised fund.


•	$9.9 million ($6.3 million, net of tax) favorable impact related to the gain recorded in association with the August 1, 2012 completion of the sale of our Iowa, Illinois and Missouri assets.


•	$5.3 million ($3.3 million, net of tax) unfavorable impact related to the noncash impairment of certain assets in our nonregulated business.

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

Natural Gas Distribution Segment

The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates 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

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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. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.

We completed the sale of our Georgia natural gas distribution operations on April 1, 2013 to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million. In connection with the sale, we recognized a net of tax gain of $5.3 million. On August 1, 2012, we completed the sale of substantially all of our natural gas distribution operations in Missouri, Illinois and Iowa.

During fiscal 2013, we completed 13 regulatory proceedings, which should result in a $71.4 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with the utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as they are now less dependent on customer consumption.

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Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2013, 2012 and 2011 are presented below.



	For the Fiscal Year Ended September 30
	2013		2012			2011		2013 vs. 2012			2012 vs. 2011
	(In thousands, unless otherwise noted)
Gross profit	$	1,081,236	$	1,022,743		$	1,017,943	$	58,493		$	4,800
Operating expenses	738,143		718,282			695,855		19,861			22,427
Operating income	343,093		304,461			322,088		38,632			(17,627		)
Miscellaneous income (expense)	2,535		(12,657		)	16,242		15,192			(28,899		)
Interest charges	98,296		110,642			115,740		(12,346		)	(5,098		)
Income from continuing operations before income taxes	247,332		181,162			222,590		66,170			(41,428		)
Income tax expense	96,476		57,314			77,885		39,162			(20,571		)
Income from continuing operations	150,856		123,848			144,705		27,008			(20,857		)
Income from discontinued operations, net of tax	7,202		18,172			18,013		(10,970		)	159
Gain on sale of discontinued operations, net of tax	5,649		6,349			—		(700		)	6,349
Net Income	$	163,707	$	148,369		$	162,718	$	15,338		$	(14,349	)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf	269,162		244,466			275,540		24,696			(31,074		)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf	123,144		128,222			125,812		(5,078		)	2,410
Consolidated natural gas distribution throughput from continuing operations — MMcf	392,306		372,688			401,352		19,618			(28,664		)
Consolidated natural gas distribution throughput from discontinued operations — MMcf	4,731		18,295			22,668		(13,564		)	(4,373		)
Total consolidated natural gas distribution throughput — MMcf	397,037		390,983			424,020		6,054			(33,037		)
Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.43		$	0.47	$	0.03		$	(0.04	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	4.91	$	4.64		$	5.30	$	0.27		$	(0.66	)

Fiscal year ended September 30, 2013 compared with fiscal year ended September 30, 2012

The $58.5 million period-over-period increase in natural gas distribution gross profit primarily reflects the following:


•	$25.7 million increase in our Mid-Tex and West Texas divisions associated with the rate design changes implemented in the fiscal first quarter.


•	$16.1 million increase in rates in our Kentucky/Mid-States, Mississippi, Colorado-Kansas and Louisiana divisions.


•	$7.5 million increase due to colder weather, primarily in the Mississippi, Kentucky/Mid-States and Colorado-Kansas divisions.


•	$5.9 million increase in revenue-related taxes in our Mid-Tex and West Texas service areas primarily due to higher revenues on which the tax is calculated.


•	$4.5 million increase in transportation revenues.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased by $19.9 million, primarily due to the following:


•	$12.2 million increase in employee-related expenses due to lower labor capitalization rates, increased benefit costs and increased variable compensation expense.

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•	$11.7 million increase primarily associated with higher line locate activities, pipeline and right-of-way maintenance spending to improve the safety and reliability of our system.


•	$5.0 million increase in taxes, other than income due to higher revenue-related taxes, as discussed above.


•	$6.8 million increase in bad debt expense primarily attributable to an increase in revenue arising from the rate design changes and the temporary suspension of active customer collection activities following the implementation of a new customer information system during the third fiscal quarter.

These increases were partially offset by:


•	$6.9 million decrease in legal and other administrative costs.


•	$6.4 million decrease in depreciation expense due to new depreciation rates approved in the most recent Mid-Tex rate case that went into effect in January 2013.


•	$2.4 million gain realized on the sale of certain investments.

Miscellaneous income increased $15.2 million, primarily due to the absence of a $10.0 million one-time donation to a donor advised fund in the prior year, the completion of a periodic review of our performance-based ratemaking (PBR) mechanism in our Tennessee service area and the implementation of a new PBR program in our Mississippi Division during fiscal 2013.

Interest charges decreased $12.3 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas.

Fiscal year ended September 30, 2012 compared with fiscal year ended September 30, 2011

The $4.8 million increase in natural gas distribution gross profit was primarily due to a $17.7 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Mississippi, West Texas and Kentucky service areas.

These increases were partially offset by the following:


•	$11.1 million decrease in revenue-related taxes in our Mid-Tex, West Texas and Mississippi service areas, primarily due to lower revenues on which the tax is calculated.


•	$1.6 million decrease due to an eight percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather in the current year compared to fiscal 2011 in most of our service areas.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income increased $22.4 million primarily due to the following:


•	$11.2 million increase in legal costs, primarily due to settlements.


•	$10.6 million increase in employee-related costs.


•	$8.4 million increase in depreciation and amortization associated with an increase in our net plant as a result of our capital investments in fiscal 2011.


•	$2.6 million increase in software maintenance costs.

These increases were partially offset by the following:


•	$6.8 million decrease in operating expenses due to increased capital spending and warmer weather allowing us time to complete more capital work than in the prior year.


•	$2.9 million decrease due to the establishment of regulatory assets for pension and postretirement costs.

Miscellaneous income decreased $28.9 million primarily due to the absence of a $21.8 million pre-tax gain recognized in fiscal 2011 as a result of unwinding two Treasury locks ($13.6 million, net of tax) and a $10.0 million one-time donation to a donor advised fund in fiscal 2012.

Interest charges decreased $5.1 million compared to the prior year due primarily to the prepayment of our 5.125% $250 million senior notes in the fourth quarter of fiscal 2012, refinancing long-term debt at reduced interest rates and reducing commitment fees from decreasing the number of credit facilities and extending the length of their terms in fiscal 2011.

Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $11.3 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated

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analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.

The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the fiscal years ended September 30, 2013, 2012 and 2011. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.



	For the Fiscal Year Ended September 30
	2013		2012		2011		2013 vs. 2012		2012 vs. 2011
	(In thousands)
Mid-Tex	$	158,900	$	142,755	$	144,204	$	16,145	$	(1,449	)
Kentucky/Mid-States	46,164		32,185		37,593		13,979		(5,408		)
Louisiana	52,125		48,958		50,442		3,167		(1,484		)
West Texas	28,085		27,875		29,686		210		(1,811		)
Mississippi	29,112		27,369		26,338		1,743		1,031
Colorado-Kansas	25,478		23,898		25,920		1,580		(2,022		)
Other	3,229		1,421		7,905		1,808		(6,484		)
Total	$	343,093	$	304,461	$	322,088	$	38,632	$	(17,627	)

Regulated Transmission and Storage Segment

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

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

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

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

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Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the fiscal years ended September 30, 2013, 2012 and 2011 are presented below.



	For the Fiscal Year Ended September 30
	2013			2012			2011		2013 vs. 2012			2012 vs. 2011
	(In thousands, unless otherwise noted)
Mid-Tex Division transportation	$	179,628		$	162,808		$	125,973	$	16,820		$	36,835
Third-party transportation	66,939			64,158			73,676		2,781			(9,518		)
Storage and park and lend services	5,985			6,764			7,995		(779		)	(1,231		)
Other	16,348			13,621			11,729		2,727			1,892
Gross profit	268,900			247,351			219,373		21,549			27,978
Operating expenses	129,047			118,527			111,098		10,520			7,429
Operating income	139,853			128,824			108,275		11,029			20,549
Miscellaneous income (expense)	(2,285		)	(1,051		)	4,715		(1,234		)	(5,766		)
Interest charges	30,678			29,414			31,432		1,264			(2,018		)
Income before income taxes	106,890			98,359			81,558		8,531			16,801
Income tax expense	38,630			35,300			29,143		3,330			6,157
Net income	$	68,260		$	63,059		$	52,415	$	5,201		$	10,644
Gross pipeline transportation volumes — MMcf	649,740			640,732			620,904		9,008			19,828
Consolidated pipeline transportation volumes — MMcf	467,178			466,527			435,012		651			31,515

Fiscal year ended September 30, 2013 compared with fiscal year ended September 30, 2012

The $21.5 million increase in regulated transmission and storage gross profit compared to the prior-year period was primarily a result of the Gas Reliability Infrastructure Program (GRIP) filings approved by the Railroad Commission of Texas (RRC) during fiscal 2012 and 2013. During fiscal 2012, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $14.7 million, effective April 2012. On May 7, 2013, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $26.7 million that went into effect with bills rendered on and after May 7, 2013. GRIP filings increased period-over-period gross profit by $19.7 million.

This increase was partially offset by a $10.5 million increase in operating expenses largely attributable to increased depreciation expense as a result of increased capital investments and increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system.

The APT 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 APT’s non-regulated annual revenue and a pre-defined base credit. The annual adjustment mechanism expired on June 30, 2013. APT requested to extend the annual adjustment mechanism until November 1, 2017. A hearing to review the request was held on October 29, 2013 with a final decision expected in December 2013.

Fiscal year ended September 30, 2012 compared with fiscal year ended September 30, 2011

The $28.0 million increase in regulated transmission and storage gross profit compared to the prior year was primarily a result of the rate case that was finalized and became effective in May 2011 as well as the GRIP filings approved by the RRC during fiscal 2011 and 2012. In May 2011, the RRC issued an order in the rate case of Atmos Pipeline - Texas that approved an annual operating income increase of $20.4 million. During fiscal 2011, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $12.6 million that went into effect in the fiscal fourth quarter. On April 10, 2012, the RRC approved the Atmos Pipeline - Texas GRIP filing with an annual operating income increase of $14.7 million that went into effect with bills rendered on an after April 10, 2012.

Operating expenses increased $7.4 million primarily due to a $5.4 million increase in depreciation expense, resulting from higher investment in net plant.

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Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $2.3 million associated with an update of the estimated tax rate at which deferred taxes would reverse in future periods after the completion of the sale of our Missouri, Illinois and Iowa assets. Net income for this segment for fiscal 2011 was favorably impacted by a $6.0 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks ($3.9 million, net of tax).

Nonregulated Segment

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

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, 2013, 2012 and 2011 are presented below.



	For the Fiscal Year Ended September 30
	2013			2012			2011			2013 vs. 2012			2012 vs. 2011
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	39,839		$	46,578		$	58,990		$	(6,739	)	$	(12,412	)
Storage and transportation services	14,641			13,382			14,570			1,259			(1,188		)
Other	(103		)	3,179			1,841			(3,282		)	1,338
Total realized margins	54,377			63,139			75,401			(8,762		)	(12,262		)
Unrealized margins	8,954			(8,015		)	(10,401		)	16,969			2,386
Gross profit	63,331			55,124			65,000			8,207			(9,876		)
Operating expenses, excluding asset impairment	44,404			36,886			39,113			7,518			(2,227		)
Asset impairment	—			5,288			30,270			(5,288		)	(24,982		)
Operating income (loss)	18,927			12,950			(4,383		)	5,977			17,333
Miscellaneous income	2,316			1,035			657			1,281			378
Interest charges	2,168			3,084			4,015			(916		)	(931		)
Income (loss) from continuing operations before income taxes	19,075			10,901			(7,741		)	8,174			18,642
Income tax expense (benefit)	7,493			5,612			(209		)	1,881			5,821
Income (loss) from continuing operations	11,582			5,289			(7,532		)	6,293			12,821
Loss on sale of discontinued operations, net of tax	(355		)	—			—			(355		)	—
Net income (loss)	$	11,227		$	5,289		$	(7,532	)	$	5,938		$	12,821
Gross nonregulated delivered gas sales volumes — MMcf	396,561			400,512			446,903			(3,951		)	(46,391		)
Consolidated nonregulated delivered gas sales volumes — MMcf	343,669			351,628			384,799			(7,959		)	(33,171		)
Net physical position (Bcf)	12.0			18.8			21.0			(6.8		)	(2.2		)

Fiscal year ended September 30, 2013 compared with fiscal year ended September 30, 2012

Gross profit increased $8.2 million for the year ended September 30, 2013 compared to the prior year. Realized margins decreased $8.8 million, primarily attributable to lower gas delivery margins. Consolidated sales volumes decreased two percent due to increased competition which reduced industrial and power generation sales. The impact of lower sales volumes was compounded by a decrease in per-unit margins from 11.6 cents per Mcf to 10.0 cents per Mcf. This decrease was offset by an increase of $17.0 million in unrealized margins, primarily due to the year-over-year timing of realized margins on the settlement of hedged natural gas inventory positions.

Operating expenses increased $7.5 million, primarily due to increased litigation and software support costs, partially offset by reduced employee costs.

Miscellaneous income increased $1.3 million primarily due to a gain realized from the sale of a peaking power facility and related assets during the first quarter of fiscal 2013.

Fiscal year ended September 30, 2012 compared with fiscal year ended September 30, 2011

Realized margins for gas delivery, storage and transportation services and other services were $63.1 million during the year ended September 30, 2012 compared with $75.4 million for fiscal 2011. The decrease reflects the following:


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


•	A $0.02/Mcf decrease in gas delivery per-unit margins compared to the prior year primarily due to lower basis differentials resulting from increased natural gas supply and increased transportation costs.

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Unrealized margins increased $2.4 million in fiscal 2012 compared to fiscal 2011 primarily due to the year-over-year timing of realized margins on the settlement of hedged natural gas inventory positions.

Operating expenses, excluding asset impairments decreased $2.2 million primarily due to lower employee-related expenses.

During the fourth quarter of fiscal 2012, we recorded a $5.3 million noncash charge to impair our natural gas gathering assets located in Kentucky. The charge reflected a reduction in the value of the project due to the current low natural gas price environment and management’s decision to focus AEH’s activities on its gas delivery, storage and transportation services. In fiscal 2011, asset impairments included an asset impairment charge of $19.3 million related to our investment in our Fort Necessity storage project as well as an $11.0 million pre-tax impairment charge related to the write-off of certain natural gas gathering assets.

LIQUIDITY AND CAPITAL RESOURCES

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

We regularly evaluate our funding strategy and profile to ensure that we (i) have sufficient liquidity for our short-term and long-term needs in a cost-effective manner and (ii) maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

The following table presents our capitalization as of September 30, 2013 and 2012:



	September 30
	2013				2012
	(In thousands, except percentages)
Short-term debt	$	367,984	6.8	%	$	570,929	11.7	%
Long-term debt	2,455,671		45.4	%	1,956,436		40.0	%
Shareholders’ equity	2,580,409		47.8	%	2,359,243		48.3	%
Total capitalization, including short-term debt	$	5,404,064	100.0	%	$	4,886,608	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 52.2 percent and 51.7 percent at September 30, 2013 and 2012.

On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which, in effect, replaced our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012, on a long-term basis. The net proceeds of approximately $494 million were used to repay $260 million outstanding under our short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.

Going forward, we anticipate our capital spending will be more consistent with levels experienced during fiscal 2013 as we continue to invest in the safety and reliability of our distribution and transportation system. We plan to continue to fund our growth and maintain a balanced capital structure through the use of long-term debt securities and, to a lesser extent, equity.

Further, $500 million of long-term debt will mature in October 2014. We plan to issue new senior notes to replace this maturing debt. During the current year, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with this anticipated issuance at 3.129%. We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for fiscal year 2014.

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.

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Cash flows from operating, investing and financing activities for the years ended September 30, 2013, 2012 and 2011 are presented below.



	For the Fiscal Year Ended September 30
	2013			2012			2011			2013 vs. 2012			2012 vs. 2011
	(In thousands)
Total cash provided by (used in)
Operating activities	$	613,127		$	586,917		$	582,844		$	26,210		$	4,073
Investing activities	(696,914		)	(609,260		)	(627,386		)	(87,654		)	18,126
Financing activities	85,747			(44,837		)	44,009			130,584			(88,846		)
Change in cash and cash equivalents	1,960			(67,180		)	(533		)	69,140			(66,647		)
Cash and cash equivalents at beginning of period	64,239			131,419			131,952			(67,180		)	(533		)
Cash and cash equivalents at end of period	$	66,199		$	64,239		$	131,419		$	1,960		$	(67,180	)

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 natural gas distribution segment resulting from the price of natural gas and the timing of customer collections, payments for natural gas purchases and purchased gas cost recoveries. The significant factors impacting our operating cash flow for the last three fiscal years are summarized below.

Fiscal Year ended September 30, 2013 compared with fiscal year ended September 30, 2012

For the fiscal year ended September 30, 2013, we generated operating cash flow of $613.1 million from operating activities compared with $586.9 million in the prior year. The year-over-year increase reflects changes in working capital offset by a $10.5 million decrease in contributions made to our pension and postretirement plans in the current year.

Fiscal Year ended September 30, 2012 compared with fiscal year ended September 30, 2011

For the fiscal year ended September 30, 2012, we generated operating cash flow of $586.9 million from operating activities compared with $582.8 million in fiscal 2011. The year-over-year increase reflects changes in working capital offset by a $56.7 million increase in contributions made to our pension and postretirement plans during fiscal 2012.

Cash flows from investing activities

Our ongoing capital expenditure program enables us to provide safe and reliable natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets and enhance the integrity of our pipelines. In recent years, we have increased our level of capital spending to improve the safety and reliability of our distribution system and to expand our intrastate pipeline network. Over the last three fiscal years, approximately 68 percent of our capital spending has been committed to improving the safety and reliability of our system.

Over the next five years, we anticipate our capital spending will be more consistent with levels experienced during fiscal 2013 as we continue to invest in the safety and reliability of our distribution and transportation system. Where possible, we will also continue to focus our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system.

For the fiscal year ended September 30, 2013, we incurred $845.0 million for capital expenditures compared with $732.9 million for the fiscal year ended September 30, 2012 and $623.0 million for the fiscal year ended September 30, 2011.

Fiscal Year ended September 30, 2013 compared with fiscal year ended September 30, 2012

The $112.1 million increase in capital expenditures in fiscal 2013 compared to fiscal 2012 primarily reflects spending incurred for the Line W and Line WX expansion projects and increased cathodic protection spending in our regulated transmission and storage segment.

Fiscal Year ended September 30, 2012 compared with fiscal year ended September 30, 2011

The $109.9 million increase in capital expenditures in fiscal 2012 compared to fiscal 2011 primarily reflects spending for the steel service line replacement program in the Mid-Tex Division, the development of new customer billing and information systems for our natural gas distribution and our nonregulated segments and increased capital spending to increase the capacity on our Atmos Pipeline — Texas system.

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Cash flows from financing activities

We received a net $85.7 million and $44.0 million in cash from financing activities for fiscal years 2013 and 2011. In fiscal 2012, we used a net $44.8 million in financing activities. Our significant financing activities for the fiscal years ended September 30, 2013, 2012 and 2011 are summarized as follows:

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 the prior year. Current year 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.

2012

During the fiscal year ended September 30, 2012, our financing activities used $44.8 million of cash, primarily due to the payment of $257.0 million associated with the early redemption of our $250 million 5.125% Senior notes that were scheduled to mature in January 2013. The repayment of our $250 million 5.125% Senior notes was financed using a $260 million short-term loan. Additionally, we repurchased $12.5 million of common stock under our 2011 share repurchase program.

2011

During the fiscal year ended September 30, 2011, our financing activities generated $44.0 million of cash, primarily related to the issuance of $400 million 5.50% Senior Notes in June 2011 and the related settlement of three Treasury locks for $20.1 million. We used a portion of the net cash proceeds of $394.5 million to pay scheduled long-term debt repayments, including our $350 million 7.375% senior notes that were paid on their maturity date in May 2011. Additionally, we received $27.8 million cash in March 2011 related to the unwinding of two Treasury locks.

The following table shows the number of shares issued for the fiscal years ended September 30, 2013, 2012 and 2011:



	For the Fiscal Year Ended September 30
	2013	2012	2011
Shares issued:
1998 Long-term incentive plan	531,672	482,289	675,255
Outside directors stock-for-fee plan	2,088	2,375	2,385
Total shares issued	533,760	484,664	677,640

The increase in the number of shares issued in fiscal 2013 compared with the number of shares issued in fiscal 2012 primarily reflects the type of awards that were issued from the 1998 Long-Term Incentive Plan (LTIP). In the current year, employees were issued restricted stock units, for which we issued new shares. In the prior year, employees were issued restricted stock awards, which were held in trust and did not require the issuance of new shares. During fiscal 2013, we canceled and retired 133,449 shares attributable to federal withholdings on equity awards which are not included in the table above. At September 30, 2013, of the 8.7 million shares authorized for issuance from the LTIP, 1.4 million shares remained available.

The decreased number of shares issued in fiscal 2012 compared with the number of shares issued in fiscal 2011 primarily reflects the exercise of a significant number of stock options during fiscal 2011. During fiscal 2012, we canceled and retired 153,255 shares attributable to federal withholdings on equity awards and repurchased and retired 387,991 shares attributable to our share repurchase program, 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 $950 million commercial paper program, which is collateralized by our $950 million unsecured credit facility, as well as three additional committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. As a result, we have approximately $1 billion of working capital funding. Additionally, our $950 million unsecured credit facility has an accordion feature, which, if utilized, would increase borrowing capacity to $1.2 billion. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.

Shelf Registration

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On March 28, 2013, we filed a registration statement with the Securities and Exchange Commission to

issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaced our

registration statement that expired on March 31, 2013. As of September 30, 2013, $1.75 billion was available under the shelf

registration statement.

Credit Ratings

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

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, 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-

Baa1

A-

Commercial paper

A-2

P-2

F-2

On October 8, 2013, S&P upgraded our senior unsecured debt rating to A- from BBB+, with a ratings outlook of stable, citing an improved business risk profile from an increasing contribution of earnings from our regulated operations and focusing our nonregulated operations on our delivered gas business.

A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

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

Debt Covenants

We were in compliance with all of our debt covenants as of September 30, 2013. Our debt covenants are described in Note 5 to the consolidated financial statements.

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Contractual Obligations and Commercial Commitments

The following table provides information about contractual obligations and commercial commitments at September 30, 2013.



	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	$	—	$	500,000	$	250,000	$	1,710,000
Short-term debt⁽¹⁾	367,984		367,984		—		—		—
Interest charges⁽²⁾	1,918,491		144,317		240,097		218,585		1,315,492
Gas purchase commitments⁽³⁾	230,480		230,480		—		—		—
Capital lease obligations⁽⁴⁾	822		186		372		264		—
Operating leases⁽⁴⁾	166,802		16,722		30,276		30,131		89,673
Demand fees for contracted storage⁽⁵⁾	6,088		4,196		1,252		284		356
Demand fees for contracted transportation⁽⁶⁾	13,098		8,466		4,604		28		—
Financial instrument obligations⁽⁷⁾	7,676		1,543		6,133		—		—
Pension and postretirement benefit plan contributions⁽⁸⁾	411,623		67,687		101,176		82,976		159,784
Uncertain tax positions (including interest)⁽⁹⁾	3,172		—		3,172		—		—
Total contractual obligations	$	5,586,236	$	841,581	$	887,082	$	582,268	$	3,275,305


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


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


⁽³⁾	Gas purchase commitments were determined based upon contractually determined volumes at prices estimated based upon the index specified in the contract, adjusted for estimated basis differentials and contractual discounts as of September 30, 2013.


⁽⁴⁾	See Note 9 to the consolidated financial statements.


⁽⁵⁾	Represents third party contractual demand fees for contracted storage in our nonregulated segment. Contractual demand fees for contracted storage for our natural gas distribution segment are excluded as these costs are fully recoverable through our purchase gas adjustment mechanisms.


⁽⁶⁾	Represents third party contractual demand fees for transportation in our nonregulated segment.


⁽⁷⁾	Represents liabilities for natural gas commodity financial instruments that were valued as of September 30, 2013. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled.


⁽⁸⁾	Represents expected contributions to our pension and postretirement benefit plans, which are discussed in Note 6 to the consolidated financial statements.


⁽⁹⁾	Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax returns.

With the exception of our Mid-Tex Division, our natural gas 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 maintains long-term supply contracts to ensure a reliable source of natural gas for our customers in its service area which obligate it to purchase specified volumes at market prices. The estimated commitments under the terms of these contracts as of September 30, 2013 are reflected in the table above.

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, 2013, AEH was committed to purchase 78.0 Bcf within one year, 21.9 Bcf within one to three years and 1.0 Bcf after three years under indexed contracts. AEH is committed to purchase 6.1 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $3.32 to $6.36 per Mcf.

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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 natural gas distribution and nonregulated segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. 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 natural gas distribution segment’s financial instruments for the fiscal year ended September 30, 2013 (in thousands):



Fair value of contracts at September 30, 2012	$	(76,260	)
Contracts realized/settled	2,590
Fair value of new contracts	3,077
Other changes in value	180,241
Fair value of contracts at September 30, 2013	$	109,648

The fair value of our natural gas distribution segment’s financial instruments at September 30, 2013, is presented below by time period and fair value source:



	Fair Value of Contracts at September 30, 2013
	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	$	294	$	109,354	$	—	$	—	$	109,648
Prices based on models and other valuation methods	—		—		—		—		—
Total Fair Value	$	294	$	109,354	$	—	$	—	$	109,648

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, 2013 (in thousands):




Fair value of contracts at September 30, 2012	$	(15,123	)
Contracts realized/settled	(245		)
Fair value of new contracts	—
Other changes in value	668
Fair value of contracts at September 30, 2013	(14,700		)
Netting of cash collateral	24,829
Cash collateral and fair value of contracts at September 30, 2013	$	10,129

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The fair value of our nonregulated segment’s financial instruments at September 30, 2013, is presented below by time period and fair value source.



	Fair Value of Contracts at September 30, 2013
	Maturity in years
Source of Fair Value	Less than 1			1-3			4-5			Greater than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(8,567	)	$	(5,957	)	$	(176	)	$	—	$	(14,700	)
Prices based on models and other valuation methods	—			—			—			—		—
Total Fair Value	$	(8,567	)	$	(5,957	)	$	(176	)	$	—	$	(14,700	)

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, and we believe these programs are consistent with other programs in our industry. Since 2006, we have experienced medical and prescription inflation of approximately four percent. 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.

In March 2010, President Obama signed The Patient Protection and Affordable Care Act into law (the “Health Care Reform Act”). The Health Care Reform Act will be phased in over an eight-year period. We have changed the design of our health care plans to comply with provisions of the Health Care Reform Act that have already gone into effect or will be going into effect in future years. We will continue to monitor all developments on health care reform and continue to comply with all existing relevant laws and regulations.

For fiscal 2014, we anticipate an approximate six percent medical and prescription drug inflation rate, primarily due to anticipated higher claims costs and the implementation of the Health Care Reform Act.

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2013, our total net periodic pension and other benefits costs was $78.5 million, compared with $69.2 million and $56.6 million for the fiscal years ended September 30, 2012 and 2011. These costs relating to our natural gas distribution operations are recoverable through our gas distribution rates. A portion of these costs is capitalized into our gas distribution rate base, and the remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 2013 costs were determined using a September 30, 2012 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, 2011, the measurement date for our fiscal 2012 net periodic cost. As a result of the lower interest and corporate bond rates, we decreased the discount rate used to determine our fiscal 2013 pension and benefit costs to 4.04 percent. Our expected return on our pension plan assets was maintained at 7.75 percent due to historical experience and the current market projection of the target asset allocation. As a result, our fiscal 2013 pension and postretirement medical costs were higher than in the prior year.

The increase in total net periodic pension and other benefits costs during fiscal 2012 compared with fiscal 2011 primarily reflects the decrease in our discount rate at September 30, 2011, the measurement date for our fiscal 2012 pension and postretirement costs. The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. At our September 30, 2011 measurement date, the interest and corporate bond rates used to determine our fiscal 2012 net periodic pension cost were significantly lower than the rates at September 30, 2010, the measurement date used to determine our fiscal 2011 net periodic cost. Our expected return on our pension plan assets was reduced to 7.75 percent due to historical experience and the then-current market projection of the target asset allocation.

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

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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, 2013. Based on this valuation, we were required to contribute cash of $32.7 million, $46.5 million and $0.9 million to our pension plans during fiscal 2013, 2012 and 2011. The higher level of contributions experienced during fiscal 2013 and 2012 reflect lower discount rates than in previous years. Each contribution increased the level of our plan assets to achieve a desirable PPA funding threshold.

We contributed $26.6 million and $22.1 million to our postretirement benefits plans for the fiscal years ended September 30, 2013 and 2012. 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 2014 and Beyond

As of September 30, 2013, interest and corporate bond rates were higher than the rates as of September 30, 2012. 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 changes in these and other assumptions, we expect our fiscal 2014 net period pension cost to decrease by less than five percent.

Based upon market conditions subsequent to September 30, 2013, the current funded position of the plans and the funding requirements under the PPA, we anticipate contributing between $15 million and $25 million to the Plans in fiscal 2014. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds. With respect to our postretirement medical plans, we anticipate contributing between $25 million and $30 million during fiscal 2014.

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 $2.8 million. A 0.25 percent change in our expected

rate of return would impact our pension and postretirement costs by approximately $1.0 million.

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

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 natural gas distribution and nonregulated segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to 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

Natural gas distribution segment

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

Nonregulated segment

Our nonregulated segment is also exposed to risks associated with changes in the market price of natural gas. For our nonregulated segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open position (including existing storage and related financial contracts) at the end of each period. Based on AEH’s net open position (including existing storage and related financial contracts) at September 30, 2013 of 0.1 Bcf, a $0.50 change in the forward NYMEX price would have had a $0.1 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, 2013 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 $3.7 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 $3.2 million during 2013.

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ITEM 8.	Financial Statements and Supplementary Data.

Index to financial statements and financial statement schedule:



	Page
Report of independent registered public accounting firm	47
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2013 and 2012	48
Consolidated statements of income for the years ended September 30, 2013, 2012 and 2011	49
Consolidated statements of comprehensive income for the years ended September 30, 2013, 2012 and 2011	50
Consolidated statements of shareholders’ equity for the years ended September 30, 2013, 2012 and 2011	51
Consolidated statements of cash flows for the years ended September 30, 2013, 2012 and 2011	52
Notes to consolidated financial statements	53
Selected Quarterly Financial Data (Unaudited)	100
Financial statement schedule for the years ended September 30, 2013, 2012 and 2011
Schedule II. Valuation and Qualifying Accounts	110

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.

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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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2013, 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, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated November 13, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

November 13, 2013

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ATMOS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS



	September 30
	2013		2012
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	7,446,272	$	6,860,358
Construction in progress	275,747		274,112
	7,722,019		7,134,470
Less accumulated depreciation and amortization	1,691,364		1,658,866
Net property, plant and equipment	6,030,655		5,475,604
Current assets
Cash and cash equivalents	66,199		64,239
Accounts receivable, less allowance for doubtful accounts of $20,624 in 2013 and $9,425 in 2012	301,992		234,526
Gas stored underground	244,741		256,415
Other current assets	70,334		272,782
Total current assets	683,266		827,962
Goodwill and intangible assets	741,484		740,847
Deferred charges and other assets	484,996		451,262
	$	7,940,401	$	7,495,675
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2013 — 90,640,211 shares, 2012 — 90,239,900 shares	$	453	$	451
Additional paid-in capital	1,765,811		1,745,467
Accumulated other comprehensive income (loss)	38,878		(47,607		)
Retained earnings	775,267		660,932
Shareholders’ equity	2,580,409		2,359,243
Long-term debt	2,455,671		1,956,305
Total capitalization	5,036,080		4,315,548
Commitments and contingencies
Current liabilities
Accounts payable and accrued liabilities	241,611		215,229
Other current liabilities	368,891		489,665
Short-term debt	367,984		570,929
Current maturities of long-term debt	—		131
Total current liabilities	978,486		1,275,954
Deferred income taxes	1,164,053		1,015,083
Regulatory cost of removal obligation	359,299		381,164
Pension and postretirement liabilities	358,787		457,196
Deferred credits and other liabilities	43,696		50,730
	$	7,940,401	$	7,495,675

See accompanying notes to consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME



	Year Ended September 30
	2013			2012			2011
	(In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	2,399,493		$	2,145,330		$	2,470,664
Regulated transmission and storage segment	268,900			247,351			219,373
Nonregulated segment	1,598,711			1,351,303			2,024,893
Intersegment eliminations	(380,847		)	(305,501		)	(428,495		)
	3,886,257			3,438,483			4,286,435
Purchased gas cost
Natural gas distribution segment	1,318,257			1,122,587			1,452,721
Regulated transmission and storage segment	—			—			—
Nonregulated segment	1,535,380			1,296,179			1,959,893
Intersegment eliminations	(379,430		)	(304,022		)	(426,999		)
	2,474,207			2,114,744			2,985,615
Gross profit	1,412,050			1,323,739			1,300,820
Operating expenses
Operation and maintenance	488,020			453,613			442,965
Depreciation and amortization	235,079			237,525			223,832
Taxes, other than income	187,072			181,073			177,767
Asset impairments	—			5,288			30,270
Total operating expenses	910,171			877,499			874,834
Operating income	501,879			446,240			425,986
Miscellaneous income (expense), net	(197		)	(14,644		)	21,184
Interest charges	128,385			141,174			150,763
Income from continuing operations before income taxes	373,297			290,422			296,407
Income tax expense	142,599			98,226			106,819
Income from continuing operations	230,698			192,196			189,588
Income from discontinued operations, net of tax ($3,986, $10,066 and $12,372)	7,202			18,172			18,013
Gain on sale of discontinued operations, net of tax ($2,909, $3,519 and $0)	5,294			6,349			—
Net income	$	243,194		$	216,717		$	207,601
Basic earnings per share
Income per share from continuing operations	$	2.54		$	2.12		$	2.08
Income per share from discontinued operations	0.14			0.27			0.20
Net income per share — basic	$	2.68		$	2.39		$	2.28
Diluted earnings per share
Income per share from continuing operations	$	2.50		$	2.10		$	2.07
Income per share from discontinued operations	0.14			0.27			0.20
Net income per share — diluted	$	2.64		$	2.37		$	2.27
Weighted average shares outstanding:
Basic	90,533			90,150			90,201
Diluted	91,711			91,172			90,652

See accompanying notes to consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Year Ended September 30
	2013			2012			2011
	(In thousands)
Net income	$	243,194		$	216,717		$	207,601
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(186), $1,881 and $(953)	(213		)	3,103			(1,647		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $47,236, $(5,388) and $(16,850)	82,179			(10,116		)	(28,689		)
Net unrealized gains on commodity cash flow hedges, net of tax of $2,889, $5,029 and $3,355	4,519			7,866			5,248
Total other comprehensive income (loss)	86,485			853			(25,088		)
Total comprehensive income	$	329,679		$	217,570		$	182,513

See accompanying notes to condensed consolidated financial statements.

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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			Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	(In thousands, except share and per share data)
Balance, September 30, 2010	90,164,103		$	451		$	1,714,364		$	(23,372	)	$	486,905		$	2,178,348
Net income	—		—			—			—			207,601			207,601
Other comprehensive loss	—		—			—			(25,088		)	—			(25,088		)
Repurchase of common stock	(375,468	)	(2		)	2			—			—			—
Repurchase of equity awards	(169,793	)	(1		)	(5,298		)	—			—			(5,299		)
Cash dividends ($1.36 per share)	—		—			—			—			(124,011		)	(124,011		)
Common stock issued:
Direct stock purchase plan	—		—			(54		)	—			—			(54		)
1998 Long-term incentive plan	675,255		3			13,886			—			—			13,889
Employee stock-based compensation	—		—			9,958			—			—			9,958
Outside directors stock-for-fee plan	2,385		—			77			—			—			77
Balance, September 30, 2011	90,296,482		451			1,732,935			(48,460		)	570,495			2,255,421
Net income	—		—			—			—			216,717			216,717
Other comprehensive income	—		—			—			853			—			853
Repurchase of common stock	(387,991	)	(2		)	(12,533		)	—			—			(12,535		)
Repurchase of equity awards	(153,255	)	—			(5,219		)	—			—			(5,219		)
Cash dividends ($1.38 per share)	—		—			—			—			(125,796		)	(125,796		)
Common stock issued:
Direct stock purchase plan	—		—			(65		)	—			—			(65		)
1998 Long-term incentive plan	482,289		2			12,519			—			(484		)	12,037
Employee stock-based compensation	—		—			17,752			—			—			17,752
Outside directors stock-for-fee plan	2,375		—			78			—			—			78
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

See accompanying notes to consolidated financial statements.

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ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended September 30
	2013			2012			2011
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	243,194		$	216,717		$	207,601
Adjustments to reconcile net income to net cash provided by operating activities:
Asset impairments	—			5,288			30,270
Gain on sale of discontinued operations	(8,203		)	(9,868		)	—
Depreciation and amortization:
Charged to depreciation and amortization	236,928			246,093			233,155
Charged to other accounts	679			484			228
Deferred income taxes	141,336			104,319			117,353
Stock-based compensation	17,814			19,222			11,586
Debt financing costs	8,480			8,147			9,438
Other	(2,887		)	(493		)	(961		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(73,669		)	32,578			(96		)
Decrease in gas stored underground	31,979			28,417			27,737
(Increase) decrease in other current assets	15,644			20,989			(38,048		)
(Increase) decrease in deferred charges and other assets	111,069			(50,055		)	(53,519		)
Increase (decrease) in accounts payable and accrued liabilities	31,912			(64,234		)	23,904
Increase (decrease) in other current liabilities	(44,491		)	7,889			(57,495		)
Increase (decrease) in deferred credits and other liabilities	(96,658		)	21,424			71,691
Net cash provided by operating activities	613,127			586,917			582,844
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures	(845,033		)	(732,858		)	(622,965		)
Proceeds from the sale of discontinued operations	153,023			128,223			—
Other, net	(4,904		)	(4,625		)	(4,421		)
Net cash used in investing activities	(696,914		)	(609,260		)	(627,386		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in short-term debt	(208,070		)	354,141			83,306
Net proceeds from issuance of long-term debt	493,793			—			394,466
Settlement of Treasury lock agreements	(66,626		)	—			20,079
Unwinding of Treasury lock agreements	—			—			27,803
Repayment of long-term debt	(131		)	(257,034		)	(360,131		)
Cash dividends paid	(128,115		)	(125,796		)	(124,011		)
Repurchase of common stock	—			(12,535		)	—
Repurchase of equity awards	(5,150		)	(5,219		)	(5,299		)
Issuance of common stock	46			1,606			7,796
Net cash provided by (used in) financing activities	85,747			(44,837		)	44,009
Net increase (decrease) in cash and cash equivalents	1,960			(67,180		)	(533		)
Cash and cash equivalents at beginning of year	64,239			131,419			131,952
Cash and cash equivalents at end of year	$	66,199		$	64,239		$	131,419
CASH PAID (RECEIVED) DURING THE PERIOD FOR:
Interest	$	148,461		$	150,606		$	157,976
Income taxes	$	10,008		$	(432	)	$	(8,329	)

See accompanying notes to consolidated financial statements.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated natural gas distribution divisions 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 natural gas distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

Our regulated transmission and storage business 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, natural gas 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, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, asset retirement obligations, 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 natural gas distribution and regulated transmission and storage 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

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2013 and 2012 included the following:



	September 30
	2013		2012
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	187,977	$	296,160
Merger and integration costs, net	5,250		5,754
Deferred gas costs	15,152		31,359
Regulatory cost of removal asset	10,008		10,500
Rate case costs	6,329		4,661
Deferred franchise fees	—		2,714
Texas Rule 8.209⁽²⁾	30,364		5,370
APT annual adjustment mechanism	5,853		4,539
Recoverable loss on reacquired debt	21,435		23,944
Other	4,380		7,262
	$	286,748	$	392,263
Regulatory liabilities:
Deferred gas costs	$	16,481	$	23,072
Deferred franchise fees	1,689		—
Regulatory cost of removal obligation	427,524		459,688
Other	7,887		5,637
	$	453,581	$	488,397


⁽¹⁾	Includes $17.4 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.


⁽²⁾	Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

The amounts above do not include regulatory assets and liabilities related to our Georgia operations, which were classified as assets held for sale at September 30, 2012 as discussed in Note 16. As of September 30, 2013, we did not have any assets or liabilities classified as held for sale due to the sale of substantially all of our Georgia assets on April 1, 2013.

Currently, authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. During the fiscal years ended September 30, 2013, 2012 and 2011, we recognized $0.5 million, $0.5 million and $0.5 million in amortization expense related to these costs.

Revenue recognition — Sales of natural gas to our natural gas 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 natural gas 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.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 natural gas 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 transmission and storage 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 and unrealized gains and losses arising from changes in the fair value of natural gas inventory designated as a hedged item in a fair value hedge and the associated financial instruments. For the fiscal years ended September 30, 2013, 2012 and 2011, we included unrealized gains (losses) on open contracts of $9.0 million, $(8.0) million and $(10.4) million as a component of nonregulated revenues.

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 natural gas distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for all our regulated operations, except for certain jurisdictions in the Kentucky/Mid-States Division, where it is valued on the first-in first-out method basis, in accordance with regulatory requirements. 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 $1.9 million, $2.6 million and $1.7 million was capitalized in 2013, 2012 and 2011.

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, 3.6 percent and 3.6 percent for the fiscal years ended September 30, 2013, 2012 and 2011.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 50 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, 2013 and 2012, we had asset retirement obligations of $6.8 million and $10.5 million. Additionally, we had $3.3 million and $5.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.

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

Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

During fiscal 2012, we recorded a pre-tax noncash impairment loss of $5.3 million related to our gathering systems in Kentucky. In fiscal 2011, we recorded pre-tax noncash impairment losses of $19.3 million related to our Fort Necessity storage project and $11.0 million related to our gathering systems in Kentucky. See Note 14 for further details.

Goodwill and intangible assets — 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.

Intangible assets are amortized over their useful lives of 10 years. These assets are reviewed for impairment as impairment indicators arise. 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. No impairment has been recognized.

Marketable securities — As of September 30, 2013 and 2012, 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 natural gas 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.

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

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In our natural gas 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 natural gas 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 revenue 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 revenue 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.

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 revenue 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 revenue.

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, 2013 and 2012, the Company netted $24.8 million and $23.7 million of cash held in margin accounts into its current risk management assets and liabilities.

Financial Instruments Associated with Interest Rate Risk

We manage interest rate risk, typically when we plan to issue new long-term debt or to refinance existing long-term debt. Prior to fiscal 2012, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We designated these Treasury lock agreements as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income (loss). When the Treasury locks were settled, the realized gain or loss was recorded as a component of accumulated other comprehensive income (loss) and is being recognized as a component of interest expense over the life of the related financing arrangement.

During fiscal 2012, we began using interest rate swaps and forward starting interest rate swaps to mitigate interest rate risk. Unrealized gains and losses associated with the swaps are recorded as a component of accumulated other comprehensive income (loss). When the 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.

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

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 our 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.

As of September 30, 2013 our Master Trust owned one real estate investment with a value less than $0.2 million that qualifies as a Level 3 fair value measurement. The valuation technique used was a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land and building sales values per square foot. Currently, we have no other assets or liabilities recorded at fair value that would qualify for Level 3 reporting.

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.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 cost is 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 calculation 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 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.

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 concerning the October 2, 2013 payment from our Supplemental Executive Benefits Plan related to the retirement of one of our executives, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.

Recent accounting pronouncements — During the year ended September 30, 2013, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard clarifies the enhanced disclosure of offsetting arrangements for financial instruments that will become effective for us for annual and interim periods beginning on October 1, 2013. The adoption of this standard should not have an impact on our financial position, results of operations or cash flows. The second standard changes the presentation requirements for an unrecognized tax benefit if a net operating loss carryforward or tax credit carryforward exists, which will become effective for us for annual and interim periods beginning on October 1, 2014. The adoption of this standard should not have a material impact on our financial position, results of operations or cash flows.

Beginning in our first fiscal quarter, we have presented a single statement of other comprehensive income, due to an accounting pronouncement that became effective for us on October 1, 2012. Additionally, a standard that became effective during our second fiscal quarter requires the presentation of amounts reclassified out of accumulated other comprehensive income by component as well as significant amounts reclassified out of accumulated other comprehensive income by the respective line item in the statement of net income. We have presented the disclosures relating to reclassifications out of accumulated other comprehensive income in Note 13. The adoption of these standards did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the year ended September 30, 2013.

3. Segment Information

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Atmos Energy Corporation and its subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage 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 natural gas 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, natural gas distribution companies, including certain divisions of Atmos Energy and third parties.

We operate the Company through the following three segments:


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


•	The regulated transmission and storage 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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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.

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



	Year Ended September 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,394,418	$	89,011		$	1,402,828		$	—		$	3,886,257
Intersegment revenues	5,075		179,889			195,883			(380,847		)	—
	2,399,493		268,900			1,598,711			(380,847		)	3,886,257
Purchased gas cost	1,318,257		—			1,535,380			(379,430		)	2,474,207
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

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Year Ended September 30, 2012
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,144,376		$	92,604		$	1,201,503	$	—		$	3,438,483
Intersegment revenues	954			154,747			149,800		(305,501		)	—
	2,145,330			247,351			1,351,303		(305,501		)	3,438,483
Purchased gas cost	1,122,587			—			1,296,179		(304,022		)	2,114,744
Gross profit	1,022,743			247,351			55,124		(1,479		)	1,323,739
Operating expenses
Operation and maintenance	353,879			71,521			29,697		(1,484		)	453,613
Depreciation and amortization	202,026			31,438			4,061		—			237,525
Taxes, other than income	162,377			15,568			3,128		—			181,073
Asset impairments	—			—			5,288		—			5,288
Total operating expenses	718,282			118,527			42,174		(1,484		)	877,499
Operating income	304,461			128,824			12,950		5			446,240
Miscellaneous income (expense)	(12,657		)	(1,051		)	1,035		(1,971		)	(14,644		)
Interest charges	110,642			29,414			3,084		(1,966		)	141,174
Income from continuing operations before income taxes	181,162			98,359			10,901		—			290,422
Income tax expense	57,314			35,300			5,612		—			98,226
Income from continuing operations	123,848			63,059			5,289		—			192,196
Income from discontinued operations, net of tax	18,172			—			—		—			18,172
Gain on sale of discontinued operations, net of tax	6,349			—			—		—			6,349
Net income	$	148,369		$	63,059		$	5,289	$	—		$	216,717
Capital expenditures	$	546,818		$	175,768		$	10,272	$	—		$	732,858

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Year Ended September 30, 2011
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,469,781	$	87,141	$	1,729,513		$	—		$	4,286,435
Intersegment revenues	883		132,232		295,380			(428,495		)	—
	2,470,664		219,373		2,024,893			(428,495		)	4,286,435
Purchased gas cost	1,452,721		—		1,959,893			(426,999		)	2,985,615
Gross profit	1,017,943		219,373		65,000			(1,496		)	1,300,820
Operating expenses
Operation and maintenance	341,758		70,401		32,308			(1,502		)	442,965
Depreciation and amortization	193,642		25,997		4,193			—			223,832
Taxes, other than income	160,455		14,700		2,612			—			177,767
Asset impairments	—		—		30,270			—			30,270
Total operating expenses	695,855		111,098		69,383			(1,502		)	874,834
Operating income (loss)	322,088		108,275		(4,383		)	6			425,986
Miscellaneous income	16,242		4,715		657			(430		)	21,184
Interest charges	115,740		31,432		4,015			(424		)	150,763
Income (loss) from continuing operations before income taxes	222,590		81,558		(7,741		)	—			296,407
Income tax expense (benefit)	77,885		29,143		(209		)	—			106,819
Income (loss) from continuing operations	144,705		52,415		(7,532		)	—			189,588
Income from discontinued operations, net of tax	18,013		—		—			—			18,013
Net income (loss)	$	162,718	$	52,415	$	(7,532	)	$	—		$	207,601
Capital expenditures	$	496,899	$	118,452	$	7,614		$	—		$	622,965

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



	2013		2012		2011
	(In thousands)
Natural gas distribution revenues:
Gas sales revenues:
Residential	$	1,512,495	$	1,351,479	$	1,535,887
Commercial	661,930		587,651		685,380
Industrial	81,155		71,960		96,636
Public authority and other	60,557		54,334		68,676
Total gas sales revenues	2,316,137		2,065,424		2,386,579
Transportation revenues	55,938		53,924		57,331
Other gas revenues	22,343		25,028		25,871
Total natural gas distribution revenues	2,394,418		2,144,376		2,469,781
Regulated transmission and storage revenues	89,011		92,604		87,141
Nonregulated revenues	1,402,828		1,201,503		1,729,513
Total operating revenues	$	3,886,257	$	3,438,483	$	4,286,435

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at September 30, 2013 and 2012 by segment is presented in the following tables.



	September 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,719,873	$	1,249,767	$	61,015		$	—		$	6,030,655
Investment in subsidiaries	831,136		—		(2,096		)	(829,040		)	—
Current assets
Cash and cash equivalents	4,237		—		61,962			—			66,199
Assets from risk management activities	1,837		—		16,262			—			18,099
Other current assets	428,366		11,709		452,126			(293,233		)	598,968
Intercompany receivables	783,738		—		—			(783,738		)	—
Total current assets	1,218,178		11,709		530,350			(1,076,971		)	683,266
Intangible assets	—		—		121			—			121
Goodwill	574,190		132,462		34,711			—			741,363
Noncurrent assets from risk management activities	109,354		—		—			—			109,354
Deferred charges and other assets	347,687		19,227		8,728			—			375,642
	$	7,800,418	$	1,413,165	$	632,829		$	(1,906,011	)	$	7,940,401
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,580,409	$	396,421	$	434,715		$	(831,136	)	$	2,580,409
Long-term debt	2,455,671		—		—			—			2,455,671
Total capitalization	5,036,080		396,421		434,715			(831,136		)	5,036,080
Current liabilities
Current maturities of long-term debt	—		—		—			—			—
Short-term debt	645,984		—		—			(278,000		)	367,984
Liabilities from risk management activities	1,543		—		—			—			1,543
Other current liabilities	491,681		20,288		110,306			(13,316		)	608,959
Intercompany payables	—		712,768		70,970			(783,738		)	—
Total current liabilities	1,139,208		733,056		181,276			(1,075,054		)	978,486
Deferred income taxes	871,360		283,554		8,960			179			1,164,053
Noncurrent liabilities from risk management activities	—		—		6,133			—			6,133
Regulatory cost of removal obligation	359,299		—		—			—			359,299
Pension and postretirement liabilities	358,787		—		—			—			358,787
Deferred credits and other liabilities	35,684		134		1,745			—			37,563
	$	7,800,418	$	1,413,165	$	632,829		$	(1,906,011	)	$	7,940,401

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	September 30, 2012
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,432,017	$	979,443	$	64,144		$	—		$	5,475,604
Investment in subsidiaries	747,496		—		(2,096		)	(745,400		)	—
Current assets
Cash and cash equivalents	12,787		—		51,452			—			64,239
Assets from risk management activities	6,934		—		17,773			—			24,707
Other current assets	546,187		11,788		404,097			(223,056		)	739,016
Intercompany receivables	636,557		—		—			(636,557		)	—
Total current assets	1,202,465		11,788		473,322			(859,613		)	827,962
Intangible assets	—		—		164			—			164
Goodwill	573,550		132,422		34,711			—			740,683
Noncurrent assets from risk management activities	2,283		—		—			—			2,283
Deferred charges and other assets	417,893		24,353		6,733			—			448,979
	$	7,375,704	$	1,148,006	$	576,978		$	(1,605,013	)	$	7,495,675
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,359,243	$	328,161	$	419,335		$	(747,496	)	$	2,359,243
Long-term debt	1,956,305		—		—			—			1,956,305
Total capitalization	4,315,548		328,161		419,335			(747,496		)	4,315,548
Current liabilities
Current maturities of long-term debt	—		—		131			—			131
Short-term debt	782,719		—		—			(211,790		)	570,929
Liabilities from risk management activities	85,366		—		15			—			85,381
Other current liabilities	526,089		12,478		90,116			(9,170		)	619,513
Intercompany payables	—		584,578		51,979			(636,557		)	—
Total current liabilities	1,394,174		597,056		142,241			(857,517		)	1,275,954
Deferred income taxes	789,288		220,647		5,148			—			1,015,083
Noncurrent liabilities from risk management activities	—		—		9,206			—			9,206
Regulatory cost of removal obligation	381,164		—		—			—			381,164
Pension and postretirement liabilities	457,196		—		—			—			457,196
Deferred credits and other liabilities	38,334		2,142		1,048			—			41,524
	$	7,375,704	$	1,148,006	$	576,978		$	(1,605,013	)	$	7,495,675

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Earnings Per Share

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

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



	2013		2012		2011
	(In thousands, except per share data)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	230,698	$	192,196	$	189,588
Less: Income from continuing operations allocated to participating securities	775		793		1,980
Income from continuing operations available to common shareholders	$	229,923	$	191,403	$	187,608
Basic weighted average shares outstanding	90,533		90,150		90,201
Income from continuing operations per share — Basic	$	2.54	$	2.12	$	2.08
Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	12,496	$	24,521	$	18,013
Less: Income from discontinued operations allocated to participating securities	42		101		188
Income from discontinued operations available to common shareholders	$	12,454	$	24,420	$	17,825
Basic weighted average shares outstanding	90,533		90,150		90,201
Income from discontinued operations per share — Basic	$	0.14	$	0.27	$	0.20
Net income per share — Basic	$	2.68	$	2.39	$	2.28
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	229,923	$	191,403	$	187,608
Effect of dilutive stock options and other shares	5		4		4
Income from continuing operations available to common shareholders	$	229,928	$	191,407	$	187,612
Basic weighted average shares outstanding	90,533		90,150		90,201
Additional dilutive stock options and other shares	1,178		1,022		451
Diluted weighted average shares outstanding	91,711		91,172		90,652
Income from continuing operations per share — Diluted	$	2.50	$	2.10	$	2.07
Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	12,454	$	24,420	$	17,825
Effect of dilutive stock options and other shares	—		—		—
Income from discontinued operations available to common shareholders	$	12,454	$	24,420	$	17,825
Basic weighted average shares outstanding	90,533		90,150		90,201
Additional dilutive stock options and other shares	1,178		1,022		451
Diluted weighted average shares outstanding	91,711		91,172		90,652
Income from discontinued operations per share — Diluted	$	0.14	$	0.27	$	0.20
Net income per share — Diluted	$	2.64	$	2.37	$	2.27

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the fiscal years ended September 30, 2013, 2012 and 2011.

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5. Debt

Long-term debt

Long-term debt at September 30, 2013 and 2012 consisted of the following:



	2013		2012
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	500,000	$	500,000
Unsecured 6.35% Senior Notes, due 2017	250,000		250,000
Unsecured 8.50% Senior Notes, due 2019	450,000		450,000
Unsecured 5.95% Senior Notes, due 2034	200,000		200,000
Unsecured 5.50% Senior Notes, due 2041	400,000		400,000
Unsecured 4.15% Senior Notes, due 2043	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
Rental property term notes due in installments through 2013	—		131
Total long-term debt	2,460,000		1,960,131
Less:
Original issue discount on unsecured senior notes and debentures	4,329		3,695
Current maturities	—		131
	$	2,455,671	$	1,956,305

We issued $500 million Unsecured 4.15% Senior Notes on January 11, 2013. The effective rate of these notes is 4.67%, after giving effect to offering costs and the settlement of the associated Treasury lock agreements discussed in Note 12. Of the net proceeds of approximately $494 million, $234 million was used to partially repay our commercial paper borrowings and for general corporate purposes. The remaining $260 million was used to repay a short-term financing facility that was scheduled to mature on February 1, 2013. This facility was executed on September 27, 2012, with interest rates at a LIBOR based rate plus a company specific spread, to repay commercial paper borrowings that were used to redeem our $250 million Unsecured 5.125% Senior Notes were scheduled to mature in January 2013.

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 $950 million 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 billion of working capital funding. At September 30, 2013 and 2012, there was $368.0 million and $310.9 million outstanding under our commercial paper program with weighted average interest rates of 0.25% and 0.48%, 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 $985 million of working capital funding. The first facility is a five-year unsecured facility that was amended on December 7, 2012 to increase the borrowing capacity from $750 million to $950 million with an accordion feature, which, if utilized would increase the borrowing capacity to $1.2 billion. On August 22, 2013 the terms of the facility were amended to extend the expiration date from May 2016 to August 2018. 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 two percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At September 30, 2013, there were no borrowings under this facility, but we had $368.0 million of commercial paper outstanding leaving $582.0 million available.

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2013. At September 30, 2013, there were no borrowings outstanding under this facility.

The third facility which was renewed on September 30, 2013 for $10 million is a committed revolving credit facility used primarily to issue letters of credit that bears interest at a LIBOR-based rate plus 1.5 percent. At September 30, 2013, 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, 2013, 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 each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2013, our total-debt-to-total-capitalization ratio, as defined, was 54 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, 2013. There was $278.0 million outstanding under this facility at September 30, 2013.

Nonregulated Operations

Prior to December 5, 2012, Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, had a three-year $200 million committed revolving credit facility, expiring in December 2014, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility was primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. This facility

was collateralized by substantially all of the assets of AEM and was guaranteed by AEH. AEM terminated the committed

revolving credit facility on December 5, 2012, to reduce external credit expense. AEM incurred no penalties in connection with

the termination. This facility was replaced with two $25 million, 364-day bilateral credit facilities, one of which is a committed

facility. 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 $37.4 million at September 30, 2013.

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 or (ii) the rate for AEM’s borrowings under its committed line of credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013. There were no borrowings outstanding under this facility at September 30, 2013.

Shelf Registration

On March 28, 2013, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaced our registration statement that expired on March 31, 2013. As of September 30, 2013, $1.75 billion was available under the shelf registration statement.

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, 2013. 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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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Maturities of long-term debt at September 30, 2013 were as follows (in thousands):



2014	$	—
2015	500,000
2016	—
2017	250,000
2018	—
Thereafter	1,710,000
	$	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, 2013
Unrecognized transition obligation	$	—		$	—	$	628		$	628
Unrecognized prior service credit	(91		)	—		(5,961		)	(6,052		)
Unrecognized actuarial loss	108,621			31,466		35,961			176,048
	$	108,530		$	31,466	$	30,628		$	170,624
September 30, 2012
Unrecognized transition obligation	$	—		$	—	$	1,709		$	1,709
Unrecognized prior service credit	(232		)	—		(7,411		)	(7,643		)
Unrecognized actuarial loss	187,050			43,995		63,402			294,447
	$	186,818		$	43,995	$	57,700		$	288,513

Defined Benefit Plans

Employee Pension Plans

As of September 30, 2013, 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 are held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust).

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 grandfather 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.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Union Plan is a defined benefit plan that covers substantially all full-time union employees in our Mississippi Division. Under this plan, benefits are based upon years of benefit service and average final earnings. Participants vest in the plan after five years and will receive their benefit in an annuity.

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

During fiscal 2013 and 2012 we contributed $32.7 million and $46.5 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 subsequent to September 30, 2013, the current funded position of the Plans and the new funding requirements under the PPA, we anticipate contributing between $15 million and $25 million to the Plans in fiscal 2014. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds.

We manage the Master Trust’s assets with the objective of achieving a rate of return net of inflation of approximately four percent per year. We make investment decisions and evaluate performance 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, 2013 and 2012.



	Targeted Allocation Range	Actual Allocation September 30
Security Class	Targeted Allocation Range	2013		2012
Domestic equities	35%-55%	46.5	%	42.6	%
International equities	10%-20%	16.1	%	13.9	%
Fixed income	10%-30%	14.9	%	18.6	%
Company stock	5%-15%	12.6	%	12.0	%
Other assets	5%-15%	9.9	%	12.9	%

At September 30, 2013 and 2012, the Plan held 1,169,700 shares of our common stock, which represented 12.6 percent and 12.0 percent of total Master Trust assets. These shares generated dividend income for the Plan of approximately $1.6 million and $1.6 million during fiscal 2013 and 2012.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the Plans were determined as of September 30, 2012, 2011 and 2010. These assumptions are presented in the following table:



	Pension Liability				Pension Cost
	2013		2012		2013		2012		2011
Discount rate	4.95	%	4.04	%	4.04	%	5.05	%	5.39	%	⁽¹⁾
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	4.00	%
Expected return on plan assets	7.25	%	7.75	%	7.75	%	7.75	%	8.25	%


⁽¹⁾	The discount rate for the Pension Account Plan increased from 5.39% to 5.68% effective January 1, 2011 due to a curtailment gain recorded in fiscal 2011.

The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2013 and 2012:



	2013			2012
	(In thousands)
Accumulated benefit obligation	$	446,133		$	468,440
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	480,031		$	429,432
Service cost	17,754			15,084
Interest cost	19,334			21,568
Actuarial (gain) loss	(29,822		)	46,197
Benefits paid	(25,073		)	(24,553		)
Divestitures	(6,425		)	(7,697		)
Benefit obligation at end of year	455,799			480,031
Change in plan assets:
Fair value of plan assets at beginning of year	343,144			280,204
Actual return on plan assets	52,496			48,656
Employer contributions	32,745			46,534
Benefits paid	(25,073		)	(24,553		)
Divestitures	(6,425		)	(7,697		)
Fair value of plan assets at end of year	396,887			343,144
Reconciliation:
Funded status	(58,912		)	(136,887		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Net amount recognized	$	(58,912	)	$	(136,887	)

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic pension cost for the Plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:



	Fiscal Year Ended September 30
	2013			2012			2011
	(In thousands)
Components of net periodic pension cost:
Service cost	$	17,754		$	15,084		$	14,384
Interest cost	19,334			21,568			22,264
Expected return on assets	(22,955		)	(21,474		)	(24,817		)
Amortization of prior service credit	(141		)	(141		)	(429		)
Recognized actuarial loss	19,066			14,451			9,498
Curtailment gain	—			—			(40		)
Net periodic pension cost	$	33,058		$	29,488		$	20,860

The following table sets forth by level, within the fair value hierarchy, the Master Trust’s assets at fair value as of September 30, 2013 and 2012. 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. Assets at September 30, 2012 include $7.7 million that were transferred to the purchaser of our Missouri, Illinois and Iowa operations during the first quarter of fiscal 2013. In addition to the assets shown below, the Master Trust had net accounts receivable of $0.4 million and $0.5 million at September 30, 2013 and 2012 which materially approximates fair value due to the short-term nature of these assets.



	Assets at Fair Value as of September 30, 2013
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks — domestic equities	$	143,543	$	—	$	—	$	143,543
Money market funds	—		12,266		—		12,266
Registered investment companies:
Domestic funds	30,200		—		—		30,200
International funds	47,036		—		—		47,036
Common/collective trusts — domestic funds	—		57,627		—		57,627
Government securities:
Mortgage-backed securities	—		18,446		—		18,446
U.S. treasuries	4,117		663		—		4,780
Corporate bonds	—		35,012		—		35,012
Limited partnerships	—		47,417		—		47,417
Real estate	—		—		155		155
Total investments at fair value	$	224,896	$	171,431	$	155	$	396,482

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Assets at Fair Value as of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Common stocks — domestic equities	$	114,799	$	—	$	—	$	114,799
Money market funds	—		21,010		—		21,010
Registered investment companies:
Domestic funds	19,984		—		—		19,984
International funds	36,714		—		—		36,714
Common/collective trusts — domestic funds	—		52,155		—		52,155
Government securities
Mortgage-backed securities	—		19,509		—		19,509
U.S. treasuries	7,597		487		—		8,084
Corporate bonds	—		35,960		—		35,960
Limited partnerships	140		41,786		—		41,926
Real estate	—		—		155		155
Total investments at fair value	$	179,234	$	170,907	$	155	$	350,296

The fair value of our Level 3 real estate assets was determined using a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land sales values per square foot in the range of $0.94 to $2.98 and comparable building sales values per square foot in the range of $23.13 to $30.42.

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 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.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Supplemental Executive Benefits Plan. In association with the retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.

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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2012, 2011 and 2010. These assumptions are presented in the following table:



	Pension Liability				Pension Cost
	2013		2012		2013			2012		2011
Discount rate	4.95	%	4.04	%	4.04	%	⁽¹⁾	5.05	%	5.39	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%		3.50	%	4.00	%


⁽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, 2013 and 2012:



	2013			2012
	(In thousands)
Accumulated benefit obligation	$	109,817		$	121,815
Change in projected benefit obligation:
Benefit obligation at beginning of year	$	130,186		$	112,115
Service cost	3,039			2,108
Interest cost	4,755			5,142
Actuarial (gain) loss	(6,451		)	15,459
Benefits paid	(4,375		)	(4,638		)
Settlements	(10,074		)	—
Benefit obligation at end of year	117,080			130,186
Change in plan assets:
Fair value of plan assets at beginning of year	—			—
Employer contribution	14,449			4,638
Benefits paid	(4,375		)	(4,638		)
Settlements	(10,074		)	—
Fair value of plan assets at end of year	—			—
Reconciliation:
Funded status	(117,080		)	(130,186		)
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued pension cost	$	(117,080	)	$	(130,186	)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2013 and 2012, assets held in the rabbi trusts consisted of available-for-sale securities of $44.5 million and $41.8 million, which are included in our fair value disclosures in Note 14.

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic pension cost for the supplemental plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:



	Fiscal Year Ended September 30
	2013		2012		2011
	(In thousands)
Components of net periodic pension cost:
Service cost	$	3,039	$	2,108	$	2,768
Interest cost	4,755		5,142		5,825
Amortization of transition asset	—		—		—
Amortization of prior service cost	—		—		—
Recognized actuarial loss	2,918		2,118		2,239
Settlements	3,160		—		—
Net periodic pension cost	$	13,872	$	9,368	$	10,832

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)
2014	$	40,640	$	22,940
2015	36,230		6,363
2016	34,752		6,226
2017	33,612		6,440
2018	33,273		6,913
2019-2023	156,367		34,260

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 will apply to all non-grandfathered participants will be determined using a new 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 $25 million and $30 million to our postretirement benefits plan during fiscal 2014.

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, 2013 and 2012.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Actual Allocation September 30
Security Class	2013		2012
Diversified investment funds	96.8	%	97.0	%
Cash and cash equivalents	3.2	%	3.0	%

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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2012, 2011 and 2010. The assumptions are presented in the following table:



	Postretirement Liability				Postretirement Cost
	2013		2012		2013		2012		2011
Discount rate	4.95	%	4.04	%	4.04	%	5.05	%	5.39	%
Expected return on plan assets	4.60	%	4.70	%	4.70	%	5.00	%	5.00	%
Initial trend rate	8.00	%	8.00	%	8.00	%	8.00	%	8.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%
Ultimate trend reached in	2020		2019		2019		2018		2016

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2013 and 2012:



	2013			2012
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	308,315		$	263,694
Service cost	18,800			16,353
Interest cost	12,964			13,861
Plan participants’ contributions	3,815			3,649
Actuarial (gain) loss	(13,801		)	28,815
Benefits paid	(14,458		)	(13,197		)
Divestitures	(3,487		)	(4,860		)
Benefit obligation at end of year	312,148			308,315
Change in plan assets:
Fair value of plan assets at beginning of year	77,072			53,065
Actual return on plan assets	13,432			12,912
Employer contributions	26,552			22,139
Plan participants’ contributions	3,815			3,649
Benefits paid	(14,458		)	(13,197		)
Divestitures	—			(1,496		)
Fair value of plan assets at end of year	106,413			77,072
Reconciliation:
Funded status	(205,735		)	(231,243		)
Unrecognized transition obligation	—			—
Unrecognized prior service cost	—			—
Unrecognized net loss	—			—
Accrued postretirement cost	$	(205,735	)	$	(231,243	)

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic postretirement cost for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the components presented below.



	Fiscal Year Ended September 30
	2013			2012			2011
	(In thousands)
Components of net periodic postretirement cost:
Service cost	$	18,800		$	16,353		$	14,403
Interest cost	12,964			13,861			12,813
Expected return on assets	(3,988		)	(2,607		)	(2,727		)
Amortization of transition obligation	1,081			1,511			1,511
Amortization of prior service credit	(1,450		)	(1,450		)	(1,450		)
Recognized actuarial loss	4,196			2,648			347
Net periodic postretirement cost	$	31,603		$	30,316		$	24,897

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	$	4,399	$	(3,682	)
Effect on postretirement benefit obligation	$	36,680	$	(30,940	)

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, 2013 and 2012. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2. Assets at September 30, 2012 include $1.5 million that were transferred to the purchaser of our Missouri, Illinois and Iowa operations during the first quarter of fiscal 2013.



	Assets at Fair Value as of September 30, 2013
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	3,356	$	—	$	3,356
Registered investment companies:
Domestic funds	9,614		—		—		9,614
International funds	93,443		—		—		93,443
Total investments at fair value	$	103,057	$	3,356	$	—	$	106,413

Table of Contents

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Assets at Fair Value as of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Investments:
Money market funds	$	—	$	2,360	$	—	$	2,360
Registered investment companies:
Domestic funds	7,756		—		—		7,756
International funds	68,452		—		—		68,452
Total investments at fair value	$	76,208	$	2,360	$	—	$	78,568

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		Retiree Payments		Subsidy Payments		Total Postretirement Benefits
	(In thousands)
2014	$	25,547	$	3,899	$	—	$	29,446
2015	16,628		4,915		—		21,543
2016	19,260		6,049		—		25,309
2017	21,216		7,304		—		28,520
2018	22,550		8,677		—		31,227
2019-2023	116,617		58,595		—		175,212

Defined Contribution Plans

As of September 30, 2013, we maintained three defined contribution benefit plans: the Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan), the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401K 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. In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Pension Account Plan to new participants effective October 1, 2010. New employees participate in our defined contribution plan, which was enhanced, effective January 1, 2011. Employees participating in the Pension Account Plan as of October 1, 2010 were allowed to make a one-time election to migrate from the Plan into the Retirement Savings Plan, effective January 1, 2011. Under the enhanced plan, 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.

The Union 401K Plan covers substantially all Mississippi Division employees who are members of the International Chemical Workers Union Council, United Food and Commercial Workers Union International (the Union) and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Employees of the Union automatically become participants of the Union 401K plan on the date of union membership. We match 50 percent of a participant’s contribution in cash, limited to six percent of the participant’s eligible contribution. Participants are also permitted to take out loans against their accounts subject to certain restrictions.

Matching contributions to the Retirement Savings Plan and the Union 401K Plan are expensed as incurred and amounted to $10.4 million, $10.5 million, and $10.2 million for fiscal years 2013, 2012 and 2011. The Board of Directors may also

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approve discretionary contributions, subject to the provisions of the Internal Revenue Code and applicable Treasury regulations. No discretionary contributions were made for fiscal years 2013, 2012 or 2011. At September 30, 2013 and 2012, the Retirement Savings Plan held 4.9 percent and 4.9 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, $1.2 million and $1.3 million for fiscal years 2013, 2012 and 2011.

7. Stock and Other Compensation Plans

Share Repurchase Agreement

On, July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman Sachs & Co. under which we repurchased $100 million of our outstanding common stock in order to offset stock grants made under our various employee and director incentive compensation plans. We paid $100 million to Goldman Sachs & Co. on July 7, 2010 in a share forward transaction and received 2,958,580 shares of Atmos Energy common stock. On March 4, 2011, we received and retired an additional 375,468 common shares which concluded our share repurchase agreement. In total, we received and retired 3,334,048 common shares under the repurchase agreement. The final number of shares we ultimately repurchased in the transaction was based generally on the average of the effective share repurchase price of our common stock over the duration of the agreement, which was $29.99. As a result of this transaction, beginning in our fourth quarter of fiscal 2010, the number of outstanding shares used to calculate our earnings per share was reduced by the number of shares received and the $100 million purchase price was recorded as a reduction in shareholders’ equity.

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, 2013, a total of 387,991 shares had been repurchased for an aggregate value of $12.5 million.

Stock-Based Compensation Plans

Total stock-based compensation expense was $17.8 million, $19.2 million and $11.6 million for the fiscal years ended September 30, 2013, 2012 and 2011, 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, 2013, 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, 2013, 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 1,403,439 shares were available for future issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years. However, no stock options have been granted under this plan since fiscal 2003, except for a limited number of options that were converted from bonuses paid under our Annual Incentive Plan, the last of which occurred in fiscal 2006. We had 7,930 stock options outstanding at September 30, 2013 at a $25.96 weighted average exercise price that are currently vested and expire in November 2014.

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Restricted Stock 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 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 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 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) and a performance condition based on a cumulative earnings per share target amount.

The following summarizes information regarding the restricted stock issued under the plan during the fiscal years ended September 30, 2013, 2012 and 2011:



	2013				2012				2011
	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Number of Restricted Shares		Weighted Average Grant-Date Fair Value
Nonvested at beginning of year	1,262,582		$	32.46	1,264,142		$	29.56	1,293,960		$	27.28
Granted	473,775		40.48		532,711		33.44		491,345		33.10
Vested	(657,795	)	32.20		(494,308	)	26.32		(464,321	)	27.21
Forfeited	(25,718	)	33.42		(39,963	)	29.83		(56,842	)	27.56
Nonvested at end of year	1,052,844		$	36.20	1,262,582		$	32.46	1,264,142		$	29.56

As of September 30, 2013, there was $5.1 million of total unrecognized compensation cost related to nonvested time-lapse restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2013, 2012 and 2011 was $21.2 million, $13.0 million and $12.6 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.

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

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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, invest deferred compensation into either a cash account or a stock account and to receive an annual grant of share units for each year of service on the Board.

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.

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, 2013 and 2012:



	September 30
	2013			2012
	(In thousands)
Billed accounts receivable	$	230,712		$	177,953
Unbilled revenue	58,710			42,694
Other accounts receivable	33,194			23,304
Total accounts receivable	322,616			243,951
Less: allowance for doubtful accounts	(20,624		)	(9,425		)
Net accounts receivable	$	301,992		$	234,526

Other current assets

Other current assets as of September 30, 2013 and 2012 were comprised of the following accounts.



	September 30
	2013		2012
	(In thousands)
Assets from risk management activities	$	18,099	$	24,707
Deferred gas costs	15,152		31,359
Taxes receivable	3,141		1,291
Current deferred tax asset	—		27,091
Prepaid expenses	21,666		17,114
Materials and supplies	5,511		5,872
Assets held for sale⁽¹⁾	—		154,571
Other	6,765		10,777
Total	$	70,334	$	272,782

⁽¹⁾As discussed in Note 16, assets and liabilities related to our Georgia operations were classified as “assets held for sale” in other current assets and liabilities in our consolidated balance sheets at September 30, 2012.

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Property, plant and equipment

Property, plant and equipment was comprised of the following as of September 30, 2013 and 2012:



	September 30
	2013			2012
	(In thousands)
Production plant	$	5,020		$	5,020
Storage plant	262,246			232,260
Transmission plant	1,362,662			1,185,007
Distribution plant	5,061,711			4,680,877
General plant	716,189			717,568
Intangible plant	38,444			39,626
	7,446,272			6,860,358
Construction in progress	275,747			274,112
	7,722,019			7,134,470
Less: accumulated depreciation and amortization	(1,691,364		)	(1,658,866		)
Net property, plant and equipment⁽¹⁾	$	6,030,655		$	5,475,604


⁽¹⁾	Net property, plant and equipment includes plant acquisition adjustments of ($83.8) million and ($91.5) million at September 30, 2013 and 2012.

Goodwill

The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2013:



	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated		Total
	(In thousands)
Balance as of September 30, 2012	$	573,550	$	132,422	$	34,711	$	740,683
Deferred tax adjustments on prior acquisitions⁽¹⁾	640		40		—		680
Balance as of September 30, 2013	$	574,190	$	132,462	$	34,711	$	741,363


⁽¹⁾	During the preparation of the fiscal 2013 tax provision, we adjusted 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

Deferred charges and other assets as of September 30, 2013 and 2012 were comprised of the following accounts.



	September 30
	2013		2012
	(In thousands)
Marketable securities	$	72,682	$	64,398
Regulatory assets	273,287		358,495
Deferred financing costs	15,199		11,157
Assets from risk management activities	109,354		2,283
Other	14,474		14,929
Total	$	484,996	$	451,262

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Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.



	September 30
	2013		2012
	(In thousands)
Trade accounts payable	$	70,116	$	82,531
Accrued gas payable	121,202		81,658
Accrued liabilities	50,293		51,040
Total	$	241,611	$	215,229

Other current liabilities

Other current liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.



	September 30
	2013		2012
	(In thousands)
Customer credit balances and deposits	$	76,313	$	100,926
Accrued employee costs	54,034		37,675
Deferred gas costs	16,481		23,072
Accrued interest	36,744		34,451
Liabilities from risk management activities	1,543		85,381
Taxes payable	66,960		64,319
Pension and postretirement obligations	22,940		39,625
Current deferred tax liability	14,697		—
Regulatory cost of removal accrual	68,225		78,525
Liabilities held for sale	—		11,573
Other	10,954		14,118
Total	$	368,891	$	489,665

Deferred credits and other liabilities

Deferred credits and other liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.



	September 30
	2013		2012
	(In thousands)
Customer advances for construction	$	11,723	$	12,937
Regulatory liabilities	1,123		5,638
Asset retirement obligation	6,764		10,394
Liabilities from risk management activities	6,133		9,206
Other	17,953		12,555
Total	$	43,696	$	50,730

9. Leases

Capital and Operating 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 21 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. We have also entered into capital leases for division offices and operating facilities. Property, plant and equipment included amounts for capital leases of $1.3 million at September 30, 2013 and 2012. Accumulated depreciation for these capital leases totaled $1.0 million and $0.9 million at

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September 30, 2013 and 2012. Depreciation expense for these assets is included in consolidated depreciation expense on the consolidated statement of income.

The related future minimum lease payments at September 30, 2013 were as follows:



	Capital Leases		Operating Leases
	(In thousands)
2014	$	186	$	16,722
2015	186		15,584
2016	186		14,692
2017	186		15,074
2018	78		15,057
Thereafter	—		89,673
Total minimum lease payments	822		$	166,802
Less amount representing interest	198
Present value of net minimum lease payments	$	624

Consolidated lease and rental expense amounted to $32.4 million, $33.6 million and $35.5 million for fiscal 2013, 2012 and 2011.

10. Commitments and Contingencies

Litigation

Since April 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.

Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.

During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.

A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals (Court), appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments were held in the case on August 27, 2012.

In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.

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The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and to the landowners’ motion on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have been engaged in discovery activities in this case.

Tennessee Business License Tax

Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. The Company anticipates a decision by the Chancery Court on the remaining issues in fiscal 2014. AEM has been assessed $6.1 million in business taxes and $3.7 million in penalties and interest for the period from December 2002 through March 31, 2012. We have accrued what we believe to be an adequate amount for the anticipated resolution of this matter and we will continue to review and if appropriate adjust this reserve until this matter is resolved. We continue to believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

We are a party to other litigation and claims that have arisen in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims 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 natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. At September 30, 2013, the estimated commitments under these contracts are $230.5 million for fiscal 2014.

Our nonregulated segment has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2013, we were committed to purchase 78.0 Bcf within one year, 21.9 Bcf within one to three years and 1.0 Bcf after three years under indexed contracts. We are committed to purchase 6.1 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $3.32 to $6.36 per Mcf. Purchases under these contracts totaled $1,246.1 million, $978.8 million and $1,498.6 million for 2013, 2012 and 2011.

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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, 2013 are as follows (in thousands):



2014	$	12,662
2015	5,113
2016	743
2017	170
2018	142
Thereafter	356
	$	19,186

Other Contingencies

In December 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines.

The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission’s findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company paid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company’s financial position, results of operations or cash flows and none of the payments were charged to any of the Company’s customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.

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.

11. Income Taxes

The components of income tax expense from continuing operations for 2013, 2012 and 2011 were as follows:



	2013			2012			2011
	(In thousands)
Current
Federal	$	—		$	631		$	(13,298	)
State	8,178			6,888			6,841
Deferred
Federal	124,836			103,971			107,950
State	9,605			(13,237		)	5,498
Investment tax credits	(20		)	(27		)	(172		)
	$	142,599		$	98,226		$	106,819

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2013, 2012 and 2011 are set forth below:



	2013			2012			2011
	(In thousands)
Tax at statutory rate of 35%	$	130,655		$	101,648		$	103,743
Common stock dividends deductible for tax reporting	(2,153		)	(2,096		)	(1,930		)
Penalties	153			66			2,292
Recognition (settlement) of uncertain tax positions	1,341			1,831			(4,950		)
State taxes (net of federal benefit)	10,687			(5,958		)	8,109
Other, net	1,916			2,735			(445		)
Income tax expense	$	142,599		$	98,226		$	106,819

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, 2013 and 2012 are presented below:



	2013			2012
	(In thousands)
Deferred tax assets:
Accruals not currently deductible for tax purposes	$	11,496		$	7,906
Customer advances	4,279			4,721
Nonqualified benefit plans	52,051			48,513
Postretirement benefits	63,919			62,802
Treasury lock agreements	—			25,448
Unamortized investment tax credit	6			14
Tax net operating loss and credit carryforwards	206,996			164,419
Difference between book and tax on mark to market accounting	2,271			2,342
Other, net	—			7,223
Total deferred tax assets	341,018			323,388
Deferred tax liabilities:
Difference in net book value and net tax value of assets	(1,445,450		)	(1,254,698		)
Pension funding	(23,480		)	(32,812		)
Gas cost adjustments	(19,182		)	(21,806		)
Interest rate agreements	(21,726		)	—
Cost expensed for tax purposes and capitalized for book purposes	(2,815		)	(2,065		)
Other, net	(7,115		)	—
Total deferred tax liabilities	(1,519,768		)	(1,311,381		)
Net deferred tax liabilities	$	(1,178,750	)	$	(987,993	)
Deferred credits for rate regulated entities	$	(51	)	$	140

At September 30, 2013, we had $10.1 million of federal alternative minimum tax credit carryforwards, $185.3 million of federal net operating loss carryforwards, $11.0 million of state net operating loss carryforwards and $0.6 million of state tax credits. The alternative minimum tax credit carryforwards do not expire. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. Depending on the jurisdiction in which the state net operating loss was generated, the state net operating loss carryforwards will begin to expire between 2016 and 2030. The state tax credits will begin to expire in 2018. We believe it is more likely than not that the benefit from certain charitable contribution carryforwards will not be realized. In recognition of this risk, we have established a valuation allowance of $1.1 million for deferred tax assets relating to these charitable contribution carryforwards.

At September 30, 2013, we had recorded liabilities associated with uncertain tax positions totaling $3.2 million. The realization of these tax benefits would reduce our income tax expense by approximately $3.2 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $13.6 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.

At September 30, 2010, we had accrued liabilities associated with uncertain tax positions totaling $6.7 million. During the fiscal year ended September 30, 2011, the IRS completed its audit of fiscal years 2005-2007. All uncertain tax positions were effectively settled upon completion of the audit. As a result of the settlement, we reduced our unrecognized tax benefits by $6.7 million in the second quarter of fiscal 2011. Income tax expense was reduced by $5.0 million in the second quarter due to the realization of the tax positions which were previously uncertain.

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 natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit-risk-related or other contingent features that could cause 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, 2013 and 2012:



	Natural Gas Distribution			Nonregulated			Total
	(In thousands)
September 30, 2013
Assets from risk management activities, current⁽¹⁾	$	1,837		$	16,262		$	18,099
Assets from risk management activities, noncurrent	109,354			—			109,354
Liabilities from risk management activities, current⁽¹⁾	(1,543		)	—			(1,543		)
Liabilities from risk management activities, noncurrent	—			(6,133		)	(6,133		)
Net assets (liabilities)	$	109,648		$	10,129		$	119,777
September 30, 2012⁽³⁾
Assets from risk management activities, current⁽²⁾	$	6,934		$	17,773		$	24,707
Assets from risk management activities, noncurrent	2,283			—			2,283
Liabilities from risk management activities, current⁽²⁾	(85,366		)	(15		)	(85,381		)
Liabilities from risk management activities, noncurrent	—			(9,206		)	(9,206		)
Net assets (liabilities)	$	(76,149	)	$	8,552		$	(67,597	)


⁽¹⁾	Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.


⁽²⁾	Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.


⁽³⁾	The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.

Regulated Commodity Risk Management Activities

Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through

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a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 22.8 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $4.03 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.

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 deliver gas to customers. These financial instruments have maturity dates ranging from one to 55 months. We use financial instruments, designated as fair value hedges, to hedge natural gas inventory used in these operations. We also use storage and basis swaps, futures and various over-the-counter and exchange-traded options primarily to protect the economic value of our fixed price and storage books. These financial instruments have not been designated as hedges.

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, 2013, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 Bcf.

Interest Rate Risk Management Activities

We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used Treasury locks to mitigate interest rate risk; however, in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.

In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million out of a total $500 million of senior notes that were issued on January 11, 2013. This offering is discussed in Note 5. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with a payment of $66.6 million to the counterparties due to a decrease in the 30-year Treasury rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.6 million unrealized loss 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In the fourth quarter of fiscal 2012 we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility through December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated 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.

In September 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $300 million of a total $400 million of senior notes that were issued in June 2011. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the net $12.6 million unrealized 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.

Additionally, our original fiscal 2011 financing plans included the issuance of $250 million of 30-year unsecured notes in November 2011 to fund our capital expenditure program. In September 2010, we entered into two Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuance of these senior notes, which were designated as cash flow hedges. Due primarily to stronger than anticipated cash flows primarily resulting from the extension of the Bush tax cuts that allow the continued use of bonus depreciation on qualifying expenditures through December 31, 2011, the need to issue $250 million of debt in November was eliminated and the related Treasury lock agreements were unwound in March 2011. As a result of unwinding these Treasury locks, we recognized a pre-tax cash gain of $27.8 million during the second quarter of fiscal 2011.

In prior years, 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 2043.

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, 2013, 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, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:



Contract Type	Hedge Designation	Natural Gas Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(13,033	)
	Cash Flow	—	31,195
	Not designated	29,185	75,683
		29,185	93,845

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, 2013 and 2012. As required by authoritative accounting literature, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $24.8 million and $23.7 million of cash held on deposit in margin accounts as of September 30, 2013 and 2012 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

not be equal to the amounts presented on our consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 14.



	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
September 30, 2013
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	9,094		$	9,094
Noncurrent commodity contracts	Deferred charges and other assets	107,512			416			107,928
Liability Financial Instruments
Current commodity contracts	Other current liabilities	—			(12,173		)	(12,173		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(1,639		)	(1,639		)
Total		107,512			(4,302		)	103,210
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	1,837			65,388			67,225
Noncurrent commodity contracts	Deferred charges and other assets	1,842			40,982			42,824
Liability Financial Instruments
Current commodity contracts	Other current liabilities	(1,543		)	(70,876		)	(72,419		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(45,892		)	(45,892		)
Total		2,136			(10,398		)	(8,262		)
Total Financial Instruments		$	109,648		$	(14,700	)	$	94,948



	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
		(In thousands)
September 30, 2012
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	19,301		$	19,301
Noncurrent commodity contracts	Deferred charges and other assets	—			1,923			1,923
Liability Financial Instruments
Current commodity contracts	Other current liabilities	(85,040		)	(23,787		)	(108,827		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(4,999		)	(4,999		)
Total		(85,040		)	(7,562		)	(92,602		)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets⁽¹⁾	7,082			98,393			105,475
Noncurrent commodity contracts	Deferred charges and other assets	2,283			60,932			63,215
Liability Financial Instruments
Current commodity contracts	Other current liabilities⁽²⁾	(585		)	(99,824		)	(100,409		)
Noncurrent commodity contracts	Deferred credits and other liabilities	—			(67,062		)	(67,062		)
Total		8,780			(7,561		)	1,219
Total Financial Instruments		$	(76,260	)	$	(15,123	)	$	(91,383	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


⁽¹⁾	Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.


⁽²⁾	Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the years ended September 30, 2013, 2012 and 2011, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $18.2 million, $23.1 million and $24.8 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, 2013, 2012 and 2011 is presented below.



	Fiscal Year Ended September 30
	2013			2012			2011
	(In thousands)
Commodity contracts	$	2,165		$	30,266		$	16,552
Fair value adjustment for natural gas inventory designated as the hedged item	15,938			(5,797		)	9,824
Total decrease in purchased gas cost	$	18,103		$	24,469		$	26,376
The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(208	)	$	1,170		$	803
Timing ineffectiveness	18,311			23,299			25,573
	$	18,103		$	24,469		$	26,376

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. During the year ended September 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market. We did not record a writedown for nonqualifying natural gas inventory for the years ended September 30, 2013 and 2011.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges

The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2013, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



	Fiscal Year Ended September 30, 2013
	Natural Gas Distribution			Regulated Transmission and Storage		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	)



	Fiscal Year Ended September 30, 2012
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	—	$	(62,678	)	$	(62,678	)
Loss arising from ineffective portion of commodity contracts	—			—		(1,369		)	(1,369		)
Total impact on purchased gas cost	—			—		(64,047		)	(64,047		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(2,009		)	—		—			(2,009		)
Total impact from cash flow hedges	$	(2,009	)	$	—	$	(64,047	)	$	(66,056	)



	Fiscal Year Ended September 30, 2011
	Natural Gas Distribution			Regulated Transmission and Storage		Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	—	$	(28,430	)	$	(28,430	)
Loss arising from ineffective portion of commodity contracts	—			—		(1,585		)	(1,585		)
Total impact on purchased gas cost	—			—		(30,015		)	(30,015		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(2,455		)	—		—			(2,455		)
Gain on unwinding of interest rate agreement reclassified from AOCI into miscellaneous income	21,803			6,000		—			27,803
Total impact from cash flow hedges	$	19,348		$	6,000	$	(30,015	)	$	(4,667	)

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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, 2013 and 2012. 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
	2013			2012
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	79,963		$	(11,458	)
Forward commodity contracts	(2,057		)	(30,366		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	2,216			1,342
Forward commodity contracts	6,576			38,232
Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	86,698		$	(2,250	)


⁽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, 2013. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 as those financial instruments have not yet settled.



	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
2014	$	(2,686	)	$	(3,748	)	$	(6,434	)
2015	(804		)	(425		)	(1,229		)
2016	(634		)	(163		)	(797		)
2017	(735		)	(109		)	(844		)
2018	(936		)	(31		)	(967		)
Thereafter	(24,569		)	—			(24,569		)
Total⁽¹⁾	$	(30,364	)	$	(4,476	)	$	(34,840	)


⁽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, 2013, 2012 and 2011 was an increase (decrease) in purchased gas cost of $3.0 million, $(2.5) million and $(1.4) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

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

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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 table provides 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, 2012	$	5,661		$	(44,273	)	$	(8,995	)	$	(47,607	)
Other comprehensive income before reclassifications	1,162			79,963			(2,057		)	79,068
Amounts reclassified from accumulated other comprehensive income	(1,375		)	2,216			6,576			7,417
Net current-period other comprehensive income (loss)	(213		)	82,179			4,519			86,485
September 30, 2013	$	5,448		$	37,906		$	(4,476	)	$	38,878

The following table details reclassifications out of AOCI for the fiscal year ended September 30, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.



	Fiscal Year Ended September 30, 2013
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	$	2,166		Operation and maintenance expense
	2,166			Total before tax
	(791		)	Tax expense
	$	1,375		Net of tax
Cash flow hedges
Interest rate agreements	$	(3,489	)	Interest charges
Commodity contracts	(10,778		)	Purchased gas cost
	(14,267		)	Total before tax
	5,475			Tax benefit
	$	(8,792	)	Net of tax
Total reclassifications	$	(7,417	)	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.

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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, 2013 and 2012. 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, 2013
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	111,191	$	—	$	—		$	111,191
Nonregulated segment	745		115,135		—		(99,618		)	16,262
Total financial instruments	745		226,326		—		(99,618		)	127,453
Hedged portion of gas stored underground	44,758		—		—		—			44,758
Available-for-sale securities
Money market funds	—		4,428		—		—			4,428
Registered investment companies	40,094		—		—		—			40,094
Bonds	—		28,160		—		—			28,160
Total available-for-sale securities	40,094		32,588		—		—			72,682
Total assets	$	85,597	$	258,914	$	—	$	(99,618	)	$	244,893
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	1,543	$	—	$	—		$	1,543
Nonregulated segment	158		130,422		—		(124,447		)	6,133
Total liabilities	$	158	$	131,965	$	—	$	(124,447	)	$	7,676

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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, 2012
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	9,365	$	—	$	—		$	9,365
Nonregulated segment	714		179,835		—		(162,776		)	17,773
Total financial instruments	714		189,200		—		(162,776		)	27,138
Hedged portion of gas stored underground	67,192		—		—		—			67,192
Available-for-sale securities
Money market funds	—		1,634		—		—			1,634
Registered investment companies	40,212		—		—		—			40,212
Bonds	—		22,552		—		—			22,552
Total available-for-sale securities	40,212		24,186		—		—			64,398
Total assets	$	108,118	$	213,386	$	—	$	(162,776	)	$	158,728
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	85,625	$	—	$	—		$	85,625
Nonregulated segment	4,563		191,109		—		(186,451		)	9,221
Total liabilities	$	4,563	$	276,734	$	—	$	(186,451	)	$	94,846

⁽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, 2013 we had $24.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting agreements and the remaining $16.2 million is classified as current risk management assets.

⁽³⁾

This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting agreements and the remaining $17.8 million is classified as current risk management assets.

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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, 2013
Domestic equity mutual funds	$	27,043	$	7,476	$	(23	)	$	34,496
Foreign equity mutual funds	4,536		1,062		—			5,598
Bonds	28,016		168		(24		)	28,160
Money market funds	4,428		—		—			4,428
	$	64,023	$	8,706	$	(47	)	$	72,682
As of September 30, 2012
Domestic equity mutual funds	$	25,779	$	8,183	$	—		$	33,962
Foreign equity mutual funds	5,568		682		—			6,250
Bonds	22,358		196		(2		)	22,552
Money market funds	1,634		—		—			1,634
	$	55,339	$	9,061	$	(2	)	$	64,398

At September 30, 2013 and 2012, our available-for-sale securities included $44.5 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 6. At September 30, 2013 we maintained investments in bonds that have contractual maturity dates ranging from October 2013 through December 2019. During the year ended September 30, 2013, we recognized a net gain of $2.2 million on the sale of certain assets in the rabbi trusts.

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.

Atmos Gathering Company (AGC) owns and operates the Park City and Shrewsbury gathering systems in Kentucky. The Park City gathering system consists of a 23-mile low pressure pipeline and a nitrogen removal unit that was constructed in 2008. The Shrewsbury production, gathering and processing assets were acquired in 2008 at which time we sold the production assets to a third party. As a result of the sale of the production assets, we obtained a 10-year production payment note under which we were to be paid from future production generated from the assets.

As discussed in Note 10, AGC is involved in an ongoing lawsuit with the Park City gathering system. Due to the lawsuit and a low natural gas price environment, the assets have generated operating losses. As a result of these developments, in fiscal 2011, we performed an impairment assessment of these assets and determined the assets to be impaired at which time we recorded a pre-tax noncash impairment loss of approximately $11 million. Due to developments in the fourth quarter of fiscal 2012, including further operating losses as a result of the lawsuit and management’s decision to focus our nonregulated operations on delivered gas and transportation services, we performed an impairment assessment of these assets and determined the assets to be further impaired. We reduced the carrying value of the assets to their estimated fair value of approximately $0.5 million and recorded a pre-tax noncash impairment loss of approximately $5.3 million. We used a combination of a market and income approach in a weighted average discounted cash flow analysis that included significant inputs such as our weighted average cost of capital and assumptions regarding future natural gas prices. This is a Level 3 fair value measurement because the inputs used are unobservable. Based on this analysis, we determined the assets to be impaired.

In February 2008, Atmos Pipeline and Storage, LLC, a subsidiary of AEH, announced plans to construct and operate a salt-cavern storage project in Franklin Parish, Louisiana. In March 2010, we entered into an option and acquisition agreement with a third party, which provided the third party with the exclusive option to develop the proposed Fort Necessity salt-dome natural gas storage project. In July 2010, we agreed with the third party to extend the option period to March 2011. In January 2011, the third party developer notified us that it did not plan to commence the activities required to allow it to exercise the option by March 2011; accordingly, the option was terminated. We evaluated our strategic alternatives and concluded the

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

project’s returns did not meet our investment objectives. Accordingly, in March 2011, we recorded a $19.3 million pre-tax noncash impairment loss to write off substantially all of our investment in the project.

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, 2013:



	September 30, 2013
	(In thousands)
Carrying Amount	$	2,460,000
Fair Value	$	2,676,487

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 natural gas 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.

16. Discontinued Operations

On April 1, 2013, we completed the sale of substantially all of our natural gas 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.

On August 1, 2012, we completed the sale of substantially all of our natural gas distribution assets located in Missouri, Illinois and Iowa to Liberty Energy (Midstates) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $128 million, pursuant to an asset purchase agreement executed on May 12, 2011. In connection with the sale, we recognized a pre-tax gain of approximately $9.9 million.

As required under generally accepted accounting principles, the operating results of our Georgia, Missouri, Illinois and Iowa operations 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 tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations.

The following table presents statement of income data related to discontinued operations in our Georgia, Missouri, Illinois and Iowa service areas.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Year Ended September 30
	2013		2012		2011
	(In thousands)
Operating revenues	$	37,962	$	114,703	$	141,227
Purchased gas cost	21,464		62,902		83,537
Gross profit	16,498		51,801		57,690
Operating expenses	5,858		24,174		27,362
Operating income	10,640		27,627		30,328
Other nonoperating income	548		611		57
Income from discontinued operations before income taxes	11,188		28,238		30,385
Income tax expense	3,986		10,066		12,372
Income from discontinued operations	7,202		18,172		18,013
Gain on sale of discontinued operations, net of tax	5,294		6,349		—
Net income from discontinued operations	$	12,496	$	24,521	$	18,013

The following table presents balance sheet data related to assets held for sale. At September 30, 2013 we did not have any assets or liabilities held for sale. At September 30, 2012 assets held for sale include assets and liabilities associated with our Georgia operations.



	September 30, 2012
	(In thousands)
Net plant, property & equipment	$	142,865
Gas stored underground	4,688
Other current assets	6,931
Deferred charges and other assets	87
Assets held for sale	$	154,571
Accounts payable and accrued liabilities	$	2,114
Other current liabilities	3,776
Regulatory cost of removal	3,257
Deferred credits and other liabilities	2,426
Liabilities held for sale	$	11,573

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.

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2013:
Operating revenues
Natural gas distribution	$	666,787		$	905,176		$	467,144		$	360,386
Regulated transmission and storage	60,681			61,848			74,041			72,330
Nonregulated	399,894			428,948			421,808			348,061
Intersegment eliminations	(93,207		)	(86,976		)	(105,058		)	(95,606		)
	1,034,155			1,308,996			857,935			685,171
Gross profit	362,362			432,751			316,497			300,440
Operating income	154,922			210,178			86,396			50,383
Income from continuing operations	77,348			112,340			33,474			7,536
Income from discontinued operations	3,117			4,085			—			—
Gain on sale of discontinued operations	—			—			5,294			—
Net income	80,465			116,425			38,768			7,536
Basic earnings per share
Income per share from continuing operations	$	0.85		$	1.24		$	0.37		$	0.08
Income per share from discontinued operations	$	0.04		$	0.04		$	0.06		$	—
Net income per share — basic	$	0.89		$	1.28		$	0.43		$	0.08
Diluted earnings per share
Income per share from continuing operations	$	0.85		$	1.23		$	0.36		$	0.08
Income per share from discontinued operations	$	0.03		$	0.04		$	0.06		$	—
Net income per share — diluted	$	0.88		$	1.27		$	0.42		$	0.08

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Quarter Ended
	December 31			March 31			June 30			September 30
	(In thousands, except per share data)
Fiscal year 2012:
Operating revenues
Natural gas distribution	$	676,113		$	871,067		$	315,634		$	282,516
Regulated transmission and storage	56,759			58,037			67,073			65,482
Nonregulated	444,176			370,763			256,250			280,114
Intersegment eliminations	(93,054		)	(74,358		)	(62,543		)	(75,546		)
	1,083,994			1,225,509			576,414			552,566
Gross profit	355,392			425,787			293,171			249,389
Operating income	139,471			202,432			81,546			22,791
Income (loss) from continuing operations	62,384			102,084			28,014			(286		)
Income from discontinued operations	6,123			7,027			3,118			1,904
Gain on sale of discontinued operations	—			—			—			6,349
Net income	68,507			109,111			31,132			7,967
Basic earnings per share
Income per share from continuing operations	$	0.68		$	1.12		$	0.31		$	—
Income per share from discontinued operations	$	0.07		0.08			$	0.03		$	0.09
Net income per share — basic	$	0.75		$	1.20		$	0.34		$	0.09
Diluted earnings per share
Income per share from continuing operations	$	0.68		$	1.12		$	0.31		$	—
Income per share from discontinued operations	$	0.07		$	0.08		$	0.03		$	0.09
Net income per share — diluted	$	0.75		$	1.20		$	0.34		$	0.09

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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, 2013 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 (1992 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, 2013, 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
President and Chief Executive Officer		Senior Vice President and Chief Financial Officer

November 13, 2013

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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, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 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, 2013, 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, 2013 and 2012, 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, 2013 of Atmos Energy Corporation and our report dated November 13, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Dallas, Texas

November 13, 2013

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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, 2013 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 5, 2014. Information regarding executive officers is reported below:

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2013, 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	62	7	President and Chief Executive Officer
Bret J. Eckert	46	1	Senior Vice President and Chief Financial Officer
Marvin L. Sweetin	50	13	Senior Vice President, Utility Operations
Louis P. Gregory	58	13	Senior Vice President, General Counsel and Corporate Secretary
Michael E. Haefner	53	5	Senior Vice President, Human Resources

Kim R. Cocklin was named President and 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.

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 is responsible for the operations of our six utility divisions, as well as customer service, safety and training. Mr. Sweetin joined the Company in May 2000 and served in a variety of leadership positions with responsibility for procurement, customer service, training and safety.

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

Michael E. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources.

Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors’ determination as to whether one or more audit committee financial experts are serving on the Audit Committee of the Board of Directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2014.

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.”

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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 5, 2014.



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 5, 2014. 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 5, 2014.



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 5, 2014.

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 10.4(a) through 10.13.(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 13, 2013

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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	President, Chief Executive Officer and Director	November 13, 2013
Kim R. Cocklin	President, Chief Executive Officer and Director

/s/ BRET J. ECKERT	Senior Vice President and Chief Financial Officer	November 13, 2013
Bret J. Eckert	Senior Vice President and Chief Financial Officer

/s/ CHRISTOPHER T. FORSYTHE	Vice President and Controller (Principal Accounting Officer)	November 13, 2013
Christopher T. Forsythe

/s/ ROBERT W. BEST	Chairman of the Board	November 13, 2013
Robert W. Best

/s/ RICHARD W. DOUGLAS	Director	November 13, 2013
Richard W. Douglas

/s/ RUBEN E. ESQUIVEL	Director	November 13, 2013
Ruben E. Esquivel

/s/ RICHARD K. GORDON	Director	November 13, 2013
Richard K. Gordon

/s/ ROBERT C. GRABLE	Director	November 13, 2013
Robert C. Grable

/s/ THOMAS C. MEREDITH	Director	November 13, 2013
Thomas C. Meredith

/s/ NANCY K. QUINN	Director	November 13, 2013
Nancy K. Quinn

/s/ RICHARD A. SAMPSON	Director	November 13, 2013
Richard A. Sampson

/s/ STEPHEN R. SPRINGER	Director	November 13, 2013
Stephen R. Springer

/s/ RICHARD WARE II	Director	November 13, 2013
Richard Ware II

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Schedule II

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2013



			Additions
	Balance at beginning of period		Charged to cost & expenses		Charged to other accounts		Deductions			Balance at end of period
			(In thousands)
2013
Allowance for doubtful accounts	$	9,425	$	14,484	$	—	$	3,285	⁽¹⁾	$	20,624
2012
Allowance for doubtful accounts	$	7,440	$	8,901	$	—	$	6,916	⁽¹⁾	$	9,425
2011
Allowance for doubtful accounts	$	12,701	$	2,201	$	—	$	7,462	⁽¹⁾	$	7,440


⁽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(a)	Asset Purchase Agreement by and between Atmos Energy Corporation as Seller and Liberty Energy (Midstates) Corp. as Buyer, dated as of May 12, 2011	Exhibit 2.1 to Form 8-K dated May 12, 2011 (File No. 1-10042)
2.1(b)	Amendment No. 1 to Asset Purchase Agreement	Exhibit 2.1(b) to Form 10-K for fiscal year ended September 30, 2012 (File No. 1-10042)
2.2	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 February 3, 2010)	Exhibit 3.2 to Form 8-K dated February 3, 2010 (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 4.95% Senior Notes due 2014	Exhibit 10(2)(f) to Form 10-K for fiscal year ended September 30, 2004 (File No. 1-10042)

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4.7(c)	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(d)	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(e)	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(f)	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)
4.7(g)	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)
	Material Contracts
10.1(a)	Revolving Credit Agreement, dated as of May 2, 2011 among Atmos Energy Corporation, the Lenders from time to time parties thereto, The Royal Bank of Scotland plc as Administrative Agent, Crédit Agricole Corporate and Investment Bank as Syndication Agent, Bank of America, N.A., U.S. Bank National Association and Wells Fargo Bank, N.A. as Co-Documentation Agents	Exhibit 10.1 to Form 8-K dated May 2, 2011 (File No. 1-10042)
10.1(b)	Second Amendment to Revolving Credit Agreement, made and entered into as of December 7, 2012, by and among Atmos Energy Corporation, a Texas and Virginia corporation, the several banks and other financial institutions from time to time party thereto (the “Lenders”) and The Royal Bank of Scotland plc, in its capacity as Administrative Agent for the Lenders	Exhibit 10.1 to Form 8-K dated December 5, 2012 (File No. 1-10042)
10.1(c)	Third Amendment to Revolving Credit Agreement, made and entered into as of August 22, 2013, by and among Atmos Energy Corporation, a Texas and Virginia corporation, the several banks and other financial institutions from time to time party thereto (the “Lenders”) and The Royal Bank of Scotland plc, in its capacity as Administrative Agent for the Lenders	Exhibit 10.1 to Form 8-K dated August 22, 2013 (File No. 1-10042)
10.2(a)	Accelerated Share Buyback Agreement with Goldman, Sachs & Co. - Master Confirmation dated July 1, 2010	Exhibit 10.6(a) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.2(b)	Accelerated Share Buyback Agreement with Goldman, Sachs & Co. - Supplemental Confirmation dated July 1, 2010	Exhibit 10.6(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.3(a)	Guaranty of Algonquin Power & Utilities Corp. dated May 12, 2011	Exhibit 10.1 to Form 8-K dated May 12, 2011 (File No. 1-10042)
10.3(b)	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
10.4(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)
10.4(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)

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10.5(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)
10.5(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)
10.6(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)
10.6(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)
10.6(c)*	Amendment No 2 to the Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 10, 2011)
10.7(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)
10.7(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)
10.8(a)*	Atmos Energy Corporation Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of November 12, 2009)	Exhibit 10.10(b) to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.8(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)
10.9*	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)
10.10(a)*	Mini-Med/Dental Benefit Extension Agreement dated October 1, 1994	Exhibit 10.28(f) to Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042)
10.10(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)
10.10(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)
10.11*	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)
10.12*	Atmos Energy Corporation Outside Directors Stock-for-Fee Plan, Amended and Restated as of October 1, 2009	Exhibit 10.13 to Form 10-K for fiscal year ended September 30, 2010 (File No. 1-10042)
10.13(a)*	Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated February 10, 2011)	Exhibit 99.1 to Form S-8 dated October 28, 2011 (File No. 333-177593)
10.13(b)*	Form of Award Agreement of Time-Lapse Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan
10.13(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

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	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, 2013
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.

113

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 April 30, 2013, 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.

(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), based on 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

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 April 30, 2013, 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.

3. Number of Units Awarded.

Except as provided in Section 5(a) below, the number of Units ultimately to be awarded to the Grantee upon vesting is contingent upon the cumulative amount of earnings per share achieved by the Company for the three year measurement cycle, Fiscal Years 2013 through 2015 (October 1, 2012 through September 30, 2015). 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 2013-2015
Performance Level	Cumulative 3-Yr. EPS	Restricted Stock Units Earned
Below Threshold	Less than $____	—%
Threshold	$____	50%
Target	$____	100%
Maximum	$____	200%


4.	Forfeiture of Units.

All Units granted shall be forfeited if, prior to the removal of restrictions on the Units awarded hereunder as provided below in Section 8, the Grantee has a voluntary or involuntary Termination of Service for any reason other than as described below in Section 5. Each Grantee, by his or her acceptance of the Units, agrees to execute any documents requested by the Company in connection with such forfeiture. Such provisions with respect to forfeited Units shall be specifically performable by the Company in a court of equity or law. Upon any forfeiture, all rights of the Grantee with respect to the forfeited Units shall cease and terminate, without any further obligation on the part of the Company.


5.	Removal of Restrictions.

(a) Death, Disability, Certain Involuntary Terminations and Terminations following a Change in Control.

At the time and on the date of the Grantee's death, Termination of Service due to Total and Permanent Disability, involuntary Termination of Service due to a general reduction in force or specific elimination of the Grantee's job, or Termination of Service for any reason following a Change in Control, while employed by the Company or a Subsidiary, all restrictions placed on each Unit awarded shall be removed, and the measurement cycle for purposes of Section 6 and Section 8 below shall be deemed to have ended. The prorated number of Units awarded shall be determined by multiplying the percentage of Units awarded at the “Target” performance level discussed above in Section 3, by the ratio of actual months of service to 36 months of the original measurement cycle, with the resulting product being increased, if appropriate, as provided below in Section 6. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to such prorated number of Units.

(b) Retirement.

At the time and on the date of the Grantee's Retirement on or after attaining the age of 55 and completing at least three (3) consecutive years of service with the Company at the time of such Retirement, the restrictions placed on the Units under Section 2 above shall not be removed and the percentage of Units earned shall not be determined until the end of the

measurement cycle. The number of Units awarded shall be determined by multiplying the ratio of actual months of service to 36 months of the original measurement cycle by the percentage of Units earned, based on the actual performance achieved over the original measurement cycle, as discussed above in Section 3, with the resulting product being increased, if appropriate, as provided below in Section 6. The Grantee, or his or her legal representatives, beneficiaries or heirs shall be entitled to a distribution, as provided in Section 8 below, of shares of Common Stock equal in number to such prorated number of Units.


6.	Credit of Dividend Equivalents.

Immediately prior to distribution of Units as described above in Section 5 or below in Section 8, the Grantee’s account shall be credited with a number of Units which are based on the amount of dividends that are declared and paid on shares of Common Stock during each fiscal quarter of the measurement cycle, determined in accordance with Section 3 or Section 5 above (“dividend equivalents”). The number of Units upon which dividend equivalents shall be credited for the benefit of the Grantee is the total number of Units finally determined to have been earned by the Grantee at the end of the measurement cycle in accordance with Section 3 or Section 5 above, as appropriate. The total amount of each quarterly dividend equivalent shall be converted to the number of Units attributable to that quarterly dividend equivalent, by dividing such dividend equivalent amount by the average of the high and low prices of the Common Stock on the last trading day of the month during each quarter that such dividends are paid during the appropriate measurement cycle.

7. Adjustment Upon Changes in Stock.

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 a written request from the Grantee for delivery of the certificates. From and after the date of receipt of such distribution, the Grantee or the Grantee's legal representatives, beneficiaries or heirs, as the case may be, shall have full rights of transfer or resale with respect to such shares subject to applicable state and federal regulations. Notwithstanding any provisions of this Award Agreement to the contrary, in lieu of a distribution of shares of Common Stock, the Company shall have the option to settle the payment of some or all of the Units in an economically equivalent amount of cash.

9. Withholding Requirements.

Upon the removal or lapse of the restrictions on the Units, the number of shares of Common Stock to be distributed by the Company to the Grantee, which are equal to the number of Units finally determined to be earned by the Grantee as set forth in Sections 3 or Section 5(a) and Section 6 above, or an economically equivalent amount of cash, as discussed in Section 8 above, shall be subject to applicable withholding requirements for income and employment taxes arising from the removal or lapse of the restrictions on the Units. However, if the Grantee is a "specified employee" as defined in §1.409A-1(i) of the Final Regulations under Code Section 409A who is subject to the six (6) months delay provided for in Section 8 above, the Company shall, on the date of the Grantee’s Termination of Service, based on the value of a share of Common Stock on such date, withhold the number of shares attributable to any employment taxes and shall, on the date which occurs six (6) months following the date of the Grantee’s Termination of Service (or, if earlier, the date of death of the Grantee), based on 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.

ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN

Kim R. Cocklin

President and

Chief Executive Officer

Exhibit 10.6(c)

AMENDMENT NO. 2

TO THE

ATMOS ENERGY CORPORATION

ANNUAL INCENTIVE PLAN FOR MANAGEMENT

(as amended and restated February 10, 2011)

The shareholders of Atmos Energy Corporation (the “Company”) on February 9, 2011, approved the Atmos Energy Corporation Annual Incentive Plan for Management, as amended and restated, effective February 10, 2011 (the “Plan”). The Plan was then amended by the Board of Directors of the Company through Amendment No. 1, effective as of September 30, 2011. This Amendment No. 2 to the Plan was approved by the shareholders on February 13, 2013, effective as of February 14, 2013 (the “Effective Date”). All capitalized terms not otherwise defined herein shall have the meaning ascribed to them in the Plan, as amended.

Section 6.3 of the Plan is hereby amended, with respect to awards for fiscal years of the Company commencing on and after October 1, 2013, by striking said section and substituting in lieu thereof the following:

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

IN WITNESS WHEREOF, the Company has caused this AMENDMENT NO. 2 TO THE ATMOS ENERGY CORPORATION ANNUAL INCENTIVE PLAN FOR MANAGEMENT (AS AMENDED AND RESTATED FEBRUARY 10, 2011), to be executed in its name and on its behalf this 23^rd day of September, 2013, effective as of the date provided herein.

ATMOS ENERGY CORPORATION

By: /s/ KIM R. COCKLIN

Kim R. Cocklin

President and Chief Executive Officer

Exhibit 12

Atmos Energy Corporation

Computation of Earnings to Fixed Charges



	Year Ended September 30
	2013		2012		2011		2010		2009
	(Dollars in thousands)
Income from continuing operations before provision for income taxes per statement of income	$	373,297	$	290,422	$	296,407	$	309,054	$	268,636
Add:
Portion of rents representative of the interest factor	12,442		12,623		13,229		13,565		12,768
Interest on debt & amortization of debt expense	128,385		141,174		150,763		154,188		152,740
Income as adjusted	$	514,124	$	444,219	$	460,399	$	476,807	$	434,144
Fixed charges:
Interest on debt & amortization of debt expense (1)	$	128,385	$	141,174	$	150,763	$	154,188	$	152,740
Capitalized interest (2)	1,895		2,642		1,690		3,860		4,583
Rents	37,326		37,868		39,686		40,696		38,304
Portion of rents representative of the interest factor (3)	12,442		12,623		13,229		13,565		12,768
Fixed charges (1)+(2)+(3)	$	142,722	$	156,439	$	165,682	$	171,613	$	170,091
Ratio of earnings to fixed charges	3.60		2.84		2.78		2.78		2.55

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%

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; and Form S-8, No. 333-177593) of Atmos Energy Corporation and in the related Prospectuses of our reports dated November 13, 2013, 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, 2013.

/s/ ERNST & YOUNG LLP

Dallas, Texas

November 13, 2013

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 13, 2013

/s/ KIM R. COCKLIN

Kim R. Cocklin

President and

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 13, 2013

/s/ BRET J. ECKERT

Bret J. Eckert

Senior Vice President and

Chief Financial Officer

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, 2013, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Kim R. Cocklin, President and Chief Executive Officer of the Company, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:


(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 13, 2013

/s/ KIM R. COCKLIN

Kim R. Cocklin

President and Chief

Executive Officer

A signed original of this written statement has been provided to Atmos Energy Corporation and will be retained by Atmos Energy Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Atmos Energy Corporation (the "Company") on Form 10-K for the fiscal year ended September 30, 2013, 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 13, 2013

/s/ BRET J. ECKERT

Bret J. Eckert

Senior Vice President and

Chief Financial Officer

v2.4.0.8

Stock and Other Compensation Plans
12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock and Other Compensation Plans
Stock and Other Compensation Plans
Share Repurchase Agreement
On, July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman Sachs & Co. under which we repurchased $100 million of our outstanding common stock in order to offset stock grants made under our various employee and director incentive compensation plans. We paid $100 million to Goldman Sachs & Co. on July 7, 2010 in a share forward transaction and received 2,958,580 shares of Atmos Energy common stock. On March 4, 2011, we received and retired an additional 375,468 common shares which concluded our share repurchase agreement. In total, we received and retired 3,334,048 common shares under the repurchase agreement. The final number of shares we ultimately repurchased in the transaction was based generally on the average of the effective share repurchase price of our common stock over the duration of the agreement, which was $29.99. As a result of this transaction, beginning in our fourth quarter of fiscal 2010, the number of outstanding shares used to calculate our earnings per share was reduced by the number of shares received and the $100 million purchase price was recorded as a reduction in shareholders’ equity.
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, 2013, a total of 387,991 shares had been repurchased for an aggregate value of $12.5 million.
Stock-Based Compensation Plans
Total stock-based compensation expense was $17.8 million, $19.2 million and $11.6 million for the fiscal years ended September 30, 2013, 2012 and 2011, 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, 2013, 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, 2013, 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 1,403,439 shares were available for future issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years. However, no stock options have been granted under this plan since fiscal 2003, except for a limited number of options that were converted from bonuses paid under our Annual Incentive Plan, the last of which occurred in fiscal 2006. We had 7,930 stock options outstanding at September 30, 2013 at a $25.96 weighted average exercise price that are currently vested and expire in November 2014.
Restricted Stock 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 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 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 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) and a performance condition based on a cumulative earnings per share target amount.
The following summarizes information regarding the restricted stock issued under the plan during the fiscal years ended September 30, 2013, 2012 and 2011:

2013

2012

2011

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value
Nonvested at beginning of year
1,262,582

$
32.46

1,264,142

$
29.56

1,293,960

$
27.28

Granted
473,775

40.48

532,711

33.44

491,345

33.10

Vested
(657,795
)

32.20

(494,308
)

26.32

(464,321
)

27.21

Forfeited
(25,718
)

33.42

(39,963
)

29.83

(56,842
)

27.56

Nonvested at end of year
1,052,844

$
36.20

1,262,582

$
32.46

1,264,142

$
29.56

As of September 30, 2013, there was $5.1 million of total unrecognized compensation cost related to nonvested time-lapse restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted-average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2013, 2012 and 2011 was $21.2 million, $13.0 million and $12.6 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.
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, invest deferred compensation into either a cash account or a stock account and to receive an annual grant of share units for each year of service on the Board.
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.

v2.4.0.8

Retirement and Post-Retirement Employee Benefit Plans Fair Value Disclosures (Details) (USD $)
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Schedule of Total Investments at Fair Value [Line Items]

Available-for-sale Securities $ 72,682,000 $ 64,398,000

Fair Value Inputs Level 1 [Member]

Schedule of Total Investments at Fair Value [Line Items]

Available-for-sale Securities 40,094,000 40,212,000

Fair Value Inputs Level 2 [Member]

Schedule of Total Investments at Fair Value [Line Items]

Available-for-sale Securities 32,588,000 24,186,000

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 396,482,000 350,296,000

Fair value of accounts receivable 400,000 500,000

Pension Plans, Defined Benefit [Member] | Equity Securities [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 143,543,000 114,799,000

Pension Plans, Defined Benefit [Member] | Money Market Funds [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 12,266,000 21,010,000

Pension Plans, Defined Benefit [Member] | Registered Investment Companies, Domestic [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 30,200,000 19,984,000

Pension Plans, Defined Benefit [Member] | Registered Investment Companies, International [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 47,036,000 36,714,000

Pension Plans, Defined Benefit [Member] | Common Collective Trusts [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 57,627,000 52,155,000

Pension Plans, Defined Benefit [Member] | Mortgage-backed securities [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 18,446,000 19,509,000

Pension Plans, Defined Benefit [Member] | U.S. Treasuries [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 4,780,000 8,084,000

Pension Plans, Defined Benefit [Member] | Corporate Debt Securities [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 35,012,000 35,960,000

Pension Plans, Defined Benefit [Member] | Limited Partnership Interest [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 47,417,000 41,926,000

Pension Plans, Defined Benefit [Member] | Real Estate Investment [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 155,000 155,000

Pension Plans, Defined Benefit [Member] | Fair Value Inputs Level 1 [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 224,896,000 179,234,000

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 143,543,000 114,799,000

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 30,200,000 19,984,000

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 47,036,000 36,714,000

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 4,117,000 7,597,000

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 0 140,000

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 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 171,431,000 170,907,000

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 12,266,000 21,010,000

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 57,627,000 52,155,000

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 18,446,000 19,509,000

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 663,000 487,000

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 35,012,000 35,960,000

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 47,417,000 41,786,000

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 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 155,000 155,000

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 155,000 155,000

Defined Benefit Plan, Plan Assets at Fair Value, Valuation Inputs The fair value of our Level 3 real estate assets was determined using a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land sales values per square foot in the range of $0.94 to $2.98 and comparable building sales values per square foot in the range of $23.13 to $30.42.

Other Postretirement Benefit Plans, Defined Benefit [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 106,413,000 78,568,000

Other Postretirement Benefit Plans, Defined Benefit [Member] | Money Market Funds [Member]

Schedule of Total Investments at Fair Value [Line Items]

Investments, Fair Value Disclosure 3,356,000 2,360,000

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 9,614,000 7,756,000

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 93,443,000 68,452,000

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 103,057,000 76,208,000

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 9,614,000 7,756,000

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 93,443,000 68,452,000

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 3,356,000 2,360,000

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 3,356,000 2,360,000

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

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Schedule of Total Investments at Fair Value [Line Items]

Available-for-sale Securities $ 44,500,000 $ 41,800,000

Minimum [Member]

Schedule of Total Investments at Fair Value [Line Items]

Comparable Land Sale Values 0.94

Comparable Building Sales Values 23.13

Maximum [Member]

Schedule of Total Investments at Fair Value [Line Items]

Comparable Land Sale Values 2.98

Comparable Building Sales Values 30.42

v2.4.0.8

CONSOLIDATED STATEMENTS OF INCOME (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Operating revenues

Operating revenues $ 685,171 $ 857,935 $ 1,308,996 $ 1,034,155 $ 552,566 $ 576,414 $ 1,225,509 $ 1,083,994 $ 3,886,257 $ 3,438,483 $ 4,286,435

Purchased gas cost

Purchased gas cost 2,474,207 2,114,744 2,985,615

Gross profit 300,440 316,497 432,751 362,362 249,389 293,171 425,787 355,392 1,412,050 1,323,739 1,300,820

Operating expenses

Operation and maintenance 488,020 453,613 442,965

Depreciation and amortization 235,079 237,525 223,832

Taxes, other than income 187,072 181,073 177,767

Asset impairments 0 5,288 30,270

Total operating expenses 910,171 877,499 874,834

Operating income 50,383 86,396 210,178 154,922 22,791 81,546 202,432 139,471 501,879 446,240 425,986

Miscellaneous income (expense), net (197) (14,644) 21,184

Interest charges 128,385 141,174 150,763

Income from continuing operations before income taxes 373,297 290,422 296,407

Income tax expense 142,599 98,226 106,819

Income from continuing operations 7,536 33,474 112,340 77,348 (286) 28,014 102,084 62,384 230,698 192,196 189,588

Income from discontinued operations, net of tax 0 0 4,085 3,117 1,904 3,118 7,027 6,123 7,202 18,172 18,013

Gain on sale of discontinued operations, net of tax 0 5,294 0 0 6,349 0 0 0 5,294 6,349 0

Net income 7,536 38,768 116,425 80,465 7,967 31,132 109,111 68,507 243,194 216,717 207,601

Income per share from continuing operations - basic (usd per share) $ 0.08 $ 0.37 $ 1.24 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.54 $ 2.12 $ 2.08

Income per share from discontinued operations - basic (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.04 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — basic (usd per share) $ 0.08 $ 0.43 $ 1.28 $ 0.89 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.68 $ 2.39 $ 2.28

Income per share from continuing operations - diluted (usd per share) $ 0.08 $ 0.36 $ 1.23 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.50 $ 2.10 $ 2.07

Income per share from discontinued operations - diluted (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.03 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — diluted (usd per share) $ 0.08 $ 0.42 $ 1.27 $ 0.88 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.64 $ 2.37 $ 2.27

Weighted average shares outstanding:

Basic (shares) 90,533 90,150 90,201

Diluted (shares) 91,711 91,172 90,652

Natural Gas Distribution Segment [Member]

Operating revenues

Operating revenues 360,386 467,144 905,176 666,787 282,516 315,634 871,067 676,113 2,399,493 2,145,330 2,470,664

Purchased gas cost

Purchased gas cost 1,318,257 1,122,587 1,452,721

Gross profit 1,081,236 1,022,743 1,017,943

Operating expenses

Operation and maintenance 375,188 353,879 341,758

Depreciation and amortization 195,581 202,026 193,642

Taxes, other than income 167,374 162,377 160,455

Asset impairments 0 0

Total operating expenses 738,143 718,282 695,855

Operating income 343,093 304,461 322,088

Miscellaneous income (expense), net 2,535 (12,657) 16,242

Interest charges 98,296 110,642 115,740

Income from continuing operations before income taxes 247,332 181,162 222,590

Income tax expense 96,476 57,314 77,885

Income from continuing operations 150,856 123,848 144,705

Income from discontinued operations, net of tax 7,202 18,172 18,013

Gain on sale of discontinued operations, net of tax 5,649 6,349

Net income 163,707 148,369 162,718

Regulated Transmission and Storage Segment [Member]

Operating revenues

Operating revenues 72,330 74,041 61,848 60,681 65,482 67,073 58,037 56,759 268,900 247,351 219,373

Purchased gas cost

Purchased gas cost 0 0 0

Gross profit 268,900 247,351 219,373

Operating expenses

Operation and maintenance 76,686 71,521 70,401

Depreciation and amortization 35,302 31,438 25,997

Taxes, other than income 17,059 15,568 14,700

Asset impairments 0 0

Total operating expenses 129,047 118,527 111,098

Operating income 139,853 128,824 108,275

Miscellaneous income (expense), net (2,285) (1,051) 4,715

Interest charges 30,678 29,414 31,432

Income from continuing operations before income taxes 106,890 98,359 81,558

Income tax expense 38,630 35,300 29,143

Income from continuing operations 68,260 63,059 52,415

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax 0 0

Net income 68,260 63,059 52,415

Nonregulated Segment [Member]

Operating revenues

Operating revenues 348,061 421,808 428,948 399,894 280,114 256,250 370,763 444,176 1,598,711 1,351,303 2,024,893

Purchased gas cost

Purchased gas cost 1,535,380 1,296,179 1,959,893

Gross profit 63,331 55,124 65,000

Operating expenses

Operation and maintenance 37,569 29,697 32,308

Depreciation and amortization 4,196 4,061 4,193

Taxes, other than income 2,639 3,128 2,612

Asset impairments 5,288 30,270

Total operating expenses 44,404 42,174 69,383

Operating income 18,927 12,950 (4,383)

Miscellaneous income (expense), net 2,316 1,035 657

Interest charges 2,168 3,084 4,015

Income from continuing operations before income taxes 19,075 10,901 (7,741)

Income tax expense 7,493 5,612 (209)

Income from continuing operations 11,582 5,289 (7,532)

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax (355) 0

Net income 11,227 5,289 (7,532)

Intersegment Elimination [Member]

Operating revenues

Operating revenues (95,606) (105,058) (86,976) (93,207) (75,546) (62,543) (74,358) (93,054) (380,847) (305,501) (428,495)

Purchased gas cost

Purchased gas cost (379,430) (304,022) (426,999)

Gross profit (1,417) (1,479) (1,496)

Operating expenses

Operation and maintenance (1,423) (1,484) (1,502)

Depreciation and amortization 0 0 0

Taxes, other than income 0 0 0

Asset impairments 0 0

Total operating expenses (1,423) (1,484) (1,502)

Operating income 6 5 6

Miscellaneous income (expense), net (2,763) (1,971) (430)

Interest charges (2,757) (1,966) (424)

Income from continuing operations before income taxes 0 0 0

Income tax expense 0 0 0

Income from continuing operations 0 0 0

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax 0 0

Net income $ 0 $ 0 $ 0

v2.4.0.8

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

CASH FLOWS FROM OPERATING ACTIVITIES

Net income $ 243,194 $ 216,717 $ 207,601

Adjustments to reconcile net income to net cash provided by operating activities:

Asset impairments 0 5,288 30,270

Gain on sale of discontinued operations (8,203) (9,868) 0

Depreciation and amortization:

Charged to depreciation and amortization 236,928 246,093 233,155

Charged to other accounts 679 484 228

Deferred income taxes 141,336 104,319 117,353

Stock-based compensation 17,814 19,222 11,586

Debt financing costs 8,480 8,147 9,438

Other (2,887) (493) (961)

Changes in assets and liabilities:

(Increase) decreased in accounts receivable (73,669) 32,578 (96)

Decrease in gas stored underground 31,979 28,417 27,737

(Increase) decrease in other current assets 15,644 20,989 (38,048)

(Increase) decrease in deferred charges and other assets 111,069 (50,055) (53,519)

Increase (decrease) in account payable and accrued liabilities 31,912 (64,234) 23,904

Increase (decrease) in other current liabilities (44,491) 7,889 (57,495)

Increase (decrease) in deferred credits and other liabilities (96,658) 21,424 71,691

Net cash provided by operating activities 613,127 586,917 582,844

CASH FLOWS USED IN INVESTING ACTIVITIES

Capital expenditures (845,033) (732,858) (622,965)

Proceeds from the sale of discontinued operations 153,023 128,223 0

Other, net (4,904) (4,625) (4,421)

Net cash used in investing activities (696,914) (609,260) (627,386)

CASH FLOWS FROM FINANCING ACTIVITIES

Net increase (decrease) in short-term debt (208,070) 354,141 83,306

Net proceeds from issuance of long-term debt 493,793 0 394,466

Settlement of Treasury lock agreement (66,626) 0 20,079

Unwinding of Treasury lock agreements 0 0 27,803

Repayment of long-term debt (131) (257,034) (360,131)

Cash dividends paid (128,115) (125,796) (124,011)

Repurchase of common stock 0 (12,535) 0

Repurchase of equity awards (5,150) (5,219) (5,299)

Issuance of common stock 46 1,606 7,796

Net cash provided by (used in) financing activities 85,747 (44,837) 44,009

Net increase (decrease) in cash and cash equivalents 1,960 (67,180) (533)

Cash and cash equivalents at beginning of period 64,239 131,419 131,952

Cash and cash equivalents at end of period 66,199 64,239 131,419

CASH PAID (RECEIVED) DURING THE PERIOD FOR:

Interest 148,461 150,606 157,976

Income taxes $ 10,008 $ (432) $ (8,329)

v2.4.0.8

Fair Value Measurements
12 Months Ended

Sep. 30, 2013

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, 2013 and 2012. 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, 2013

(In thousands)
Assets:

Financial instruments

Natural gas distribution segment
$
—

$
111,191

$
—

$
—

$
111,191

Nonregulated segment
745

115,135

—

(99,618
)

16,262

Total financial instruments
745

226,326

—

(99,618
)

127,453

Hedged portion of gas stored underground
44,758

—

—

—

44,758

Available-for-sale securities

Money market funds
—

4,428

—

—

4,428

Registered investment companies
40,094

—

—

—

40,094

Bonds
—

28,160

—

—

28,160

Total available-for-sale securities
40,094

32,588

—

—

72,682

Total assets
$
85,597

$
258,914

$
—

$
(99,618
)

$
244,893

Liabilities:

Financial instruments

Natural gas distribution segment
$
—

$
1,543

$
—

$
—

$
1,543

Nonregulated segment
158

130,422

—

(124,447
)

6,133

Total liabilities
$
158

$
131,965

$
—

$
(124,447
)

$
7,676

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, 2012

(In thousands)
Assets:

Financial instruments

Natural gas distribution segment
$
—

$
9,365

$
—

$
—

$
9,365

Nonregulated segment
714

179,835

—

(162,776
)

17,773

Total financial instruments
714

189,200

—

(162,776
)

27,138

Hedged portion of gas stored underground
67,192

—

—

—

67,192

Available-for-sale securities

Money market funds
—

1,634

—

—

1,634

Registered investment companies
40,212

—

—

—

40,212

Bonds
—

22,552

—

—

22,552

Total available-for-sale securities
40,212

24,186

—

—

64,398

Total assets
$
108,118

$
213,386

$
—

$
(162,776
)

$
158,728

Liabilities:

Financial instruments

Natural gas distribution segment
$
—

$
85,625

$
—

$
—

$
85,625

Nonregulated segment
4,563

191,109

—

(186,451
)

9,221

Total liabilities
$
4,563

$
276,734

$
—

$
(186,451
)

$
94,846

⁽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, 2013 we had $24.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting agreements and the remaining $16.2 million is classified as current risk management assets.
⁽³⁾
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting agreements and the remaining $17.8 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, 2013

Domestic equity mutual funds
$
27,043

$
7,476

$
(23
)

$
34,496

Foreign equity mutual funds
4,536

1,062

—

5,598

Bonds
28,016

168

(24
)

28,160

Money market funds
4,428

—

—

4,428

$
64,023

$
8,706

$
(47
)

$
72,682

As of September 30, 2012

Domestic equity mutual funds
$
25,779

$
8,183

$
—

$
33,962

Foreign equity mutual funds
5,568

682

—

6,250

Bonds
22,358

196

(2
)

22,552

Money market funds
1,634

—

—

1,634

$
55,339

$
9,061

$
(2
)

$
64,398

At September 30, 2013 and 2012, our available-for-sale securities included $44.5 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive retirement plans as discussed in Note 6. At September 30, 2013 we maintained investments in bonds that have contractual maturity dates ranging from October 2013 through December 2019. During the year ended September 30, 2013, we recognized a net gain of $2.2 million on the sale of certain assets in the rabbi trusts.
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.
Atmos Gathering Company (AGC) owns and operates the Park City and Shrewsbury gathering systems in Kentucky. The Park City gathering system consists of a 23-mile low pressure pipeline and a nitrogen removal unit that was constructed in 2008. The Shrewsbury production, gathering and processing assets were acquired in 2008 at which time we sold the production assets to a third party. As a result of the sale of the production assets, we obtained a 10-year production payment note under which we were to be paid from future production generated from the assets.
As discussed in Note 10, AGC is involved in an ongoing lawsuit with the Park City gathering system. Due to the lawsuit and a low natural gas price environment, the assets have generated operating losses. As a result of these developments, in fiscal 2011, we performed an impairment assessment of these assets and determined the assets to be impaired at which time we recorded a pre-tax noncash impairment loss of approximately $11 million. Due to developments in the fourth quarter of fiscal 2012, including further operating losses as a result of the lawsuit and management’s decision to focus our nonregulated operations on delivered gas and transportation services, we performed an impairment assessment of these assets and determined the assets to be further impaired. We reduced the carrying value of the assets to their estimated fair value of approximately $0.5 million and recorded a pre-tax noncash impairment loss of approximately $5.3 million. We used a combination of a market and income approach in a weighted average discounted cash flow analysis that included significant inputs such as our weighted average cost of capital and assumptions regarding future natural gas prices. This is a Level 3 fair value measurement because the inputs used are unobservable. Based on this analysis, we determined the assets to be impaired.
In February 2008, Atmos Pipeline and Storage, LLC, a subsidiary of AEH, announced plans to construct and operate a salt-cavern storage project in Franklin Parish, Louisiana. In March 2010, we entered into an option and acquisition agreement with a third party, which provided the third party with the exclusive option to develop the proposed Fort Necessity salt-dome natural gas storage project. In July 2010, we agreed with the third party to extend the option period to March 2011. In January 2011, the third party developer notified us that it did not plan to commence the activities required to allow it to exercise the option by March 2011; accordingly, the option was terminated. We evaluated our strategic alternatives and concluded the project’s returns did not meet our investment objectives. Accordingly, in March 2011, we recorded a $19.3 million pre-tax noncash impairment loss to write off substantially all of our investment in the project.
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, 2013:

September 30, 2013

(In thousands)
Carrying Amount
$
2,460,000

Fair Value
$
2,676,487

v2.4.0.8

Financial Instruments Other Comprehensive Income (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Other Comprehensive Income [Abstract]

Interest rate agreements fair value $ 79,963 $ (11,458)

Forward commodity contracts fair value (2,057) (30,366)

Interest rate agreements 2,216 1,342

Forward commodity contracts 6,576 38,232

Total other comprehensive income (loss) from hedging, net of tax 86,698 ^[1] (2,250) ^[1]

Expected Earnings [Line Items]

2014 (6,434)

2015 (1,229)

2016 (797)

2017 (844)

2018 (967)

Thereafter (24,569)

Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total (34,840) ^[1]

Interest Rate Contract [Member]

Expected Earnings [Line Items]

2014 (2,686)

2015 (804)

2016 (634)

2017 (735)

2018 (936)

Thereafter (24,569)

Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total (30,364) ^[1]

Commodity Contract [Member]

Expected Earnings [Line Items]

2014 (3,748)

2015 (425)

2016 (163)

2017 (109)

2018 (31)

Thereafter 0

Cash Flow Hedge Gain (Loss) To Be Reclassiflied, Total $ (4,476) ^[1]

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

v2.4.0.8

Details of Selected Consolidated Balance Sheet Captions
12 Months Ended

Sep. 30, 2013

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, 2013 and 2012:

September 30

2013

2012

(In thousands)
Billed accounts receivable
$
230,712

$
177,953

Unbilled revenue
58,710

42,694

Other accounts receivable
33,194

23,304

Total accounts receivable
322,616

243,951

Less: allowance for doubtful accounts
(20,624
)

(9,425
)
Net accounts receivable
$
301,992

$
234,526

Other current assets
Other current assets as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Assets from risk management activities
$
18,099

$
24,707

Deferred gas costs
15,152

31,359

Taxes receivable
3,141

1,291

Current deferred tax asset
—

27,091

Prepaid expenses
21,666

17,114

Materials and supplies
5,511

5,872

Assets held for sale⁽¹⁾
—

154,571

Other
6,765

10,777

Total
$
70,334

$
272,782

⁽¹⁾As discussed in Note 16, assets and liabilities related to our Georgia operations were classified as “assets held for sale” in other current assets and liabilities in our consolidated balance sheets at September 30, 2012.
Property, plant and equipment
Property, plant and equipment was comprised of the following as of September 30, 2013 and 2012:

September 30

2013

2012

(In thousands)
Production plant
$
5,020

$
5,020

Storage plant
262,246

232,260

Transmission plant
1,362,662

1,185,007

Distribution plant
5,061,711

4,680,877

General plant
716,189

717,568

Intangible plant
38,444

39,626

7,446,272

6,860,358

Construction in progress
275,747

274,112

7,722,019

7,134,470

Less: accumulated depreciation and amortization
(1,691,364
)

(1,658,866
)
Net property, plant and equipment⁽¹⁾
$
6,030,655

$
5,475,604

⁽¹⁾
Net property, plant and equipment includes plant acquisition adjustments of ($83.8) million and ($91.5) million at September 30, 2013 and 2012.

Goodwill
The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2013:

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Total

(In thousands)
Balance as of September 30, 2012
$
573,550

$
132,422

$
34,711

$
740,683

Deferred tax adjustments on prior acquisitions⁽¹⁾
640

40

—

680

Balance as of September 30, 2013
$
574,190

$
132,462

$
34,711

$
741,363

⁽¹⁾
During the preparation of the fiscal 2013 tax provision, we adjusted 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
Deferred charges and other assets as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Marketable securities
$
72,682

$
64,398

Regulatory assets
273,287

358,495

Deferred financing costs
15,199

11,157

Assets from risk management activities
109,354

2,283

Other
14,474

14,929

Total
$
484,996

$
451,262

Accounts payable and accrued liabilities

Accounts payable and accrued liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Trade accounts payable
$
70,116

$
82,531

Accrued gas payable
121,202

81,658

Accrued liabilities
50,293

51,040

Total
$
241,611

$
215,229

Other current liabilities
Other current liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Customer credit balances and deposits
$
76,313

$
100,926

Accrued employee costs
54,034

37,675

Deferred gas costs
16,481

23,072

Accrued interest
36,744

34,451

Liabilities from risk management activities
1,543

85,381

Taxes payable
66,960

64,319

Pension and postretirement obligations
22,940

39,625

Current deferred tax liability
14,697

—

Regulatory cost of removal accrual
68,225

78,525

Liabilities held for sale
—

11,573

Other
10,954

14,118

Total
$
368,891

$
489,665

Deferred credits and other liabilities
Deferred credits and other liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Customer advances for construction
$
11,723

$
12,937

Regulatory liabilities
1,123

5,638

Asset retirement obligation
6,764

10,394

Liabilities from risk management activities
6,133

9,206

Other
17,953

12,555

Total
$
43,696

$
50,730

v2.4.0.8

Summary of Significant Accounting Policies (Details) (USD $)
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Regulatory Assets [Line Items]

Regulatory Assets $ 286,748,000 $ 392,263,000

Regulatory Liabilities [Line Items]

Regulatory Liabilities 453,581,000 488,397,000

Regulatory Assets and Liabilities, Other Disclosures [Abstract]

Regulatory Asset - Future Recoverable Pension Costs 17,400,000 7,600,000

Regulatory Noncurrent Asset, Amortization Period 20 years

Amortization of Regulatory Asset 500,000 500,000 500,000

Property, Plant and Equipment [Line Items]

Interest Costs Capitalized 1,900,000 2,600,000 1,700,000

Composite depreciation rate for regulated property, plant and equipment 3.33% 3.60% 3.60%

Other Information [Abstract]

Unrealized gain (loss) on open contracts 9,000,000 (8,000,000) (10,400,000)

Asset Retirement Obligation 6,800,000 10,500,000

Asset Retirement Costs in Property, Plant and Equipment 3,300,000 5,800,000

Asset Impairment Charges Park City 5,300,000 11,000,000

Asset Impairment Charges Fort Necessity 19,300,000

Finite-Lived Intangible Asset, Useful Life 10 years

Cash Collateral Right To Reclaim Cash 24,800,000 23,700,000

Supplemental Employee Retirement Plan, Defined Benefit [Member] | Fair Value Inputs Level 3 [Member] | Real Estate [Member]

Defined Benefit Plan Disclosure [Line Items]

Investments, Fair Value Disclosure 200,000

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 50 years

Deferred Gas Costs Liability [Member]

Regulatory Liabilities [Line Items]

Regulatory Liabilities 16,481,000 23,072,000

Deferred Franchise Fees Liability [Member]

Regulatory Liabilities [Line Items]

Regulatory Liabilities 1,689,000 0

Regulatory Cost Of Removal Liability [Member]

Regulatory Liabilities [Line Items]

Regulatory Liabilities 427,524,000 459,688,000

Miscellaneous Regulatory Liabilities [Member]

Regulatory Liabilities [Line Items]

Regulatory Liabilities 7,887,000 5,637,000

Pension And Postretirement Benefit Costs [Member]

Regulatory Assets [Line Items]

Regulatory Assets 187,977,000 ^[1] 296,160,000 ^[1]

Merger And Integration Costs Net [Member]

Regulatory Assets [Line Items]

Regulatory Assets 5,250,000 5,754,000

Deferred Gas Costs Asset [Member]

Regulatory Assets [Line Items]

Regulatory Assets 15,152,000 31,359,000

Regulatory Cost of Removal Asset [Member]

Regulatory Assets [Line Items]

Regulatory Assets 10,008,000 10,500,000

Rate Case Costs [Member]

Regulatory Assets [Line Items]

Regulatory Assets 6,329,000 4,661,000

Deferred Franchise Fees [Member]

Regulatory Assets [Line Items]

Regulatory Assets 0 2,714,000

Texas 8.209 [Member]

Regulatory Assets [Line Items]

Regulatory Assets 30,364,000 ^[2] 5,370,000 ^[2]

APT Annual Adjustment Mechanism Asset [Member]

Regulatory Assets [Line Items]

Regulatory Assets 5,853,000 4,539,000

Recoverable Loss On Reacquired Debt [Member]

Regulatory Assets [Line Items]

Regulatory Assets 21,435,000 23,944,000

Deferred Miscellaneous Costs [Member]

Regulatory Assets [Line Items]

Regulatory Assets $ 4,380,000 $ 7,262,000

[1] Includes $17.4 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.

[2] Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

v2.4.0.8

Stock and Other Compensation Plans (Details) (USD $)
0 Months Ended 12 Months Ended

Sep. 28, 2011

Apr. 04, 2011

Jul. 10, 2010

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Jul. 02, 2010

Accelerated Share Repurchase Agreement [Abstract]

Accelerated Share Repurchases Payment $ 100,000,000 $ 100,000,000 $ 100,000,000

Stock repurchased and retired, shares 375,468 2,958,580 3,334,048

Accelerated Share Repurchases, Final Price Paid Per Share $ 29.99

Stock Repurchase Program [Abstract]

Stock Repurchase Program, Number of Shares Authorized to be Repurchased 5,000,000

Stock Repurchase Program, Period in Force 5 years 0 months 0 days

Stock Repurchased During Period, Shares 387,991

Stock Repurchased During Period, Value 12,500,000

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Stock Based Compensation Expense 17,800,000 19,200,000 11,600,000

Authorized Shares 8,700,000

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available 1,403,439

Stock option, expiration period 10 years

Summary Of Stock Option Activity [Abstract]

Exercisable at end of year-Options 7,930

Exercisable at end of year-Weighted Average $ 25.96

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]

Nonvested at beginning of year-Shares 1,262,582 1,264,142 1,293,960

Nonvested at beginning of year-Weighted Average $ 32.46 $ 29.56 $ 27.28

Granted-Shares 473,775 532,711 491,345

Granted-Weighted Average $ 40.48 $ 33.44 $ 33.10

Vested-Shares (657,795) (494,308) (464,321)

Vested-Weighted Average $ 32.20 $ 26.32 $ 27.21

Forfeited-Shares (25,718) (39,963) (56,842)

Forfeited-Weighted Average $ 33.42 $ 29.83 $ 27.56

Nonvested at end of year-Shares 1,052,844 1,262,582 1,264,142

Nonvested at end of year-Weighted Average $ 36.20 $ 32.46 $ 29.56

Unrecognized Compensation Cost 5,100,000

Weighted Average Recognized Period 1 year 7 months 6 days

Fair Value Restricted Stock Vested 21,200,000 13,000,000 12,600,000

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

Minimum [Member]

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Stock option, vesting period 1 year

Maximum [Member]

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Stock option, vesting period 3 years

v2.4.0.8

Leases (Table)
12 Months Ended

Sep. 30, 2013

Leases [Abstract]

Schedule of Future Minimum Lease Payments
The related future minimum lease payments at September 30, 2013 were as follows:

Capital
Leases

Operating
Leases

(In thousands)
2014
$
186

$
16,722

2015
186

15,584

2016
186

14,692

2017
186

15,074

2018
78

15,057

Thereafter
—

89,673

Total minimum lease payments
822

$
166,802

Less amount representing interest
198

Present value of net minimum lease payments
$
624

v2.4.0.8

Selected Quarterly Financial Data
12 Months Ended

Sep. 30, 2013

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 2013:

Operating revenues

Natural gas distribution
$
666,787

$
905,176

$
467,144

$
360,386

Regulated transmission and storage
60,681

61,848

74,041

72,330

Nonregulated
399,894

428,948

421,808

348,061

Intersegment eliminations
(93,207
)

(86,976
)

(105,058
)

(95,606
)

1,034,155

1,308,996

857,935

685,171

Gross profit
362,362

432,751

316,497

300,440

Operating income
154,922

210,178

86,396

50,383

Income from continuing operations
77,348

112,340

33,474

7,536

Income from discontinued operations
3,117

4,085

—

—

Gain on sale of discontinued operations
—

—

5,294

—

Net income
80,465

116,425

38,768

7,536

Basic earnings per share

Income per share from continuing operations
$
0.85

$
1.24

$
0.37

$
0.08

Income per share from discontinued operations
$
0.04

$
0.04

$
0.06

$
—

Net income per share — basic
$
0.89

$
1.28

$
0.43

$
0.08

Diluted earnings per share

Income per share from continuing operations
$
0.85

$
1.23

$
0.36

$
0.08

Income per share from discontinued operations
$
0.03

$
0.04

$
0.06

$
—

Net income per share — diluted
$
0.88

$
1.27

$
0.42

$
0.08

Quarter Ended

December 31

March 31

June 30

September 30

(In thousands, except per share data)
Fiscal year 2012:

Operating revenues

Natural gas distribution
$
676,113

$
871,067

$
315,634

$
282,516

Regulated transmission and storage
56,759

58,037

67,073

65,482

Nonregulated
444,176

370,763

256,250

280,114

Intersegment eliminations
(93,054
)

(74,358
)

(62,543
)

(75,546
)

1,083,994

1,225,509

576,414

552,566

Gross profit
355,392

425,787

293,171

249,389

Operating income
139,471

202,432

81,546

22,791

Income (loss) from continuing operations
62,384

102,084

28,014

(286
)
Income from discontinued operations
6,123

7,027

3,118

1,904

Gain on sale of discontinued operations
—

—

—

6,349

Net income
68,507

109,111

31,132

7,967

Basic earnings per share

Income per share from continuing operations
$
0.68

$
1.12

$
0.31

$
—

Income per share from discontinued operations
$
0.07

0.08

$
0.03

$
0.09

Net income per share — basic
$
0.75

$
1.20

$
0.34

$
0.09

Diluted earnings per share

Income per share from continuing operations
$
0.68

$
1.12

$
0.31

$
—

Income per share from discontinued operations
$
0.07

$
0.08

$
0.03

$
0.09

Net income per share — diluted
$
0.75

$
1.20

$
0.34

$
0.09

v2.4.0.8

Discontinued Operations
12 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations
Discontinued Operations
On April 1, 2013, we completed the sale of substantially all of our natural gas 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.
On August 1, 2012, we completed the sale of substantially all of our natural gas distribution assets located in Missouri, Illinois and Iowa to Liberty Energy (Midstates) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $128 million, pursuant to an asset purchase agreement executed on May 12, 2011. In connection with the sale, we recognized a pre-tax gain of approximately $9.9 million.
As required under generally accepted accounting principles, the operating results of our Georgia, Missouri, Illinois and Iowa operations 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 tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations.
The following table presents statement of income data related to discontinued operations in our Georgia, Missouri, Illinois and Iowa service areas.

Year Ended September 30

2013

2012

2011

(In thousands)
Operating revenues
$
37,962

$
114,703

$
141,227

Purchased gas cost
21,464

62,902

83,537

Gross profit
16,498

51,801

57,690

Operating expenses
5,858

24,174

27,362

Operating income
10,640

27,627

30,328

Other nonoperating income
548

611

57

Income from discontinued operations before income taxes
11,188

28,238

30,385

Income tax expense
3,986

10,066

12,372

Income from discontinued operations
7,202

18,172

18,013

Gain on sale of discontinued operations, net of tax
5,294

6,349

—

Net income from discontinued operations
$
12,496

$
24,521

$
18,013

The following table presents balance sheet data related to assets held for sale. At September 30, 2013 we did not have any assets or liabilities held for sale. At September 30, 2012 assets held for sale include assets and liabilities associated with our Georgia operations.

September 30,
2012

(In thousands)
Net plant, property & equipment
$
142,865

Gas stored underground
4,688

Other current assets
6,931

Deferred charges and other assets
87

Assets held for sale
$
154,571

Accounts payable and accrued liabilities
$
2,114

Other current liabilities
3,776

Regulatory cost of removal
3,257

Deferred credits and other liabilities
2,426

Liabilities held for sale
$
11,573

v2.4.0.8

Valuation and Qualifying Accounts (Table)
12 Months Ended

Sep. 30, 2013

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts
Valuation and Qualifying Accounts
Three Years Ended September 30, 2013

Additions

Balance at
beginning
of period

Charged to
cost &
expenses

Charged to
other
accounts

Deductions

Balance
at end
of period

(In thousands)

2013

Allowance for doubtful accounts
$
9,425

$
14,484

$
—

$
3,285

⁽¹⁾

$
20,624

2012

Allowance for doubtful accounts
$
7,440

$
8,901

$
—

$
6,916

⁽¹⁾

$
9,425

2011

Allowance for doubtful accounts
$
12,701

$
2,201

$
—

$
7,462

⁽¹⁾

$
7,440

⁽¹⁾
Uncollectible accounts written off.

v2.4.0.8

Debt (Table)
12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Debt instrument table
Long-term debt at September 30, 2013 and 2012 consisted of the following:

2013

2012

(In thousands)
Unsecured 4.95% Senior Notes, due October 2014
$
500,000

$
500,000

Unsecured 6.35% Senior Notes, due 2017
250,000

250,000

Unsecured 8.50% Senior Notes, due 2019
450,000

450,000

Unsecured 5.95% Senior Notes, due 2034
200,000

200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

400,000

Unsecured 4.15% Senior Notes, due 2043
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

Rental property term notes due in installments through 2013
—

131

Total long-term debt
2,460,000

1,960,131

Less:

Original issue discount on unsecured senior notes and debentures
4,329

3,695

Current maturities
—

131

$
2,455,671

$
1,956,305

Debt maturity schedule
Maturities of long-term debt at September 30, 2013 were as follows (in thousands):
2014
$
—

2015
500,000

2016
—

2017
250,000

2018
—

Thereafter
1,710,000

$
2,460,000

v2.4.0.8

Income Taxes (Table)
12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)
The components of income tax expense from continuing operations for 2013, 2012 and 2011 were as follows:

2013

2012

2011

(In thousands)
Current

Federal
$
—

$
631

$
(13,298
)
State
8,178

6,888

6,841

Deferred

Federal
124,836

103,971

107,950

State
9,605

(13,237
)

5,498

Investment tax credits
(20
)

(27
)

(172
)

$
142,599

$
98,226

$
106,819

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 2013, 2012 and 2011 are set forth below:

2013

2012

2011

(In thousands)
Tax at statutory rate of 35%
$
130,655

$
101,648

$
103,743

Common stock dividends deductible for tax reporting
(2,153
)

(2,096
)

(1,930
)
Penalties
153

66

2,292

Recognition (settlement) of uncertain tax positions
1,341

1,831

(4,950
)
State taxes (net of federal benefit)
10,687

(5,958
)

8,109

Other, net
1,916

2,735

(445
)
Income tax expense
$
142,599

$
98,226

$
106,819

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, 2013 and 2012 are presented below:

2013

2012

(In thousands)
Deferred tax assets:

Accruals not currently deductible for tax purposes
$
11,496

$
7,906

Customer advances
4,279

4,721

Nonqualified benefit plans
52,051

48,513

Postretirement benefits
63,919

62,802

Treasury lock agreements
—

25,448

Unamortized investment tax credit
6

14

Tax net operating loss and credit carryforwards
206,996

164,419

Difference between book and tax on mark to market accounting
2,271

2,342

Other, net
—

7,223

Total deferred tax assets
341,018

323,388

Deferred tax liabilities:

Difference in net book value and net tax value of assets
(1,445,450
)

(1,254,698
)
Pension funding
(23,480
)

(32,812
)
Gas cost adjustments
(19,182
)

(21,806
)
Interest rate agreements
(21,726
)

—

Cost expensed for tax purposes and capitalized for book purposes
(2,815
)

(2,065
)
Other, net
(7,115
)

—

Total deferred tax liabilities
(1,519,768
)

(1,311,381
)
Net deferred tax liabilities
$
(1,178,750
)

$
(987,993
)
Deferred credits for rate regulated entities
$
(51
)

$
140

v2.4.0.8

Segment Information (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended

Sep. 30, 2013

state

customers

regulated_gas_distributions_divisions

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

segment

state

customers

regulated_gas_distributions_divisions

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2010

Segment Reporting Information Profit Loss [Abstract]

Operating revenues $ 685,171 $ 857,935 $ 1,308,996 $ 1,034,155 $ 552,566 $ 576,414 $ 1,225,509 $ 1,083,994 $ 3,886,257 $ 3,438,483 $ 4,286,435

Purchased gas cost 2,474,207 2,114,744 2,985,615

Gross profit 300,440 316,497 432,751 362,362 249,389 293,171 425,787 355,392 1,412,050 1,323,739 1,300,820

Operating expenses

Operation and maintenance 488,020 453,613 442,965

Depreciation and amortization 235,079 237,525 223,832

Taxes, other than income 187,072 181,073 177,767

Asset impairments 0 5,288 30,270

Total operating expenses 910,171 877,499 874,834

Operating income 50,383 86,396 210,178 154,922 22,791 81,546 202,432 139,471 501,879 446,240 425,986

Miscellaneous income (expense), net (197) (14,644) 21,184

Interest charges 128,385 141,174 150,763

Income (loss) before income taxes 373,297 290,422 296,407

Income tax expense 142,599 98,226 106,819

Income (loss) from continuing operations 7,536 33,474 112,340 77,348 (286) 28,014 102,084 62,384 230,698 192,196 189,588

Income from discontinued operations, net of tax 0 0 4,085 3,117 1,904 3,118 7,027 6,123 7,202 18,172 18,013

Gain (loss) on sale of discontinued operations, net of tax 0 5,294 0 0 6,349 0 0 0 5,294 6,349 0

Net income 7,536 38,768 116,425 80,465 7,967 31,132 109,111 68,507 243,194 216,717 207,601

Capital expenditures 845,033 732,858 622,965

Revenue from External Customers by Products and Services Table [Abstract]

Operating revenues 685,171 857,935 1,308,996 1,034,155 552,566 576,414 1,225,509 1,083,994 3,886,257 3,438,483 4,286,435

ASSETS

Net property, plant and equipment 6,030,655 5,475,604 6,030,655 5,475,604

Investment in subsidaries 0 0 0 0

Current assets

Cash and cash equivalents 66,199 64,239 66,199 64,239 131,419 131,952

Assets from risk management activities current 18,099 24,707 18,099 24,707

Other current assets 598,968 739,016 598,968 739,016

Intercompany receivables 0 0 0 0

Total current assets 683,266 827,962 683,266 827,962

Intangible assets 121 164 121 164

Goodwill 741,363 740,683 741,363 740,683

Assets from risk management activities noncurrent 109,354 2,283 109,354 2,283

Deferred charges and other assets 375,642 448,979 375,642 448,979

Total Assets 7,940,401 7,495,675 7,940,401 7,495,675

CAPITALIZATION AND LIABILITIES

Shareholders' equity 2,580,409 2,359,243 2,580,409 2,359,243 2,255,421 2,178,348

Long-term debt 2,455,671 1,956,305 2,455,671 1,956,305

Total capitalization 5,036,080 4,315,548 5,036,080 4,315,548

Current liabilities

Current maturities of long-term debt 0 131 0 131

Short-term debt 367,984 570,929 367,984 570,929

Liabilities from risk management activities current 1,543 85,381 1,543 85,381

Other current liabilities 608,959 619,513 608,959 619,513

Intercompany payables 0 0 0 0

Total current liabilities 978,486 1,275,954 978,486 1,275,954

Deferred income taxes 1,164,053 1,015,083 1,164,053 1,015,083

Liabilities from risk management activities noncurrent 6,133 9,206 6,133 9,206

Regulatory cost of removal obligation 359,299 381,164 359,299 381,164

Pension and postretirement liabilities 358,787 457,196 358,787 457,196

Deferred credits and other liabilities 37,563 41,524 37,563 41,524

Total Equity and Liabilities 7,940,401 7,495,675 7,940,401 7,495,675

Number Of Customers, Natural Gas Distribution 3,000,000 3,000,000

Number Of Divisions, Natural Gas Distribution 6 6

Number of States in which Entity Operates 8 8

Number of Operating Segments 3

Reportable Subsegments [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 3,886,257 3,438,483 4,286,435

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 3,886,257 3,438,483 4,286,435

Intersubsegment Eliminations [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 0 0 0

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 0 0 0

Natural Gas Distribution Segment [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 2,394,418 2,144,376 2,469,781

Operating revenues 360,386 467,144 905,176 666,787 282,516 315,634 871,067 676,113 2,399,493 2,145,330 2,470,664

Purchased gas cost 1,318,257 1,122,587 1,452,721

Gross profit 1,081,236 1,022,743 1,017,943

Operating expenses

Operation and maintenance 375,188 353,879 341,758

Depreciation and amortization 195,581 202,026 193,642

Taxes, other than income 167,374 162,377 160,455

Asset impairments 0 0

Total operating expenses 738,143 718,282 695,855

Operating income 343,093 304,461 322,088

Miscellaneous income (expense), net 2,535 (12,657) 16,242

Interest charges 98,296 110,642 115,740

Income (loss) before income taxes 247,332 181,162 222,590

Income tax expense 96,476 57,314 77,885

Income (loss) from continuing operations 150,856 123,848 144,705

Income from discontinued operations, net of tax 7,202 18,172 18,013

Gain (loss) on sale of discontinued operations, net of tax 5,649 6,349

Net income 163,707 148,369 162,718

Capital expenditures 528,599 546,818 496,899

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 2,394,418 2,144,376 2,469,781

Operating revenues 360,386 467,144 905,176 666,787 282,516 315,634 871,067 676,113 2,399,493 2,145,330 2,470,664

ASSETS

Net property, plant and equipment 4,719,873 4,432,017 4,719,873 4,432,017

Investment in subsidaries 831,136 747,496 831,136 747,496

Current assets

Cash and cash equivalents 4,237 12,787 4,237 12,787

Assets from risk management activities current 1,837 6,934 ^[1] 1,837 6,934 ^[1]

Other current assets 428,366 546,187 428,366 546,187

Intercompany receivables 783,738 636,557 783,738 636,557

Total current assets 1,218,178 1,202,465 1,218,178 1,202,465

Intangible assets 0 0 0 0

Goodwill 574,190 573,550 574,190 573,550

Assets from risk management activities noncurrent 109,354 2,283 109,354 2,283

Deferred charges and other assets 347,687 417,893 347,687 417,893

Total Assets 7,800,418 7,375,704 7,800,418 7,375,704

CAPITALIZATION AND LIABILITIES

Shareholders' equity 2,580,409 2,359,243 2,580,409 2,359,243

Long-term debt 2,455,671 1,956,305 2,455,671 1,956,305

Total capitalization 5,036,080 4,315,548 5,036,080 4,315,548

Current liabilities

Current maturities of long-term debt 0 0 0 0

Short-term debt 645,984 782,719 645,984 782,719

Liabilities from risk management activities current 1,543 85,366 ^[1] 1,543 85,366 ^[1]

Other current liabilities 491,681 526,089 491,681 526,089

Intercompany payables 0 0 0 0

Total current liabilities 1,139,208 1,394,174 1,139,208 1,394,174

Deferred income taxes 871,360 789,288 871,360 789,288

Liabilities from risk management activities noncurrent 0 0 0 0

Regulatory cost of removal obligation 359,299 381,164 359,299 381,164

Pension and postretirement liabilities 358,787 457,196 358,787 457,196

Deferred credits and other liabilities 35,684 38,334 35,684 38,334

Total Equity and Liabilities 7,800,418 7,375,704 7,800,418 7,375,704

Natural Gas Distribution Segment [Member] | Gas Sales Revenues [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 2,316,137 2,065,424 2,386,579

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 2,316,137 2,065,424 2,386,579

Natural Gas Distribution Segment [Member] | Gas Sales Revenues [Member] | Residential Customers [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 1,512,495 1,351,479 1,535,887

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 1,512,495 1,351,479 1,535,887

Natural Gas Distribution Segment [Member] | Gas Sales Revenues [Member] | Commercial Customers [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 661,930 587,651 685,380

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 661,930 587,651 685,380

Natural Gas Distribution Segment [Member] | Gas Sales Revenues [Member] | Industrial Customers [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 81,155 71,960 96,636

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 81,155 71,960 96,636

Natural Gas Distribution Segment [Member] | Gas Sales Revenues [Member] | Public Authority and Other Customers [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 60,557 54,334 68,676

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 60,557 54,334 68,676

Natural Gas Distribution Segment [Member] | Gas Transportation Revenues [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 55,938 53,924 57,331

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 55,938 53,924 57,331

Natural Gas Distribution Segment [Member] | Other Gas Revenues [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 22,343 25,028 25,871

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 22,343 25,028 25,871

Natural Gas Distribution Segment [Member] | Reportable Subsegments [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 2,394,418 2,144,376 2,469,781

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 2,394,418 2,144,376 2,469,781

Natural Gas Distribution Segment [Member] | Intersubsegment Eliminations [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 5,075 954 883

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 5,075 954 883

Regulated Transmission and Storage Segment [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 89,011 92,604 87,141

Operating revenues 72,330 74,041 61,848 60,681 65,482 67,073 58,037 56,759 268,900 247,351 219,373

Purchased gas cost 0 0 0

Gross profit 268,900 247,351 219,373

Operating expenses

Operation and maintenance 76,686 71,521 70,401

Depreciation and amortization 35,302 31,438 25,997

Taxes, other than income 17,059 15,568 14,700

Asset impairments 0 0

Total operating expenses 129,047 118,527 111,098

Operating income 139,853 128,824 108,275

Miscellaneous income (expense), net (2,285) (1,051) 4,715

Interest charges 30,678 29,414 31,432

Income (loss) before income taxes 106,890 98,359 81,558

Income tax expense 38,630 35,300 29,143

Income (loss) from continuing operations 68,260 63,059 52,415

Income from discontinued operations, net of tax 0 0 0

Gain (loss) on sale of discontinued operations, net of tax 0 0

Net income 68,260 63,059 52,415

Capital expenditures 313,230 175,768 118,452

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 89,011 92,604 87,141

Operating revenues 72,330 74,041 61,848 60,681 65,482 67,073 58,037 56,759 268,900 247,351 219,373

ASSETS

Net property, plant and equipment 1,249,767 979,443 1,249,767 979,443

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 11,709 11,788 11,709 11,788

Intercompany receivables 0 0 0 0

Total current assets 11,709 11,788 11,709 11,788

Intangible assets 0 0 0 0

Goodwill 132,462 132,422 132,462 132,422

Assets from risk management activities noncurrent 0 0 0 0

Deferred charges and other assets 19,227 24,353 19,227 24,353

Total Assets 1,413,165 1,148,006 1,413,165 1,148,006

CAPITALIZATION AND LIABILITIES

Shareholders' equity 396,421 328,161 396,421 328,161

Long-term debt 0 0 0 0

Total capitalization 396,421 328,161 396,421 328,161

Current liabilities

Current maturities of long-term debt 0 0 0 0

Short-term debt 0 0 0 0

Liabilities from risk management activities current 0 0 0 0

Other current liabilities 20,288 12,478 20,288 12,478

Intercompany payables 712,768 584,578 712,768 584,578

Total current liabilities 733,056 597,056 733,056 597,056

Deferred income taxes 283,554 220,647 283,554 220,647

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 134 2,142 134 2,142

Total Equity and Liabilities 1,413,165 1,148,006 1,413,165 1,148,006

Regulated Transmission and Storage Segment [Member] | Reportable Subsegments [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 89,011 92,604 87,141

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 89,011 92,604 87,141

Regulated Transmission and Storage Segment [Member] | Intersubsegment Eliminations [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 179,889 154,747 132,232

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 179,889 154,747 132,232

Nonregulated Segment [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 1,402,828 1,201,503 1,729,513

Operating revenues 348,061 421,808 428,948 399,894 280,114 256,250 370,763 444,176 1,598,711 1,351,303 2,024,893

Purchased gas cost 1,535,380 1,296,179 1,959,893

Gross profit 63,331 55,124 65,000

Operating expenses

Operation and maintenance 37,569 29,697 32,308

Depreciation and amortization 4,196 4,061 4,193

Taxes, other than income 2,639 3,128 2,612

Asset impairments 5,288 30,270

Total operating expenses 44,404 42,174 69,383

Operating income 18,927 12,950 (4,383)

Miscellaneous income (expense), net 2,316 1,035 657

Interest charges 2,168 3,084 4,015

Income (loss) before income taxes 19,075 10,901 (7,741)

Income tax expense 7,493 5,612 (209)

Income (loss) from continuing operations 11,582 5,289 (7,532)

Income from discontinued operations, net of tax 0 0 0

Gain (loss) on sale of discontinued operations, net of tax (355) 0

Net income 11,227 5,289 (7,532)

Capital expenditures 3,204 10,272 7,614

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 1,402,828 1,201,503 1,729,513

Operating revenues 348,061 421,808 428,948 399,894 280,114 256,250 370,763 444,176 1,598,711 1,351,303 2,024,893

ASSETS

Net property, plant and equipment 61,015 64,144 61,015 64,144

Investment in subsidaries (2,096) (2,096) (2,096) (2,096)

Current assets

Cash and cash equivalents 61,962 51,452 61,962 51,452

Assets from risk management activities current 16,262 ^[2] 17,773 ^[3] 16,262 ^[2] 17,773 ^[3]

Other current assets 452,126 404,097 452,126 404,097

Intercompany receivables 0 0 0 0

Total current assets 530,350 473,322 530,350 473,322

Intangible assets 121 164 121 164

Goodwill 34,711 34,711 34,711 34,711

Assets from risk management activities noncurrent 0 0 0 0

Deferred charges and other assets 8,728 6,733 8,728 6,733

Total Assets 632,829 576,978 632,829 576,978

CAPITALIZATION AND LIABILITIES

Shareholders' equity 434,715 419,335 434,715 419,335

Long-term debt 0 0 0 0

Total capitalization 434,715 419,335 434,715 419,335

Current liabilities

Current maturities of long-term debt 0 131 0 131

Short-term debt 0 0 0 0

Liabilities from risk management activities current 0 ^[2] 15 ^[3] 0 ^[2] 15 ^[3]

Other current liabilities 110,306 90,116 110,306 90,116

Intercompany payables 70,970 51,979 70,970 51,979

Total current liabilities 181,276 142,241 181,276 142,241

Deferred income taxes 8,960 5,148 8,960 5,148

Liabilities from risk management activities noncurrent 6,133 9,206 6,133 9,206

Regulatory cost of removal obligation 0 0 0 0

Pension and postretirement liabilities 0 0 0 0

Deferred credits and other liabilities 1,745 1,048 1,745 1,048

Total Equity and Liabilities 632,829 576,978 632,829 576,978

Nonregulated Segment [Member] | Reportable Subsegments [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 1,402,828 1,201,503 1,729,513

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 1,402,828 1,201,503 1,729,513

Nonregulated Segment [Member] | Intersubsegment Eliminations [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 195,883 149,800 295,380

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 195,883 149,800 295,380

Intersegment Elimination [Member]

Segment Reporting Information Profit Loss [Abstract]

Operating revenues (95,606) (105,058) (86,976) (93,207) (75,546) (62,543) (74,358) (93,054) (380,847) (305,501) (428,495)

Purchased gas cost (379,430) (304,022) (426,999)

Gross profit (1,417) (1,479) (1,496)

Operating expenses

Operation and maintenance (1,423) (1,484) (1,502)

Depreciation and amortization 0 0 0

Taxes, other than income 0 0 0

Asset impairments 0 0

Total operating expenses (1,423) (1,484) (1,502)

Operating income 6 5 6

Miscellaneous income (expense), net (2,763) (1,971) (430)

Interest charges (2,757) (1,966) (424)

Income (loss) before income taxes 0 0 0

Income tax expense 0 0 0

Income (loss) from continuing operations 0 0 0

Income from discontinued operations, net of tax 0 0 0

Gain (loss) on sale of discontinued operations, net of tax 0 0

Net income 0 0 0

Capital expenditures 0 0 0

Revenue from External Customers by Products and Services Table [Abstract]

Operating revenues (95,606) (105,058) (86,976) (93,207) (75,546) (62,543) (74,358) (93,054) (380,847) (305,501) (428,495)

ASSETS

Net property, plant and equipment 0 0 0 0

Investment in subsidaries (829,040) (745,400) (829,040) (745,400)

Current assets

Cash and cash equivalents 0 0 0 0

Assets from risk management activities current 0 0 0 0

Other current assets (293,233) (223,056) (293,233) (223,056)

Intercompany receivables (783,738) (636,557) (783,738) (636,557)

Total current assets (1,076,971) (859,613) (1,076,971) (859,613)

Intangible assets 0 0 0 0

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 (1,906,011) (1,605,013) (1,906,011) (1,605,013)

CAPITALIZATION AND LIABILITIES

Shareholders' equity (831,136) (747,496) (831,136) (747,496)

Long-term debt 0 0 0 0

Total capitalization (831,136) (747,496) (831,136) (747,496)

Current liabilities

Current maturities of long-term debt 0 0 0 0

Short-term debt (278,000) (211,790) (278,000) (211,790)

Liabilities from risk management activities current 0 0 0 0

Other current liabilities (13,316) (9,170) (13,316) (9,170)

Intercompany payables (783,738) (636,557) (783,738) (636,557)

Total current liabilities (1,075,054) (857,517) (1,075,054) (857,517)

Deferred income taxes 179 0 179 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 Equity and Liabilities (1,906,011) (1,605,013) (1,906,011) (1,605,013)

Intersegment Elimination [Member] | Reportable Subsegments [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues 0 0 0

Revenue from External Customers by Products and Services Table [Abstract]

Revenues 0 0 0

Intersegment Elimination [Member] | Intersubsegment Eliminations [Member]

Segment Reporting Information Profit Loss [Abstract]

Revenues (380,847) (305,501) (428,495)

Revenue from External Customers by Products and Services Table [Abstract]

Revenues $ (380,847) $ (305,501) $ (428,495)

[1] The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.

[2] Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.

[3] Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.

v2.4.0.8

Summary of Significant Accounting Policies (Table)
12 Months Ended

Sep. 30, 2013

Regulatory Assets and Liabilities [Abstract]

Schedule Of Regulatory Assets And Liabilities
Significant regulatory assets and liabilities as of September 30, 2013 and 2012 included the following:

September 30

2013

2012

(In thousands)
Regulatory assets:

Pension and postretirement benefit costs⁽¹⁾
$
187,977

$
296,160

Merger and integration costs, net
5,250

5,754

Deferred gas costs
15,152

31,359

Regulatory cost of removal asset
10,008

10,500

Rate case costs
6,329

4,661

Deferred franchise fees
—

2,714

Texas Rule 8.209⁽²⁾
30,364

5,370

APT annual adjustment mechanism
5,853

4,539

Recoverable loss on reacquired debt
21,435

23,944

Other
4,380

7,262

$
286,748

$
392,263

Regulatory liabilities:

Deferred gas costs
$
16,481

$
23,072

Deferred franchise fees
1,689

—

Regulatory cost of removal obligation
427,524

459,688

Other
7,887

5,637

$
453,581

$
488,397

⁽¹⁾
Includes $17.4 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.
⁽²⁾
Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.
^[1],[2]

[1] Includes $17.4 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.

[2] Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.

v2.4.0.8

Financial Instruments Descriptions (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended

Sep. 30, 2013

MMcf

Bcf

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2011

Interest Rate Hedges, Senior Notes 2011 Anticipated Issuance [Member]

Sep. 30, 2011

Interest Rate Hedges, Senior Notes 2011 Issuance [Member]

Sep. 30, 2013

Interest Rate Hedges, Senior Notes 2013 Issuance [Member]

Aug. 31, 2011

Interest Rate Hedges, Senior Notes 2013 Issuance [Member]

Sep. 30, 2013

Interest Rate Hedges, Short-term Note 2012 Issuance [Member]

Sep. 30, 2013

Interest Rate Hedges, Senior Notes 2015 Issuance [Member]

Sep. 30, 2013

Interest Rate Hedges, Senior Notes 2017 Issuance [Member]

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Minimum Hedge Percentage Of Anticipated Heating Season Gas 25.00%

Maximum Hedge Percentage Of Anticipated Heating Season Gas 50.00%

Hedge Percentage Of Actual Heating Season Gas 33.00%

Hedge Volume Of Actual Heating Season Gas 22,800

Weighted Average Cost Of Actual Heating Season Gas 4.03

Minimum Length Of Time Hedged In Cash Flow Hedge 0 years 1 month 0 days

Maximum Length of Time Hedged in Cash Flow Hedge 0 years 55 months 0 days

Net Open Positions 0.1

Cash Collateral Right To Reclaim Cash $ 24.8 $ 23.7

Gain Loss On Hedge Ineffectiveness 18.2 23.1 24.8

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 3.0 (2.5) (1.4)

Natural Gas Inventory [Abstract]

Inventory Write-down 1.7

Derivative [Line Items]

Derivative, Notional Amount 250 300 350 260 500 250

Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss) (20.1) 66.6

Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Net of Tax, Accumulated Other Comprehensive Income (Loss) 12.6

Gain (Loss) on Interest Rate Agreements Settlements $ 27.8

v2.4.0.8

Financial Instruments Balance Sheet Location (Details) (USD $)

Sep. 30, 2013

Sep. 30, 2012

Derivatives, Fair Value [Line Items]

Derivative Asset, Current $ 18,099,000 $ 24,707,000

Derivative Asset, Noncurrent 109,354,000 2,283,000

Derivative Liability, Current (1,543,000) (85,381,000)

Derivative Liability, Noncurrent (6,133,000) (9,206,000)

Derivative Assets (Liabilities), at Fair Value, Net 119,777,000 (67,597,000)

Cash Collateral Right To Reclaim Cash 24,800,000 23,700,000

Cash Held In Margin Accounts Offset Current Risk Management Liabilities 8,600,000 5,900,000

Cash Held In Margin Accounts Classified Current Risk Management Asset 16,200,000 17,800,000

Disposal Group, Including Discontinued Operation, Derivative Assets, Current 100,000

Disposal Group, Including Discontinued Operation, Derivative Liabilities, Current 300,000

Derivative, Fair Value, Net 94,948,000 (91,383,000)

Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net 103,210,000 (92,602,000)

Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 9,094,000 19,301,000

Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 107,928,000 1,923,000

Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (12,173,000) (108,827,000)

Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (1,639,000) (4,999,000)

Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net (8,262,000) 1,219,000

Not Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 67,225,000 105,475,000

Not Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 42,824,000 63,215,000

Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (72,419,000) (100,409,000)

Not Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (45,892,000) (67,062,000)

Natural Gas Distribution Segment [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Current 1,837,000 6,934,000 ^[1]

Derivative Asset, Noncurrent 109,354,000 2,283,000

Derivative Liability, Current (1,543,000) (85,366,000) ^[1]

Derivative Liability, Noncurrent 0 0

Derivative Assets (Liabilities), at Fair Value, Net 109,648,000 (76,149,000)

Derivative, Fair Value, Net 109,648,000 (76,260,000)

Natural Gas Distribution Segment [Member] | Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net 107,512,000 (85,040,000)

Natural Gas Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 0 0

Natural Gas Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 107,512,000 0

Natural Gas Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability 0 (85,040,000)

Natural Gas Distribution Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability 0 0

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net 2,136,000 8,780,000

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 1,837,000 7,082,000 ^[2]

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 1,842,000 2,283,000

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (1,543,000) (585,000) ^[3]

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability 0 0

Nonregulated Segment [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Current 16,262,000 ^[4] 17,773,000 ^[5]

Derivative Asset, Noncurrent 0 0

Derivative Liability, Current 0 ^[4] (15,000) ^[5]

Derivative Liability, Noncurrent (6,133,000) (9,206,000)

Derivative Assets (Liabilities), at Fair Value, Net 10,129,000 8,552,000

Cash Collateral Right To Reclaim Cash 24,800,000 23,700,000

Cash Held In Margin Accounts Offset Current Risk Management Liabilities 8,600,000 5,900,000

Cash Held In Margin Accounts Classified Current Risk Management Asset 16,200,000 17,800,000

Derivative, Fair Value, Net (14,700,000) (15,123,000)

Nonregulated Segment [Member] | Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net (4,302,000) (7,562,000)

Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 9,094,000 19,301,000

Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 416,000 1,923,000

Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (12,173,000) (23,787,000)

Nonregulated Segment [Member] | Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (1,639,000) (4,999,000)

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Derivative, Fair Value, Net (10,398,000) (7,561,000)

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 65,388,000 98,393,000

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Charges And Other Assets [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Asset 40,982,000 60,932,000

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability (70,876,000) (99,824,000)

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member] | Deferred Credits And Other Liabilities [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Gross Liability $ (45,892,000) $ (67,062,000)

[1] The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.

[2] Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.

[3] Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.

[4] Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.

[5] Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.

v2.4.0.8

Fair Value Measurements (Table)
12 Months Ended

Sep. 30, 2013

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, 2013 and 2012. 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, 2013

(In thousands)
Assets:

Financial instruments

Natural gas distribution segment
$
—

$
111,191

$
—

$
—

$
111,191

Nonregulated segment
745

115,135

—

(99,618
)

16,262

Total financial instruments
745

226,326

—

(99,618
)

127,453

Hedged portion of gas stored underground
44,758

—

—

—

44,758

Available-for-sale securities

Money market funds
—

4,428

—

—

4,428

Registered investment companies
40,094

—

—

—

40,094

Bonds
—

28,160

—

—

28,160

Total available-for-sale securities
40,094

32,588

—

—

72,682

Total assets
$
85,597

$
258,914

$
—

$
(99,618
)

$
244,893

Liabilities:

Financial instruments

Natural gas distribution segment
$
—

$
1,543

$
—

$
—

$
1,543

Nonregulated segment
158

130,422

—

(124,447
)

6,133

Total liabilities
$
158

$
131,965

$
—

$
(124,447
)

$
7,676

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, 2012

(In thousands)
Assets:

Financial instruments

Natural gas distribution segment
$
—

$
9,365

$
—

$
—

$
9,365

Nonregulated segment
714

179,835

—

(162,776
)

17,773

Total financial instruments
714

189,200

—

(162,776
)

27,138

Hedged portion of gas stored underground
67,192

—

—

—

67,192

Available-for-sale securities

Money market funds
—

1,634

—

—

1,634

Registered investment companies
40,212

—

—

—

40,212

Bonds
—

22,552

—

—

22,552

Total available-for-sale securities
40,212

24,186

—

—

64,398

Total assets
$
108,118

$
213,386

$
—

$
(162,776
)

$
158,728

Liabilities:

Financial instruments

Natural gas distribution segment
$
—

$
85,625

$
—

$
—

$
85,625

Nonregulated segment
4,563

191,109

—

(186,451
)

9,221

Total liabilities
$
4,563

$
276,734

$
—

$
(186,451
)

$
94,846

⁽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, 2013 we had $24.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting agreements and the remaining $16.2 million is classified as current risk management assets.
⁽³⁾
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting agreements and the remaining $17.8 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, 2013

Domestic equity mutual funds
$
27,043

$
7,476

$
(23
)

$
34,496

Foreign equity mutual funds
4,536

1,062

—

5,598

Bonds
28,016

168

(24
)

28,160

Money market funds
4,428

—

—

4,428

$
64,023

$
8,706

$
(47
)

$
72,682

As of September 30, 2012

Domestic equity mutual funds
$
25,779

$
8,183

$
—

$
33,962

Foreign equity mutual funds
5,568

682

—

6,250

Bonds
22,358

196

(2
)

22,552

Money market funds
1,634

—

—

1,634

$
55,339

$
9,061

$
(2
)

$
64,398

Other fair value measurements table
The following table presents the carrying value and fair value of our debt as of September 30, 2013:

September 30, 2013

(In thousands)
Carrying Amount
$
2,460,000

Fair Value
$
2,676,487

v2.4.0.8

Accumulated Other Comprehensive Income Affected Line Item in the Statement of Income (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Operation and maintenance $ (488,020) $ (453,613) $ (442,965)

Interest charges (128,385) (141,174) (150,763)

Income (loss) before income taxes 373,297 290,422 296,407

Income Tax Expense (Benefit) (142,599) (98,226) (106,819)

Income (loss) from continuing operations 7,536 33,474 112,340 77,348 (286) 28,014 102,084 62,384 230,698 192,196 189,588

Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Income (loss) from continuing operations (7,417)

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 2,166

Income (loss) before income taxes 2,166

Income Tax Expense (Benefit) (791)

Income (loss) from continuing operations 1,375

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Interest Rate Hedges [Member] [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Interest charges (3,489)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Commodity Contracts Cash Flow Hedges [Member] [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Purchased gas cost (10,778)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Income (loss) before income taxes (14,267)

Income Tax Expense (Benefit) 5,475

Income (loss) from continuing operations $ (8,792)

v2.4.0.8

Concentration of Credit Risk
12 Months Ended

Sep. 30, 2013

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 natural gas 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.

v2.4.0.8

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Statement of Comprehensive Income [Abstract]

Net income $ 243,194 $ 216,717 $ 207,601

Other comprehensive income (loss), net of tax [Abstract]

Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(186), $1,881 and $(953) (213) 3,103 (1,647)

Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $47,236, $(5,388) and $(16,850) 82,179 (10,116) (28,689)

Net unrealized gains on commodity cash flow hedges, net of tax of $2,889, $5,029 and $3,355 4,519 7,866 5,248

Total other comprehensive income (loss) 86,485 853 (25,088)

Total comprehensive income $ 329,679 $ 217,570 $ 182,513

v2.4.0.8

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (USD $)
In Thousands, except Share data, unless otherwise specified

Total

Common Stock [Member]

Additional Paid In Capital [Member]

Accumulated Other Comprehensive Income [Member]

Retained Earnings [Member]

Common shareholders' equity, beginning balance at Sep. 30, 2010 $ 2,178,348 $ 451 $ 1,714,364 $ (23,372) $ 486,905

Common stock shares outstanding, balance at Sep. 30, 2010 90,164,103

Net income 207,601 207,601

Other comprehensive income (loss) (25,088) (25,088)

Repurchase of common stock, shares (375,468)

Repurchase of common stock, amount 0 (2) 2

Repurchase of equity awards, shares (169,793)

Repurchase of equity awards, amount (5,299) (1) (5,298)

Cash dividends (124,011) (124,011)

Common stock issued:

Direct stock purchase plan, shares 0

Direct stock purchase plan, amount (54) 0 (54)

1998 Long-term incentive plan, shares 675,255

1998 Long-term incentive plan, amount 13,889 3 13,886 0

Employee stock-based compensation 9,958 9,958

Outside directors stock-for-fee plan, shares 2,385

Outside directors stock-for-fee-plan, amount 77 77

Common shareholders' equity, ending balance at Sep. 30, 2011 2,255,421 451 1,732,935 (48,460) 570,495

Common stock shares outstanding, ending balance at Sep. 30, 2011 90,296,482

Net income 216,717 216,717

Other comprehensive income (loss) 853 853

Repurchase of common stock, shares (387,991)

Repurchase of common stock, amount (12,535) (2) (12,533)

Repurchase of equity awards, shares (153,255)

Repurchase of equity awards, amount (5,219) 0 (5,219)

Cash dividends (125,796) (125,796)

Common stock issued:

Direct stock purchase plan, amount (65) 0 (65)

1998 Long-term incentive plan, shares 482,289

1998 Long-term incentive plan, amount 12,037 2 12,519 (484)

Employee stock-based compensation 17,752 17,752

Outside directors stock-for-fee plan, shares 2,375

Outside directors stock-for-fee-plan, amount 78 78

Common shareholders' equity, ending balance at Sep. 30, 2012 2,359,243 451 1,745,467 (47,607) 660,932

Common stock shares outstanding, ending balance at Sep. 30, 2012 90,239,900

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, 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 shareholders' equity, ending balance at Sep. 30, 2013 $ 2,580,409 $ 453 $ 1,765,811 $ 38,878 $ 775,267

Common stock shares outstanding, ending balance at Sep. 30, 2013 90,640,211

v2.4.0.8

Nature of Business
12 Months Ended

Sep. 30, 2013

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 transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated natural gas distribution divisions 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 natural gas distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.
Over the last two fiscal years, we have sold our natural gas distribution operations in four states to streamline our regulated operations. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers, and in August 2012, we completed the sale of our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers.
Our regulated transmission and storage business 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, natural gas distribution companies, including certain divisions of Atmos Energy and third parties.

v2.4.0.8

Selected Quarterly Financial Data (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Operating Revenues by Segment [Line Items]

Operating revenues $ 685,171 $ 857,935 $ 1,308,996 $ 1,034,155 $ 552,566 $ 576,414 $ 1,225,509 $ 1,083,994 $ 3,886,257 $ 3,438,483 $ 4,286,435

Selected Quarterly Financial Information [Abstract]

Gross profit 300,440 316,497 432,751 362,362 249,389 293,171 425,787 355,392 1,412,050 1,323,739 1,300,820

Operating income 50,383 86,396 210,178 154,922 22,791 81,546 202,432 139,471 501,879 446,240 425,986

Income (loss) from continuing operations 7,536 33,474 112,340 77,348 (286) 28,014 102,084 62,384 230,698 192,196 189,588

Income from discontinued operations, net of tax 0 0 4,085 3,117 1,904 3,118 7,027 6,123 7,202 18,172 18,013

Gain on sale of discontinued operations, net of tax 0 5,294 0 0 6,349 0 0 0 5,294 6,349 0

Net income 7,536 38,768 116,425 80,465 7,967 31,132 109,111 68,507 243,194 216,717 207,601

Income per share from continuing operations - basic (usd per share) $ 0.08 $ 0.37 $ 1.24 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.54 $ 2.12 $ 2.08

Income per share from discontinued operations - basic (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.04 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — basic (usd per share) $ 0.08 $ 0.43 $ 1.28 $ 0.89 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.68 $ 2.39 $ 2.28

Income per share from continuing operations - diluted (usd per share) $ 0.08 $ 0.36 $ 1.23 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.50 $ 2.10 $ 2.07

Income per share from discontinued operations - diluted (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.03 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — diluted (usd per share) $ 0.08 $ 0.42 $ 1.27 $ 0.88 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.64 $ 2.37 $ 2.27

Natural Gas Distribution Segment [Member]

Operating Revenues by Segment [Line Items]

Operating revenues 360,386 467,144 905,176 666,787 282,516 315,634 871,067 676,113 2,399,493 2,145,330 2,470,664

Selected Quarterly Financial Information [Abstract]

Gross profit 1,081,236 1,022,743 1,017,943

Operating income 343,093 304,461 322,088

Income (loss) from continuing operations 150,856 123,848 144,705

Income from discontinued operations, net of tax 7,202 18,172 18,013

Gain on sale of discontinued operations, net of tax 5,649 6,349

Net income 163,707 148,369 162,718

Regulated Transmission and Storage Segment [Member]

Operating Revenues by Segment [Line Items]

Operating revenues 72,330 74,041 61,848 60,681 65,482 67,073 58,037 56,759 268,900 247,351 219,373

Selected Quarterly Financial Information [Abstract]

Gross profit 268,900 247,351 219,373

Operating income 139,853 128,824 108,275

Income (loss) from continuing operations 68,260 63,059 52,415

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax 0 0

Net income 68,260 63,059 52,415

Nonregulated Segment [Member]

Operating Revenues by Segment [Line Items]

Operating revenues 348,061 421,808 428,948 399,894 280,114 256,250 370,763 444,176 1,598,711 1,351,303 2,024,893

Selected Quarterly Financial Information [Abstract]

Gross profit 63,331 55,124 65,000

Operating income 18,927 12,950 (4,383)

Income (loss) from continuing operations 11,582 5,289 (7,532)

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax (355) 0

Net income 11,227 5,289 (7,532)

Intersegment Elimination [Member]

Operating Revenues by Segment [Line Items]

Operating revenues (95,606) (105,058) (86,976) (93,207) (75,546) (62,543) (74,358) (93,054) (380,847) (305,501) (428,495)

Selected Quarterly Financial Information [Abstract]

Gross profit (1,417) (1,479) (1,496)

Operating income 6 5 6

Income (loss) from continuing operations 0 0 0

Income from discontinued operations, net of tax 0 0 0

Gain on sale of discontinued operations, net of tax 0 0

Net income $ 0 $ 0 $ 0

v2.4.0.8

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (PARENTHETICALS) (USD $)
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Statement of Stockholders' Equity [Abstract]

Cash dividends per share $ 1.40 $ 1.38 $ 1.36

v2.4.0.8

Financial Instruments (Table)
12 Months Ended

Sep. 30, 2013

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, 2013 and 2012:

Natural Gas
Distribution

Nonregulated

Total

(In thousands)
September 30, 2013

Assets from risk management activities, current⁽¹⁾
$
1,837

$
16,262

$
18,099

Assets from risk management activities, noncurrent
109,354

—

109,354

Liabilities from risk management activities, current⁽¹⁾
(1,543
)

—

(1,543
)
Liabilities from risk management activities, noncurrent
—

(6,133
)

(6,133
)
Net assets (liabilities)
$
109,648

$
10,129

$
119,777

September 30, 2012⁽³⁾

Assets from risk management activities, current⁽²⁾
$
6,934

$
17,773

$
24,707

Assets from risk management activities, noncurrent
2,283

—

2,283

Liabilities from risk management activities, current⁽²⁾
(85,366
)

(15
)

(85,381
)
Liabilities from risk management activities, noncurrent
—

(9,206
)

(9,206
)
Net assets (liabilities)
$
(76,149
)

$
8,552

$
(67,597
)

⁽¹⁾
Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.
⁽²⁾
Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.
⁽³⁾
The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.

Outstanding commodity contracts volumes table
As of September 30, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type

Hedge
Designation

Natural
Gas
Distribution

Nonregulated

Quantity (MMcf)
Commodity contracts

Fair Value

—

(13,033
)

Cash Flow

—

31,195

Not designated

29,185

75,683

29,185

93,845

Financial instruments on the balance sheet

Balance Sheet Location

Natural
Gas
Distribution

Nonregulated

Total

(In thousands)

September 30, 2013

Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

$
—

$
9,094

$
9,094

Noncurrent commodity contracts

Deferred charges and other assets

107,512

416

107,928

Liability Financial Instruments

Current commodity contracts

Other current liabilities

—

(12,173
)

(12,173
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(1,639
)

(1,639
)
Total

107,512

(4,302
)

103,210

Not Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

1,837

65,388

67,225

Noncurrent commodity contracts

Deferred charges and other assets

1,842

40,982

42,824

Liability Financial Instruments

Current commodity contracts

Other current liabilities

(1,543
)

(70,876
)

(72,419
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(45,892
)

(45,892
)
Total

2,136

(10,398
)

(8,262
)
Total Financial Instruments

$
109,648

$
(14,700
)

$
94,948

Balance Sheet Location

Natural
Gas
Distribution

Nonregulated

Total

(In thousands)
September 30, 2012

Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

$
—

$
19,301

$
19,301

Noncurrent commodity contracts

Deferred charges and other assets

—

1,923

1,923

Liability Financial Instruments

Current commodity contracts

Other current liabilities

(85,040
)

(23,787
)

(108,827
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(4,999
)

(4,999
)
Total

(85,040
)

(7,562
)

(92,602
)
Not Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets⁽¹⁾

7,082

98,393

105,475

Noncurrent commodity contracts

Deferred charges and other assets

2,283

60,932

63,215

Liability Financial Instruments

Current commodity contracts

Other current liabilities⁽²⁾

(585
)

(99,824
)

(100,409
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(67,062
)

(67,062
)
Total

8,780

(7,561
)

1,219

Total Financial Instruments

$
(76,260
)

$
(15,123
)

$
(91,383
)

⁽¹⁾
Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.
⁽²⁾
Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.

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, 2013, 2012 and 2011 is presented below.

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Commodity contracts
$
2,165

$
30,266

$
16,552

Fair value adjustment for natural gas inventory designated as the hedged item
15,938

(5,797
)

9,824

Total decrease in purchased gas cost
$
18,103

$
24,469

$
26,376

The decrease in purchased gas cost is comprised of the following:

Basis ineffectiveness
$
(208
)

$
1,170

$
803

Timing ineffectiveness
18,311

23,299

25,573

$
18,103

$
24,469

$
26,376

Cash flow hedges table
The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2013, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

Fiscal Year Ended September 30, 2013

Natural
Gas
Distribution

Regulated
Transmission
and Storage

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
)

Fiscal Year Ended September 30, 2012

Natural
Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Consolidated

(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

$
—

$
(62,678
)

$
(62,678
)
Loss arising from ineffective portion of commodity contracts
—

—

(1,369
)

(1,369
)
Total impact on purchased gas cost
—

—

(64,047
)

(64,047
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,009
)

—

—

(2,009
)
Total impact from cash flow hedges
$
(2,009
)

$
—

$
(64,047
)

$
(66,056
)

Fiscal Year Ended September 30, 2011

Natural
Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Consolidated

(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

$
—

$
(28,430
)

$
(28,430
)
Loss arising from ineffective portion of commodity contracts
—

—

(1,585
)

(1,585
)
Total impact on purchased gas cost
—

—

(30,015
)

(30,015
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,455
)

—

—

(2,455
)
Gain on unwinding of interest rate agreement reclassified from AOCI into miscellaneous income
21,803

6,000

—

27,803

Total impact from cash flow hedges
$
19,348

$
6,000

$
(30,015
)

$
(4,667
)

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, 2013 and 2012. 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

2013

2012

(In thousands)
Increase (decrease) in fair value:

Interest rate agreements
$
79,963

$
(11,458
)
Forward commodity contracts
(2,057
)

(30,366
)
Recognition of (gains) losses in earnings due to settlements:

Interest rate agreements
2,216

1,342

Forward commodity contracts
6,576

38,232

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾
$
86,698

$
(2,250
)

⁽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, 2013. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 as those financial instruments have not yet settled.

Interest Rate
Agreements

Commodity
Contracts

Total

(In thousands)
2014
$
(2,686
)

$
(3,748
)

$
(6,434
)
2015
(804
)

(425
)

(1,229
)
2016
(634
)

(163
)

(797
)
2017
(735
)

(109
)

(844
)
2018
(936
)

(31
)

(967
)
Thereafter
(24,569
)

—

(24,569
)
Total⁽¹⁾
$
(30,364
)

$
(4,476
)

$
(34,840
)

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

v2.4.0.8

Schedule II - Valuation and Qualifying Accounts
12 Months Ended

Sep. 30, 2013

Valuation and Qualifying Accounts [Abstract]

Schedule II Valuation and Qualifying Accounts
ATMOS ENERGY CORPORATION
Valuation and Qualifying Accounts
Three Years Ended September 30, 2013

Additions

Balance at
beginning
of period

Charged to
cost &
expenses

Charged to
other
accounts

Deductions

Balance
at end
of period

(In thousands)

2013

Allowance for doubtful accounts
$
9,425

$
14,484

$
—

$
3,285

⁽¹⁾

$
20,624

2012

Allowance for doubtful accounts
$
7,440

$
8,901

$
—

$
6,916

⁽¹⁾

$
9,425

2011

Allowance for doubtful accounts
$
12,701

$
2,201

$
—

$
7,462

⁽¹⁾

$
7,440

⁽¹⁾
Uncollectible accounts written off.

v2.4.0.8

Segment Information (Table)
12 Months Ended

Sep. 30, 2013

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, 2013

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,394,418

$
89,011

$
1,402,828

$
—

$
3,886,257

Intersegment revenues
5,075

179,889

195,883

(380,847
)

—

2,399,493

268,900

1,598,711

(380,847
)

3,886,257

Purchased gas cost
1,318,257

—

1,535,380

(379,430
)

2,474,207

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

Year Ended September 30, 2012

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,144,376

$
92,604

$
1,201,503

$
—

$
3,438,483

Intersegment revenues
954

154,747

149,800

(305,501
)

—

2,145,330

247,351

1,351,303

(305,501
)

3,438,483

Purchased gas cost
1,122,587

—

1,296,179

(304,022
)

2,114,744

Gross profit
1,022,743

247,351

55,124

(1,479
)

1,323,739

Operating expenses

Operation and maintenance
353,879

71,521

29,697

(1,484
)

453,613

Depreciation and amortization
202,026

31,438

4,061

—

237,525

Taxes, other than income
162,377

15,568

3,128

—

181,073

Asset impairments
—

—

5,288

—

5,288

Total operating expenses
718,282

118,527

42,174

(1,484
)

877,499

Operating income
304,461

128,824

12,950

5

446,240

Miscellaneous income (expense)
(12,657
)

(1,051
)

1,035

(1,971
)

(14,644
)
Interest charges
110,642

29,414

3,084

(1,966
)

141,174

Income from continuing operations before income taxes
181,162

98,359

10,901

—

290,422

Income tax expense
57,314

35,300

5,612

—

98,226

Income from continuing operations
123,848

63,059

5,289

—

192,196

Income from discontinued operations, net of tax
18,172

—

—

—

18,172

Gain on sale of discontinued operations, net of tax
6,349

—

—

—

6,349

Net income
$
148,369

$
63,059

$
5,289

$
—

$
216,717

Capital expenditures
$
546,818

$
175,768

$
10,272

$
—

$
732,858

Year Ended September 30, 2011

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,469,781

$
87,141

$
1,729,513

$
—

$
4,286,435

Intersegment revenues
883

132,232

295,380

(428,495
)

—

2,470,664

219,373

2,024,893

(428,495
)

4,286,435

Purchased gas cost
1,452,721

—

1,959,893

(426,999
)

2,985,615

Gross profit
1,017,943

219,373

65,000

(1,496
)

1,300,820

Operating expenses

Operation and maintenance
341,758

70,401

32,308

(1,502
)

442,965

Depreciation and amortization
193,642

25,997

4,193

—

223,832

Taxes, other than income
160,455

14,700

2,612

—

177,767

Asset impairments
—

—

30,270

—

30,270

Total operating expenses
695,855

111,098

69,383

(1,502
)

874,834

Operating income (loss)
322,088

108,275

(4,383
)

6

425,986

Miscellaneous income
16,242

4,715

657

(430
)

21,184

Interest charges
115,740

31,432

4,015

(424
)

150,763

Income (loss) from continuing operations before income taxes
222,590

81,558

(7,741
)

—

296,407

Income tax expense (benefit)
77,885

29,143

(209
)

—

106,819

Income (loss) from continuing operations
144,705

52,415

(7,532
)

—

189,588

Income from discontinued operations, net of tax
18,013

—

—

—

18,013

Net income (loss)
$
162,718

$
52,415

$
(7,532
)

$
—

$
207,601

Capital expenditures
$
496,899

$
118,452

$
7,614

$
—

$
622,965

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.

2013

2012

2011

(In thousands)
Natural gas distribution revenues:

Gas sales revenues:

Residential
$
1,512,495

$
1,351,479

$
1,535,887

Commercial
661,930

587,651

685,380

Industrial
81,155

71,960

96,636

Public authority and other
60,557

54,334

68,676

Total gas sales revenues
2,316,137

2,065,424

2,386,579

Transportation revenues
55,938

53,924

57,331

Other gas revenues
22,343

25,028

25,871

Total natural gas distribution revenues
2,394,418

2,144,376

2,469,781

Regulated transmission and storage revenues
89,011

92,604

87,141

Nonregulated revenues
1,402,828

1,201,503

1,729,513

Total operating revenues
$
3,886,257

$
3,438,483

$
4,286,435

Schedule of segment reporting balance sheet information, by segment
Balance sheet information at September 30, 2013 and 2012 by segment is presented in the following tables.

September 30, 2013

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
ASSETS

Property, plant and equipment, net
$
4,719,873

$
1,249,767

$
61,015

$
—

$
6,030,655

Investment in subsidiaries
831,136

—

(2,096
)

(829,040
)

—

Current assets

Cash and cash equivalents
4,237

—

61,962

—

66,199

Assets from risk management activities
1,837

—

16,262

—

18,099

Other current assets
428,366

11,709

452,126

(293,233
)

598,968

Intercompany receivables
783,738

—

—

(783,738
)

—

Total current assets
1,218,178

11,709

530,350

(1,076,971
)

683,266

Intangible assets
—

—

121

—

121

Goodwill
574,190

132,462

34,711

—

741,363

Noncurrent assets from risk management activities
109,354

—

—

—

109,354

Deferred charges and other assets
347,687

19,227

8,728

—

375,642

$
7,800,418

$
1,413,165

$
632,829

$
(1,906,011
)

$
7,940,401

CAPITALIZATION AND LIABILITIES

Shareholders’ equity
$
2,580,409

$
396,421

$
434,715

$
(831,136
)

$
2,580,409

Long-term debt
2,455,671

—

—

—

2,455,671

Total capitalization
5,036,080

396,421

434,715

(831,136
)

5,036,080

Current liabilities

Current maturities of long-term debt
—

—

—

—

—

Short-term debt
645,984

—

—

(278,000
)

367,984

Liabilities from risk management activities
1,543

—

—

—

1,543

Other current liabilities
491,681

20,288

110,306

(13,316
)

608,959

Intercompany payables
—

712,768

70,970

(783,738
)

—

Total current liabilities
1,139,208

733,056

181,276

(1,075,054
)

978,486

Deferred income taxes
871,360

283,554

8,960

179

1,164,053

Noncurrent liabilities from risk management activities
—

—

6,133

—

6,133

Regulatory cost of removal obligation
359,299

—

—

—

359,299

Pension and postretirement liabilities
358,787

—

—

—

358,787

Deferred credits and other liabilities
35,684

134

1,745

—

37,563

$
7,800,418

$
1,413,165

$
632,829

$
(1,906,011
)

$
7,940,401

September 30, 2012

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
ASSETS

Property, plant and equipment, net
$
4,432,017

$
979,443

$
64,144

$
—

$
5,475,604

Investment in subsidiaries
747,496

—

(2,096
)

(745,400
)

—

Current assets

Cash and cash equivalents
12,787

—

51,452

—

64,239

Assets from risk management activities
6,934

—

17,773

—

24,707

Other current assets
546,187

11,788

404,097

(223,056
)

739,016

Intercompany receivables
636,557

—

—

(636,557
)

—

Total current assets
1,202,465

11,788

473,322

(859,613
)

827,962

Intangible assets
—

—

164

—

164

Goodwill
573,550

132,422

34,711

—

740,683

Noncurrent assets from risk management activities
2,283

—

—

—

2,283

Deferred charges and other assets
417,893

24,353

6,733

—

448,979

$
7,375,704

$
1,148,006

$
576,978

$
(1,605,013
)

$
7,495,675

CAPITALIZATION AND LIABILITIES

Shareholders’ equity
$
2,359,243

$
328,161

$
419,335

$
(747,496
)

$
2,359,243

Long-term debt
1,956,305

—

—

—

1,956,305

Total capitalization
4,315,548

328,161

419,335

(747,496
)

4,315,548

Current liabilities

Current maturities of long-term debt
—

—

131

—

131

Short-term debt
782,719

—

—

(211,790
)

570,929

Liabilities from risk management activities
85,366

—

15

—

85,381

Other current liabilities
526,089

12,478

90,116

(9,170
)

619,513

Intercompany payables
—

584,578

51,979

(636,557
)

—

Total current liabilities
1,394,174

597,056

142,241

(857,517
)

1,275,954

Deferred income taxes
789,288

220,647

5,148

—

1,015,083

Noncurrent liabilities from risk management activities
—

—

9,206

—

9,206

Regulatory cost of removal obligation
381,164

—

—

—

381,164

Pension and postretirement liabilities
457,196

—

—

—

457,196

Deferred credits and other liabilities
38,334

2,142

1,048

—

41,524

$
7,375,704

$
1,148,006

$
576,978

$
(1,605,013
)

$
7,495,675

v2.4.0.8

Details of Selected Consolidated Balance Sheet Captions (Table)
12 Months Ended

Sep. 30, 2013

Details Of Selected Consolidated Balance Sheet Captions Disclosure [Abstract]

Accounts Receivables Detail Table
Accounts receivable was comprised of the following at September 30, 2013 and 2012:

September 30

2013

2012

(In thousands)
Billed accounts receivable
$
230,712

$
177,953

Unbilled revenue
58,710

42,694

Other accounts receivable
33,194

23,304

Total accounts receivable
322,616

243,951

Less: allowance for doubtful accounts
(20,624
)

(9,425
)
Net accounts receivable
$
301,992

$
234,526

Other Current Assets Detail Table
Other current assets as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Assets from risk management activities
$
18,099

$
24,707

Deferred gas costs
15,152

31,359

Taxes receivable
3,141

1,291

Current deferred tax asset
—

27,091

Prepaid expenses
21,666

17,114

Materials and supplies
5,511

5,872

Assets held for sale⁽¹⁾
—

154,571

Other
6,765

10,777

Total
$
70,334

$
272,782

⁽¹⁾As discussed in Note 16, assets and liabilities related to our Georgia operations were classified as “assets held for sale” in other current assets and liabilities in our consolidated balance sheets at September 30, 2012.

Property, Plant and Equipment Detail Table
Property, plant and equipment was comprised of the following as of September 30, 2013 and 2012:

September 30

2013

2012

(In thousands)
Production plant
$
5,020

$
5,020

Storage plant
262,246

232,260

Transmission plant
1,362,662

1,185,007

Distribution plant
5,061,711

4,680,877

General plant
716,189

717,568

Intangible plant
38,444

39,626

7,446,272

6,860,358

Construction in progress
275,747

274,112

7,722,019

7,134,470

Less: accumulated depreciation and amortization
(1,691,364
)

(1,658,866
)
Net property, plant and equipment⁽¹⁾
$
6,030,655

$
5,475,604

⁽¹⁾
Net property, plant and equipment includes plant acquisition adjustments of ($83.8) million and ($91.5) million at September 30, 2013 and 2012.

Goodwill Detail Table
The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2013:

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Total

(In thousands)
Balance as of September 30, 2012
$
573,550

$
132,422

$
34,711

$
740,683

Deferred tax adjustments on prior acquisitions⁽¹⁾
640

40

—

680

Balance as of September 30, 2013
$
574,190

$
132,462

$
34,711

$
741,363

⁽¹⁾
During the preparation of the fiscal 2013 tax provision, we adjusted 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, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Marketable securities
$
72,682

$
64,398

Regulatory assets
273,287

358,495

Deferred financing costs
15,199

11,157

Assets from risk management activities
109,354

2,283

Other
14,474

14,929

Total
$
484,996

$
451,262

Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Trade accounts payable
$
70,116

$
82,531

Accrued gas payable
121,202

81,658

Accrued liabilities
50,293

51,040

Total
$
241,611

$
215,229

Other Current Liabilities Detail Table
Other current liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Customer credit balances and deposits
$
76,313

$
100,926

Accrued employee costs
54,034

37,675

Deferred gas costs
16,481

23,072

Accrued interest
36,744

34,451

Liabilities from risk management activities
1,543

85,381

Taxes payable
66,960

64,319

Pension and postretirement obligations
22,940

39,625

Current deferred tax liability
14,697

—

Regulatory cost of removal accrual
68,225

78,525

Liabilities held for sale
—

11,573

Other
10,954

14,118

Total
$
368,891

$
489,665

Deferred Credits and Other Liabilities Detail Table
Deferred credits and other liabilities as of September 30, 2013 and 2012 were comprised of the following accounts.

September 30

2013

2012

(In thousands)
Customer advances for construction
$
11,723

$
12,937

Regulatory liabilities
1,123

5,638

Asset retirement obligation
6,764

10,394

Liabilities from risk management activities
6,133

9,206

Other
17,953

12,555

Total
$
43,696

$
50,730

v2.4.0.8

Retirement and Post-Retirement Employee Benefit Plans Net Periodic Cost (Details) (USD $)
0 Months Ended 12 Months Ended

Apr. 02, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Service cost $ 17,754,000 $ 15,084,000 $ 14,384,000

Interest cost 19,334,000 21,568,000 22,264,000

Expected return on assets (22,955,000) (21,474,000) (24,817,000)

Amortization of prior service cost (141,000) (141,000) (429,000)

Recognized actuarial loss 19,066,000 14,451,000 9,498,000

Curtailment loss 0 0 (40,000)

Net periodic cost 33,058,000 29,488,000 20,860,000

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Service cost 18,800,000 16,353,000 14,403,000

Interest cost 12,964,000 13,861,000 12,813,000

Expected return on assets (3,988,000) (2,607,000) (2,727,000)

Amortization of transition asset 1,081,000 1,511,000 1,511,000

Amortization of prior service cost (1,450,000) (1,450,000) (1,450,000)

Recognized actuarial loss 4,196,000 2,648,000 347,000

Net periodic cost 31,603,000 30,316,000 24,897,000

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Service cost 3,039,000 2,108,000 2,768,000

Interest cost 4,755,000 5,142,000 5,825,000

Amortization of transition asset 0 0 0

Amortization of prior service cost 0 0 0

Recognized actuarial loss 2,918,000 2,118,000 2,239,000

Settlements (3,200,000) 3,160,000 0 0

Net periodic cost 13,872,000 9,368,000 10,832,000

Effect on Net Periodic Cost Due To Discount Rate Change, Remaining Fiscal Year $ 100,000

v2.4.0.8

Earnings Per Share (Details) (USD $)
In Thousands, except Share data, unless otherwise specified
3 Months Ended 12 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Basic Earnings per Share from Continuing Operations

Income from continuing operations $ 7,536 $ 33,474 $ 112,340 $ 77,348 $ (286) $ 28,014 $ 102,084 $ 62,384 $ 230,698 $ 192,196 $ 189,588

Less: Income from continuing operations allocated to participating securities 775 793 1,980

Income from continuing operations available to common shareholders 229,923 191,403 187,608

Basic weighted average shares outstanding (shares) 90,533,000 90,150,000 90,201,000

Income per share from continuing operations - basic (usd per share) $ 0.08 $ 0.37 $ 1.24 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.54 $ 2.12 $ 2.08

Basic Earnings per Share from Discontinued Operations

Income from discontinued operations 12,496 24,521 18,013

Less: Income from discontinued operations allocated to participating securities 42 101 188

Income from discontinued operations available to common shareholders 12,454 24,420 17,825

Income (loss) from discontinued operations per share - Basic (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.04 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — basic (usd per share) $ 0.08 $ 0.43 $ 1.28 $ 0.89 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.68 $ 2.39 $ 2.28

Diluted Earnings per Share from Continuing Operations

Effect of dilutive stock options and other shares 5 4 4

Income (loss) from continuing operations available to common shareholders 229,928 191,407 187,612

Additional dilutive stock options and other shares 1,178,000 1,022,000 451,000

Diluted weighted average shares outstanding (shares) 91,711,000 91,172,000 90,652,000

Income per share from continuing operations - diluted (usd per share) $ 0.08 $ 0.36 $ 1.23 $ 0.85 $ 0.00 $ 0.31 $ 1.12 $ 0.68 $ 2.50 $ 2.10 $ 2.07

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 $ 12,454 $ 24,420 $ 17,825

Additional dilutive stock options and other shares 1,178,000 1,022,000 451,000

Diluted weighted average shares outstanding 91,711,000 91,172,000 90,652,000

Income per share from discontinued operations - diluted (usd per share) $ 0.00 $ 0.06 $ 0.04 $ 0.03 $ 0.09 $ 0.03 $ 0.08 $ 0.07 $ 0.14 $ 0.27 $ 0.20

Net income per share — diluted (usd per share) $ 0.08 $ 0.42 $ 1.27 $ 0.88 $ 0.09 $ 0.34 $ 1.20 $ 0.75 $ 2.64 $ 2.37 $ 2.27

Earnings Per Share Diluted Other Disclosures Abstract

Anti-dilutive stock options excluded from computation of diluted earnings per share 0 0 0

v2.4.0.8

Selected Quarterly Financial Data (Table)
12 Months Ended

Sep. 30, 2013

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 2013:

Operating revenues

Natural gas distribution
$
666,787

$
905,176

$
467,144

$
360,386

Regulated transmission and storage
60,681

61,848

74,041

72,330

Nonregulated
399,894

428,948

421,808

348,061

Intersegment eliminations
(93,207
)

(86,976
)

(105,058
)

(95,606
)

1,034,155

1,308,996

857,935

685,171

Gross profit
362,362

432,751

316,497

300,440

Operating income
154,922

210,178

86,396

50,383

Income from continuing operations
77,348

112,340

33,474

7,536

Income from discontinued operations
3,117

4,085

—

—

Gain on sale of discontinued operations
—

—

5,294

—

Net income
80,465

116,425

38,768

7,536

Basic earnings per share

Income per share from continuing operations
$
0.85

$
1.24

$
0.37

$
0.08

Income per share from discontinued operations
$
0.04

$
0.04

$
0.06

$
—

Net income per share — basic
$
0.89

$
1.28

$
0.43

$
0.08

Diluted earnings per share

Income per share from continuing operations
$
0.85

$
1.23

$
0.36

$
0.08

Income per share from discontinued operations
$
0.03

$
0.04

$
0.06

$
—

Net income per share — diluted
$
0.88

$
1.27

$
0.42

$
0.08

Quarter Ended

December 31

March 31

June 30

September 30

(In thousands, except per share data)
Fiscal year 2012:

Operating revenues

Natural gas distribution
$
676,113

$
871,067

$
315,634

$
282,516

Regulated transmission and storage
56,759

58,037

67,073

65,482

Nonregulated
444,176

370,763

256,250

280,114

Intersegment eliminations
(93,054
)

(74,358
)

(62,543
)

(75,546
)

1,083,994

1,225,509

576,414

552,566

Gross profit
355,392

425,787

293,171

249,389

Operating income
139,471

202,432

81,546

22,791

Income (loss) from continuing operations
62,384

102,084

28,014

(286
)
Income from discontinued operations
6,123

7,027

3,118

1,904

Gain on sale of discontinued operations
—

—

—

6,349

Net income
68,507

109,111

31,132

7,967

Basic earnings per share

Income per share from continuing operations
$
0.68

$
1.12

$
0.31

$
—

Income per share from discontinued operations
$
0.07

0.08

$
0.03

$
0.09

Net income per share — basic
$
0.75

$
1.20

$
0.34

$
0.09

Diluted earnings per share

Income per share from continuing operations
$
0.68

$
1.12

$
0.31

$
—

Income per share from discontinued operations
$
0.07

$
0.08

$
0.03

$
0.09

Net income per share — diluted
$
0.75

$
1.20

$
0.34

$
0.09

v2.4.0.8

CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) (USD $)
In Thousands, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Statement of Financial Position [Abstract]

Allowance for doubtful accounts $ 20,624 $ 9,425

Common Stock, Par Value Per Share $ 0 $ 0

Common Stock, Stated Value Per Share $ 0.005 $ 0.005

Common Stock, Shares Authorized 200,000,000 200,000,000

Common Stock, Shares, Issued 90,640,211 90,239,900

v2.4.0.8

Earnings Per Share
12 Months Ended

Sep. 30, 2013

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:

2013

2012

2011

(In thousands, except per share data)
Basic Earnings Per Share from continuing operations

Income from continuing operations
$
230,698

$
192,196

$
189,588

Less: Income from continuing operations allocated to participating securities
775

793

1,980

Income from continuing operations available to common shareholders
$
229,923

$
191,403

$
187,608

Basic weighted average shares outstanding
90,533

90,150

90,201

Income from continuing operations per share — Basic
$
2.54

$
2.12

$
2.08

Basic Earnings Per Share from discontinued operations

Income from discontinued operations
$
12,496

$
24,521

$
18,013

Less: Income from discontinued operations allocated to participating securities
42

101

188

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Basic weighted average shares outstanding
90,533

90,150

90,201

Income from discontinued operations per share — Basic
$
0.14

$
0.27

$
0.20

Net income per share — Basic
$
2.68

$
2.39

$
2.28

Diluted Earnings Per Share from continuing operations

Income from continuing operations available to common shareholders
$
229,923

$
191,403

$
187,608

Effect of dilutive stock options and other shares
5

4

4

Income from continuing operations available to common shareholders
$
229,928

$
191,407

$
187,612

Basic weighted average shares outstanding
90,533

90,150

90,201

Additional dilutive stock options and other shares
1,178

1,022

451

Diluted weighted average shares outstanding
91,711

91,172

90,652

Income from continuing operations per share — Diluted
$
2.50

$
2.10

$
2.07

Diluted Earnings Per Share from discontinued operations

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Effect of dilutive stock options and other shares
—

—

—

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Basic weighted average shares outstanding
90,533

90,150

90,201

Additional dilutive stock options and other shares
1,178

1,022

451

Diluted weighted average shares outstanding
91,711

91,172

90,652

Income from discontinued operations per share — Diluted
$
0.14

$
0.27

$
0.20

Net income per share — Diluted
$
2.64

$
2.37

$
2.27

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the fiscal years ended September 30, 2013, 2012 and 2011.

v2.4.0.8

CONSOLIDATED STATEMENTS OF INCOME (PARENTHETICALS) (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Income Statement [Abstract]

Discontinued Operation Tax Effect Of Income Loss From Discontinued Operation During Phase Out Period $ 3,986 $ 10,066 $ 12,372

Discontinued Operation, Tax Effect of Income (Loss) from Disposal of Discontinued Operation $ 2,909 $ 3,519 $ 0

v2.4.0.8

CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

ASSETS

Property, plant and equipment $ 7,446,272 $ 6,860,358

Construction in progress 275,747 274,112

Total property, plant and equipment and construction in progress 7,722,019 7,134,470

Less accumulated depreciation and amortization 1,691,364 1,658,866

Net property, plant and equipment 6,030,655 5,475,604

Current assets

Cash and cash equivalents 66,199 64,239

Accounts receivable, less allowance for doubtful accounts of $20,624 in 2013 and $9,425 in 2012 301,992 234,526

Gas stored underground 244,741 256,415

Other current assets 70,334 272,782

Total current assets 683,266 827,962

Goodwill and intangible assets 741,484 740,847

Deferred charges and other assets 484,996 451,262

Total assets 7,940,401 7,495,675

Shareholders' equity

Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2013 — 90,640,211 shares, 2012 — 90,239,900 shares 453 451

Additional paid-in capital 1,765,811 1,745,467

Accumulated other comprehensive income (loss) 38,878 (47,607)

Retained earnings 775,267 660,932

Shareholders' equity 2,580,409 2,359,243

Long-term debt 2,455,671 1,956,305

Total capitalization 5,036,080 4,315,548

Current liabilities

Accounts payable and accrued liabilities 241,611 215,229

Other current liabilities 368,891 489,665

Short-term debt 367,984 570,929

Current maturities of long-term debt 0 131

Total current liabilities 978,486 1,275,954

Deferred income taxes 1,164,053 1,015,083

Regulatory cost of removal obligation 359,299 381,164

Pension and postretirement liabilities 358,787 457,196

Deferred credits and other liabilities 43,696 50,730

Total shareholders' equity and liabilities $ 7,940,401 $ 7,495,675

v2.4.0.8

Debt (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended

Sep. 30, 2013

credit_facility

Sep. 30, 2012

Sep. 30, 2013

Minimum [Member]

Sep. 30, 2013

Maximum [Member]

Sep. 30, 2013

Regulated Facilities [Member]

Sep. 30, 2013

First Facility Regulated Operations [Member]

Sep. 30, 2012

First Facility Regulated Operations [Member]

Sep. 30, 2013

Second Facility Regulated Operations [Member]

Sep. 30, 2013

Third Facility Regulated Operations [Member]

Sep. 30, 2013

Intercompany Facility Regulated Operations [Member]

Sep. 30, 2013

Nonregulated Facilities [Member]

Dec. 05, 2012

Nonregulated Facilities [Member]

credit_facility

Dec. 05, 2012

Committed Facility Nonregulated Operations [Member]

Sep. 30, 2013

Committed Facility Nonregulated Operations [Member]

Sep. 30, 2012

Committed Facility Nonregulated Operations [Member]

Sep. 30, 2013

Uncommitted Facility Nonregulated Operations [Member]

credit_facility

Sep. 30, 2013

Intercompany Facility Nonregulated Operations [Member]

Sep. 30, 2012

Intercompany Facility Nonregulated Operations [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2014 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2014 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2017 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2017 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2019 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2019 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2034 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2034 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2041 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2041 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2043 [Member]

Sep. 30, 2013

Unsecured Senior Notes Due 2043 [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2043 [Member]

Sep. 30, 2013

Bridge Loan [Member]

Sep. 30, 2013

Medium Term Notes Due 2025 [Member]

Sep. 30, 2012

Medium Term Notes Due 2025 [Member]

Sep. 30, 2013

Unsecured Debentures Due 2028 [Member]

Sep. 30, 2012

Unsecured Debentures Due 2028 [Member]

Sep. 30, 2013

Rental Property Term Note [Member]

Sep. 30, 2012

Rental Property Term Note [Member]

Sep. 30, 2012

Unsecured Senior Notes Due 2013 [Member]

Debt Instrument [Line Items]

Debt Instrument Interest Rate Stated Percentage 4.95% 6.35% 8.50% 5.95% 5.50% 4.15% 4.15% 6.67% 6.75%

Debt Instrument Maturity Date Oct. 15, 2014 Jun. 15, 2017 Mar. 15, 2019 Oct. 15, 2034 Jun. 15, 2041 Jan. 15, 2043 Dec. 15, 2025 Jul. 15, 2028 Jul. 01, 2013

Debt Instrument Carrying Amount $ 2,460,000,000 $ 1,960,131,000 $ 500,000,000 $ 500,000,000 $ 250,000,000 $ 250,000,000 $ 450,000,000 $ 450,000,000 $ 200,000,000 $ 200,000,000 $ 400,000,000 $ 400,000,000 $ 500,000,000 $ 500,000,000 $ 0 $ 10,000,000 $ 10,000,000 $ 150,000,000 $ 150,000,000 $ 0 $ 131,000

Debt Instrument Unamortized Discount 4,329,000 3,695,000

Current maturities of long-term debt 0 131,000

Long-term debt 2,455,671,000 1,956,305,000

Debt Instrument Interest Rate Effective Percentage 4.67% 4.67%

Net Proceeds From Issuance of Debt 494,000,000

Remaining Proceeds From Issuance Of Debt 234,000,000

Extinguishment of Debt, Amount 260,000,000 250,000,000

Extinguishment of Debt, Interest Terms LIBOR based rate plus a company specific spread, 0.05125

Line Of Credit Facility [Line Items]

Number of Credit Facilities 4 2 1

Line Of Credit Facility Maximum Borrowing Capacity 1,000,000,000 985,000,000 950,000,000 750,000,000 25,000,000 10,000,000 500,000,000 25,000,000 200,000,000 25,000,000 500,000,000

Line of Credit Facility, Term 5 years 364 days 3 years

Line Of Credit Facility Interest Rate Description a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to two percent, based on the Company’s credit ratings a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin LIBOR-based rate plus 1.5 percent. 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 a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s borrowings under its committed line of credit facility plus 0.75 percent

Line Of Credit Facility Amount Outstanding 0 0 0 278,000,000 0

Line of Credit Facility, Current Available Borrowing Capacity 582,000,000 37,400,000

Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature 1,200,000,000 500,000,000

Debt Instrument, Covenant, Excess Debt Trigger 15,000,000 100,000,000

Long-term Debt, Other Disclosures [Abstract]

Authorized Commercial Paper 950,000,000

Commercial Paper 368,000,000 310,900,000

Commercial Paper Weighted Average Interest Rate 0.25% 0.48%

Debt Covenant, Total Debt To Total Capital Ratio 70.00%

Ratio of Total Debt to Total Capital 54.00%

Regulated Operations Letters of Credit Outstanding, Amount 5,900,000

Debt and Equity Securities Authorized for Issuance 1,750,000,000

Debt Instrument Covenant Compliance We were in compliance with all of our debt covenants as of September 30, 2013

Debt And Equity Securities Available For Issuance 1,750,000,000

Long-term Debt, Fiscal Year Maturity [Abstract]

2014 0

2015 500,000,000

2016 0

2017 250,000,000

2018 0

Thereafter 1,710,000,000

Debt Instrument Carrying Amount $ 2,460,000,000 $ 1,960,131,000 $ 500,000,000 $ 500,000,000 $ 250,000,000 $ 250,000,000 $ 450,000,000 $ 450,000,000 $ 200,000,000 $ 200,000,000 $ 400,000,000 $ 400,000,000 $ 500,000,000 $ 500,000,000 $ 0 $ 10,000,000 $ 10,000,000 $ 150,000,000 $ 150,000,000 $ 0 $ 131,000

v2.4.0.8

Summary of Significant Accounting Policies (Policy)
12 Months Ended

Sep. 30, 2013

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, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, asset retirement obligations, 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 natural gas distribution and regulated transmission and storage 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.
Currently, authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years

Revenue recognition
Revenue recognition — Sales of natural gas to our natural gas 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 natural gas 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 natural gas 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 transmission and storage 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 and unrealized gains and losses arising from changes in the fair value of natural gas inventory designated as a hedged item in a fair value hedge and the associated financial instruments.

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 natural gas distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for all our regulated operations, except for certain jurisdictions in the Kentucky/Mid-States Division, where it is valued on the first-in first-out method basis, in accordance with regulatory requirements. 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 $1.9 million, $2.6 million and $1.7 million was capitalized in 2013, 2012 and 2011.
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, 3.6 percent and 3.6 percent for the fiscal years ended September 30, 2013, 2012 and 2011.
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 50 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, 2013 and 2012, we had asset retirement obligations of $6.8 million and $10.5 million. Additionally, we had $3.3 million and $5.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.

Impairment of long-lived assets
Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.

Goodwill and intangible assets
Goodwill and intangible assets — 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.
Intangible assets are amortized over their useful lives of 10 years. These assets are reviewed for impairment as impairment indicators arise. 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. No impairment has been recognized.

Marketable securities
Marketable securities — As of September 30, 2013 and 2012, 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 natural gas 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.
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 natural gas 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 natural gas 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 revenue 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 revenue 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.
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 revenue 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 revenue.
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, 2013 and 2012, the Company netted $24.8 million and $23.7 million of cash held in margin accounts into its current risk management assets and liabilities.
Financial Instruments Associated with Interest Rate Risk
We manage interest rate risk, typically when we plan to issue new long-term debt or to refinance existing long-term debt. Prior to fiscal 2012, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We designated these Treasury lock agreements as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income (loss). When the Treasury locks were settled, the realized gain or loss was recorded as a component of accumulated other comprehensive income (loss) and is being recognized as a component of interest expense over the life of the related financing arrangement.
During fiscal 2012, we began using interest rate swaps and forward starting interest rate swaps to mitigate interest rate risk. Unrealized gains and losses associated with the swaps are recorded as a component of accumulated other comprehensive income (loss). When the 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.

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 our 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.
As of September 30, 2013 our Master Trust owned one real estate investment with a value less than $0.2 million that qualifies as a Level 3 fair value measurement. The valuation technique used was a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land and building sales values per square foot. Currently, we have no other assets or liabilities recorded at fair value that would qualify for Level 3 reporting.

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 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 cost is 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 calculation 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 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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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.

v2.4.0.8

Accumulated Other Comprehensive Income
12 Months Ended

Sep. 30, 2013

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 table provides 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, 2012
$
5,661

$
(44,273
)

$
(8,995
)

$
(47,607
)
Other comprehensive income before reclassifications
1,162

79,963

(2,057
)

79,068

Amounts reclassified from accumulated other comprehensive income
(1,375
)

2,216

6,576

7,417

Net current-period other comprehensive income (loss)
(213
)

82,179

4,519

86,485

September 30, 2013
$
5,448

$
37,906

$
(4,476
)

$
38,878

The following table details reclassifications out of AOCI for the fiscal year ended September 30, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.

Fiscal Year Ended September 30, 2013
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
$
2,166

Operation and maintenance expense

2,166

Total before tax

(791
)

Tax expense

$
1,375

Net of tax
Cash flow hedges

Interest rate agreements
$
(3,489
)

Interest charges
Commodity contracts
(10,778
)

Purchased gas cost

(14,267
)

Total before tax

5,475

Tax benefit

$
(8,792
)

Net of tax
Total reclassifications
$
(7,417
)

Net of tax

v2.4.0.8

Discontinued Operations (Table)
12 Months Ended

Sep. 30, 2013

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, Missouri, Illinois and Iowa service areas.

Year Ended September 30

2013

2012

2011

(In thousands)
Operating revenues
$
37,962

$
114,703

$
141,227

Purchased gas cost
21,464

62,902

83,537

Gross profit
16,498

51,801

57,690

Operating expenses
5,858

24,174

27,362

Operating income
10,640

27,627

30,328

Other nonoperating income
548

611

57

Income from discontinued operations before income taxes
11,188

28,238

30,385

Income tax expense
3,986

10,066

12,372

Income from discontinued operations
7,202

18,172

18,013

Gain on sale of discontinued operations, net of tax
5,294

6,349

—

Net income from discontinued operations
$
12,496

$
24,521

$
18,013

Assets held for sale table
The following table presents balance sheet data related to assets held for sale. At September 30, 2013 we did not have any assets or liabilities held for sale. At September 30, 2012 assets held for sale include assets and liabilities associated with our Georgia operations.

September 30,
2012

(In thousands)
Net plant, property & equipment
$
142,865

Gas stored underground
4,688

Other current assets
6,931

Deferred charges and other assets
87

Assets held for sale
$
154,571

Accounts payable and accrued liabilities
$
2,114

Other current liabilities
3,776

Regulatory cost of removal
3,257

Deferred credits and other liabilities
2,426

Liabilities held for sale
$
11,573

v2.4.0.8

Retirement and Post-Retirement Employee Benefit Plans Fair Value of Plan Assets (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Fair value of plan assets at beginning of year $ 343,144 $ 280,204

Actual return on plan assets 52,496 48,656

Employer contributions 32,745 46,534

Benefits paid (25,073) (24,553)

Divestitures (6,425) (7,697)

Fair value of plan assets at end of year 396,887 343,144

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Fair value of plan assets at beginning of year 77,072 53,065

Actual return on plan assets 13,432 12,912

Employer contributions 26,552 22,139

Plan participants' contributions 3,815 3,649

Benefits paid (14,458) (13,197)

Divestitures 0 (1,496)

Fair value of plan assets at end of year 106,413 77,072

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Fair value of plan assets at beginning of year 0 0

Employer contributions 14,449 4,638

Benefits paid (4,375) (4,638)

Settlements (10,074) 0

Fair value of plan assets at end of year $ 0 $ 0

v2.4.0.8

Financial Instruments Commodity Contract Volumes (Details)

Sep. 30, 2013

MMcf

Natural Gas Distribution Segment [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume 29,185

Natural Gas Distribution Segment [Member] | Not Designated as Hedging Instrument [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume 29,185

Natural Gas Distribution Segment [Member] | Fair Value Hedging [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume 0

Natural Gas 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 93,845

Nonregulated Segment [Member] | Not Designated as Hedging Instrument [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume 75,683

Nonregulated Segment [Member] | Fair Value Hedging [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume (13,033)

Nonregulated Segment [Member] | Cash Flow Hedging [Member]

Commodity Contract Outstanding Volumes [Line Items]

Investment Contract Volume 31,195

v2.4.0.8

Commitments and Contingencies (Table)
12 Months Ended

Sep. 30, 2013

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, 2013 are as follows (in thousands):
2014
$
12,662

2015
5,113

2016
743

2017
170

2018
142

Thereafter
356

$
19,186

v2.4.0.8

Retirement and Post-Retirement Employee Benefit Plans (Table)
12 Months Ended

Sep. 30, 2013

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, 2013

Unrecognized transition obligation
$
—

$
—

$
628

$
628

Unrecognized prior service credit
(91
)

—

(5,961
)

(6,052
)
Unrecognized actuarial loss
108,621

31,466

35,961

176,048

$
108,530

$
31,466

$
30,628

$
170,624

September 30, 2012

Unrecognized transition obligation
$
—

$
—

$
1,709

$
1,709

Unrecognized prior service credit
(232
)

—

(7,411
)

(7,643
)
Unrecognized actuarial loss
187,050

43,995

63,402

294,447

$
186,818

$
43,995

$
57,700

$
288,513

Schedule of Allocation of Plan Assets
The following table presents asset allocation information for the Master Trust as of September 30, 2013 and 2012.

Targeted
Allocation Range

Actual
Allocation
September 30
Security Class
2013

2012
Domestic equities
35%-55%

46.5
%

42.6
%
International equities
10%-20%

16.1
%

13.9
%
Fixed income
10%-30%

14.9
%

18.6
%
Company stock
5%-15%

12.6
%

12.0
%
Other assets
5%-15%

9.9
%

12.9
%

Schedule of Assumptions Used for Employee Pension Plans
These assumptions are presented in the following table:

Pension
Liability

Pension Cost

2013

2012

2013

2012

2011

Discount rate
4.95
%

4.04
%

4.04
%

5.05
%

5.39
%
⁽¹⁾
Rate of compensation increase
3.50
%

3.50
%

3.50
%

3.50
%

4.00
%

Expected return on plan assets
7.25
%

7.75
%

7.75
%

7.75
%

8.25
%

⁽¹⁾
The discount rate for the Pension Account Plan increased from 5.39% to 5.68% effective January 1, 2011 due to a curtailment gain recorded in fiscal 2011.

Schedule of Accumulated and Projected Benefit Obligations and Funded Status for Employee Pension Plans
The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2013 and 2012:

2013

2012

(In thousands)
Accumulated benefit obligation
$
446,133

$
468,440

Change in projected benefit obligation:

Benefit obligation at beginning of year
$
480,031

$
429,432

Service cost
17,754

15,084

Interest cost
19,334

21,568

Actuarial (gain) loss
(29,822
)

46,197

Benefits paid
(25,073
)

(24,553
)
Divestitures
(6,425
)

(7,697
)
Benefit obligation at end of year
455,799

480,031

Change in plan assets:

Fair value of plan assets at beginning of year
343,144

280,204

Actual return on plan assets
52,496

48,656

Employer contributions
32,745

46,534

Benefits paid
(25,073
)

(24,553
)
Divestitures
(6,425
)

(7,697
)
Fair value of plan assets at end of year
396,887

343,144

Reconciliation:

Funded status
(58,912
)

(136,887
)
Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Net amount recognized
$
(58,912
)

$
(136,887
)

Components of Net Periodic Pension Cost Table for Employee Pension Plans
Net periodic pension cost for the Plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic pension cost:

Service cost
$
17,754

$
15,084

$
14,384

Interest cost
19,334

21,568

22,264

Expected return on assets
(22,955
)

(21,474
)

(24,817
)
Amortization of prior service credit
(141
)

(141
)

(429
)
Recognized actuarial loss
19,066

14,451

9,498

Curtailment gain
—

—

(40
)
Net periodic pension cost
$
33,058

$
29,488

$
20,860

Schedule of Employee Pension Plans Investments at Fair Value
In addition to the assets shown below, the Master Trust had net accounts receivable of $0.4 million and $0.5 million at September 30, 2013 and 2012 which materially approximates fair value due to the short-term nature of these assets.

Assets at Fair Value as of September 30, 2013

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Common stocks — domestic equities
$
143,543

$
—

$
—

$
143,543

Money market funds
—

12,266

—

12,266

Registered investment companies:

Domestic funds
30,200

—

—

30,200

International funds
47,036

—

—

47,036

Common/collective trusts — domestic funds
—

57,627

—

57,627

Government securities:

Mortgage-backed securities
—

18,446

—

18,446

U.S. treasuries
4,117

663

—

4,780

Corporate bonds
—

35,012

—

35,012

Limited partnerships
—

47,417

—

47,417

Real estate
—

—

155

155

Total investments at fair value
$
224,896

$
171,431

$
155

$
396,482

Assets at Fair Value as of September 30, 2012

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Common stocks — domestic equities
$
114,799

$
—

$
—

$
114,799

Money market funds
—

21,010

—

21,010

Registered investment companies:

Domestic funds
19,984

—

—

19,984

International funds
36,714

—

—

36,714

Common/collective trusts — domestic funds
—

52,155

—

52,155

Government securities

Mortgage-backed securities
—

19,509

—

19,509

U.S. treasuries
7,597

487

—

8,084

Corporate bonds
—

35,960

—

35,960

Limited partnerships
140

41,786

—

41,926

Real estate
—

—

155

155

Total investments at fair value
$
179,234

$
170,907

$
155

$
350,296

Schedule of Assumptions Used for Supplemental Plans
The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2012, 2011 and 2010. These assumptions are presented in the following table:

Pension
Liability

Pension Cost

2013

2012

2013

2012

2011
Discount rate
4.95
%

4.04
%

4.04
%
⁽¹⁾

5.05
%

5.39
%
Rate of compensation increase
3.50
%

3.50
%

3.50
%

3.50
%

4.00
%

⁽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.

Schedule of Accumulated and Projected Benefit Obligations and Funded Status for Supplemental Plans
The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2013 and 2012:

2013

2012

(In thousands)
Accumulated benefit obligation
$
109,817

$
121,815

Change in projected benefit obligation:

Benefit obligation at beginning of year
$
130,186

$
112,115

Service cost
3,039

2,108

Interest cost
4,755

5,142

Actuarial (gain) loss
(6,451
)

15,459

Benefits paid
(4,375
)

(4,638
)
Settlements
(10,074
)

—

Benefit obligation at end of year
117,080

130,186

Change in plan assets:

Fair value of plan assets at beginning of year
—

—

Employer contribution
14,449

4,638

Benefits paid
(4,375
)

(4,638
)
Settlements
(10,074
)

—

Fair value of plan assets at end of year
—

—

Reconciliation:

Funded status
(117,080
)

(130,186
)
Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Accrued pension cost
$
(117,080
)

$
(130,186
)

Components of Net Periodic Pension Cost Table for Supplemental Plans
Net periodic pension cost for the supplemental plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic pension cost:

Service cost
$
3,039

$
2,108

$
2,768

Interest cost
4,755

5,142

5,825

Amortization of transition asset
—

—

—

Amortization of prior service cost
—

—

—

Recognized actuarial loss
2,918

2,118

2,239

Settlements
3,160

—

—

Net periodic pension cost
$
13,872

$
9,368

$
10,832

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

Pension
Plans

Supplemental
Plans

(In thousands)
2014
$
40,640

$
22,940

2015
36,230

6,363

2016
34,752

6,226

2017
33,612

6,440

2018
33,273

6,913

2019-2023
156,367

34,260

Schedule of Allocation of Postretirement Benefit Plan Assets
The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2013 and 2012.

Actual
Allocation
September 30
Security Class
2013

2012
Diversified investment funds
96.8
%

97.0
%
Cash and cash equivalents
3.2
%

3.0
%

Schedule of Assumptions Used for Postretirement Benefit Plan
The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2012, 2011 and 2010. The assumptions are presented in the following table:

Postretirement
Liability

Postretirement Cost

2013

2012

2013

2012

2011
Discount rate
4.95
%

4.04
%

4.04
%

5.05
%

5.39
%
Expected return on plan assets
4.60
%

4.70
%

4.70
%

5.00
%

5.00
%
Initial trend rate
8.00
%

8.00
%

8.00
%

8.00
%

8.00
%
Ultimate trend rate
5.00
%

5.00
%

5.00
%

5.00
%

5.00
%
Ultimate trend reached in
2020

2019

2019

2018

2016

Schedule of Accumulated and Projected Benefit Obligations and Funded Status for Postretirement Benefit Plan
The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2013 and 2012:

2013

2012

(In thousands)
Change in benefit obligation:

Benefit obligation at beginning of year
$
308,315

$
263,694

Service cost
18,800

16,353

Interest cost
12,964

13,861

Plan participants’ contributions
3,815

3,649

Actuarial (gain) loss
(13,801
)

28,815

Benefits paid
(14,458
)

(13,197
)
Divestitures
(3,487
)

(4,860
)
Benefit obligation at end of year
312,148

308,315

Change in plan assets:

Fair value of plan assets at beginning of year
77,072

53,065

Actual return on plan assets
13,432

12,912

Employer contributions
26,552

22,139

Plan participants’ contributions
3,815

3,649

Benefits paid
(14,458
)

(13,197
)
Divestitures
—

(1,496
)
Fair value of plan assets at end of year
106,413

77,072

Reconciliation:

Funded status
(205,735
)

(231,243
)
Unrecognized transition obligation
—

—

Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Accrued postretirement cost
$
(205,735
)

$
(231,243
)

Components of Net Periodic Pension Cost Table for Postretirement Benefit Plan
Net periodic postretirement cost for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the components presented below.

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic postretirement cost:

Service cost
$
18,800

$
16,353

$
14,403

Interest cost
12,964

13,861

12,813

Expected return on assets
(3,988
)

(2,607
)

(2,727
)
Amortization of transition obligation
1,081

1,511

1,511

Amortization of prior service credit
(1,450
)

(1,450
)

(1,450
)
Recognized actuarial loss
4,196

2,648

347

Net periodic postretirement cost
$
31,603

$
30,316

$
24,897

Assumed Heath Care Cost Effect on Postretirement Benefit Plan Cost
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
$
4,399

$
(3,682
)
Effect on postretirement benefit obligation
$
36,680

$
(30,940
)

Schedule of Postretirement Benefit Plans Investments at Fair Value

Assets at Fair Value as of September 30, 2013

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Money market funds
$
—

$
3,356

$
—

$
3,356

Registered investment companies:

Domestic funds
9,614

—

—

9,614

International funds
93,443

—

—

93,443

Total investments at fair value
$
103,057

$
3,356

$
—

$
106,413

Assets at Fair Value as of September 30, 2012

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Money market funds
$
—

$
2,360

$
—

$
2,360

Registered investment companies:

Domestic funds
7,756

—

—

7,756

International funds
68,452

—

—

68,452

Total investments at fair value
$
76,208

$
2,360

$
—

$
78,568

Schedule of Expected Benefit Payments for Postretirement Benefit Plan
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

Retiree
Payments

Subsidy
Payments

Total
Postretirement
Benefits

(In thousands)
2014
$
25,547

$
3,899

$
—

$
29,446

2015
16,628

4,915

—

21,543

2016
19,260

6,049

—

25,309

2017
21,216

7,304

—

28,520

2018
22,550

8,677

—

31,227

2019-2023
116,617

58,595

—

175,212

v2.4.0.8

Stock and Other Compensation Plans (Table)
12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of restricted stock activity
The following summarizes information regarding the restricted stock issued under the plan during the fiscal years ended September 30, 2013, 2012 and 2011:

2013

2012

2011

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value

Number of
Restricted
Shares

Weighted
Average
Grant-Date
Fair
Value
Nonvested at beginning of year
1,262,582

$
32.46

1,264,142

$
29.56

1,293,960

$
27.28

Granted
473,775

40.48

532,711

33.44

491,345

33.10

Vested
(657,795
)

32.20

(494,308
)

26.32

(464,321
)

27.21

Forfeited
(25,718
)

33.42

(39,963
)

29.83

(56,842
)

27.56

Nonvested at end of year
1,052,844

$
36.20

1,262,582

$
32.46

1,264,142

$
29.56

v2.4.0.8

Segment Information
12 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information
Segment Information
Atmos Energy Corporation and its subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage 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 natural gas 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, natural gas distribution companies, including certain divisions of Atmos Energy and third parties.
We operate the Company through the following three segments:
•
The natural gas distribution segment, includes our regulated natural gas distribution and related sales operations.
•
The regulated transmission and storage 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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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, 2013

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,394,418

$
89,011

$
1,402,828

$
—

$
3,886,257

Intersegment revenues
5,075

179,889

195,883

(380,847
)

—

2,399,493

268,900

1,598,711

(380,847
)

3,886,257

Purchased gas cost
1,318,257

—

1,535,380

(379,430
)

2,474,207

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

Year Ended September 30, 2012

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,144,376

$
92,604

$
1,201,503

$
—

$
3,438,483

Intersegment revenues
954

154,747

149,800

(305,501
)

—

2,145,330

247,351

1,351,303

(305,501
)

3,438,483

Purchased gas cost
1,122,587

—

1,296,179

(304,022
)

2,114,744

Gross profit
1,022,743

247,351

55,124

(1,479
)

1,323,739

Operating expenses

Operation and maintenance
353,879

71,521

29,697

(1,484
)

453,613

Depreciation and amortization
202,026

31,438

4,061

—

237,525

Taxes, other than income
162,377

15,568

3,128

—

181,073

Asset impairments
—

—

5,288

—

5,288

Total operating expenses
718,282

118,527

42,174

(1,484
)

877,499

Operating income
304,461

128,824

12,950

5

446,240

Miscellaneous income (expense)
(12,657
)

(1,051
)

1,035

(1,971
)

(14,644
)
Interest charges
110,642

29,414

3,084

(1,966
)

141,174

Income from continuing operations before income taxes
181,162

98,359

10,901

—

290,422

Income tax expense
57,314

35,300

5,612

—

98,226

Income from continuing operations
123,848

63,059

5,289

—

192,196

Income from discontinued operations, net of tax
18,172

—

—

—

18,172

Gain on sale of discontinued operations, net of tax
6,349

—

—

—

6,349

Net income
$
148,369

$
63,059

$
5,289

$
—

$
216,717

Capital expenditures
$
546,818

$
175,768

$
10,272

$
—

$
732,858

Year Ended September 30, 2011

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
Operating revenues from external parties
$
2,469,781

$
87,141

$
1,729,513

$
—

$
4,286,435

Intersegment revenues
883

132,232

295,380

(428,495
)

—

2,470,664

219,373

2,024,893

(428,495
)

4,286,435

Purchased gas cost
1,452,721

—

1,959,893

(426,999
)

2,985,615

Gross profit
1,017,943

219,373

65,000

(1,496
)

1,300,820

Operating expenses

Operation and maintenance
341,758

70,401

32,308

(1,502
)

442,965

Depreciation and amortization
193,642

25,997

4,193

—

223,832

Taxes, other than income
160,455

14,700

2,612

—

177,767

Asset impairments
—

—

30,270

—

30,270

Total operating expenses
695,855

111,098

69,383

(1,502
)

874,834

Operating income (loss)
322,088

108,275

(4,383
)

6

425,986

Miscellaneous income
16,242

4,715

657

(430
)

21,184

Interest charges
115,740

31,432

4,015

(424
)

150,763

Income (loss) from continuing operations before income taxes
222,590

81,558

(7,741
)

—

296,407

Income tax expense (benefit)
77,885

29,143

(209
)

—

106,819

Income (loss) from continuing operations
144,705

52,415

(7,532
)

—

189,588

Income from discontinued operations, net of tax
18,013

—

—

—

18,013

Net income (loss)
$
162,718

$
52,415

$
(7,532
)

$
—

$
207,601

Capital expenditures
$
496,899

$
118,452

$
7,614

$
—

$
622,965

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

2013

2012

2011

(In thousands)
Natural gas distribution revenues:

Gas sales revenues:

Residential
$
1,512,495

$
1,351,479

$
1,535,887

Commercial
661,930

587,651

685,380

Industrial
81,155

71,960

96,636

Public authority and other
60,557

54,334

68,676

Total gas sales revenues
2,316,137

2,065,424

2,386,579

Transportation revenues
55,938

53,924

57,331

Other gas revenues
22,343

25,028

25,871

Total natural gas distribution revenues
2,394,418

2,144,376

2,469,781

Regulated transmission and storage revenues
89,011

92,604

87,141

Nonregulated revenues
1,402,828

1,201,503

1,729,513

Total operating revenues
$
3,886,257

$
3,438,483

$
4,286,435

Balance sheet information at September 30, 2013 and 2012 by segment is presented in the following tables.

September 30, 2013

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
ASSETS

Property, plant and equipment, net
$
4,719,873

$
1,249,767

$
61,015

$
—

$
6,030,655

Investment in subsidiaries
831,136

—

(2,096
)

(829,040
)

—

Current assets

Cash and cash equivalents
4,237

—

61,962

—

66,199

Assets from risk management activities
1,837

—

16,262

—

18,099

Other current assets
428,366

11,709

452,126

(293,233
)

598,968

Intercompany receivables
783,738

—

—

(783,738
)

—

Total current assets
1,218,178

11,709

530,350

(1,076,971
)

683,266

Intangible assets
—

—

121

—

121

Goodwill
574,190

132,462

34,711

—

741,363

Noncurrent assets from risk management activities
109,354

—

—

—

109,354

Deferred charges and other assets
347,687

19,227

8,728

—

375,642

$
7,800,418

$
1,413,165

$
632,829

$
(1,906,011
)

$
7,940,401

CAPITALIZATION AND LIABILITIES

Shareholders’ equity
$
2,580,409

$
396,421

$
434,715

$
(831,136
)

$
2,580,409

Long-term debt
2,455,671

—

—

—

2,455,671

Total capitalization
5,036,080

396,421

434,715

(831,136
)

5,036,080

Current liabilities

Current maturities of long-term debt
—

—

—

—

—

Short-term debt
645,984

—

—

(278,000
)

367,984

Liabilities from risk management activities
1,543

—

—

—

1,543

Other current liabilities
491,681

20,288

110,306

(13,316
)

608,959

Intercompany payables
—

712,768

70,970

(783,738
)

—

Total current liabilities
1,139,208

733,056

181,276

(1,075,054
)

978,486

Deferred income taxes
871,360

283,554

8,960

179

1,164,053

Noncurrent liabilities from risk management activities
—

—

6,133

—

6,133

Regulatory cost of removal obligation
359,299

—

—

—

359,299

Pension and postretirement liabilities
358,787

—

—

—

358,787

Deferred credits and other liabilities
35,684

134

1,745

—

37,563

$
7,800,418

$
1,413,165

$
632,829

$
(1,906,011
)

$
7,940,401

September 30, 2012

Natural Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Eliminations

Consolidated

(In thousands)
ASSETS

Property, plant and equipment, net
$
4,432,017

$
979,443

$
64,144

$
—

$
5,475,604

Investment in subsidiaries
747,496

—

(2,096
)

(745,400
)

—

Current assets

Cash and cash equivalents
12,787

—

51,452

—

64,239

Assets from risk management activities
6,934

—

17,773

—

24,707

Other current assets
546,187

11,788

404,097

(223,056
)

739,016

Intercompany receivables
636,557

—

—

(636,557
)

—

Total current assets
1,202,465

11,788

473,322

(859,613
)

827,962

Intangible assets
—

—

164

—

164

Goodwill
573,550

132,422

34,711

—

740,683

Noncurrent assets from risk management activities
2,283

—

—

—

2,283

Deferred charges and other assets
417,893

24,353

6,733

—

448,979

$
7,375,704

$
1,148,006

$
576,978

$
(1,605,013
)

$
7,495,675

CAPITALIZATION AND LIABILITIES

Shareholders’ equity
$
2,359,243

$
328,161

$
419,335

$
(747,496
)

$
2,359,243

Long-term debt
1,956,305

—

—

—

1,956,305

Total capitalization
4,315,548

328,161

419,335

(747,496
)

4,315,548

Current liabilities

Current maturities of long-term debt
—

—

131

—

131

Short-term debt
782,719

—

—

(211,790
)

570,929

Liabilities from risk management activities
85,366

—

15

—

85,381

Other current liabilities
526,089

12,478

90,116

(9,170
)

619,513

Intercompany payables
—

584,578

51,979

(636,557
)

—

Total current liabilities
1,394,174

597,056

142,241

(857,517
)

1,275,954

Deferred income taxes
789,288

220,647

5,148

—

1,015,083

Noncurrent liabilities from risk management activities
—

—

9,206

—

9,206

Regulatory cost of removal obligation
381,164

—

—

—

381,164

Pension and postretirement liabilities
457,196

—

—

—

457,196

Deferred credits and other liabilities
38,334

2,142

1,048

—

41,524

$
7,375,704

$
1,148,006

$
576,978

$
(1,605,013
)

$
7,495,675

v2.4.0.8

Income Taxes Rate Reconciliation (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Effective Income Tax Rate Reconciliation, Amount [Abstract]

Tax at statutory rate of 35% $ 130,655 $ 101,648 $ 103,743

Common stock dividends deductible for tax reporting (2,153) (2,096) (1,930)

Penalties 153 66 2,292

Recognition (settlement) of uncertain tax positions 1,341 1,831 (4,950)

State taxes (net of federal benefit) 10,687 (5,958) 8,109

Other, net 1,916 2,735 (445)

Income tax expense (benefit) $ 142,599 $ 98,226 $ 106,819

v2.4.0.8

Nature of Business (Table)
12 Months Ended

Sep. 30, 2013

Schedule of Divisions And Service Areas Table [Abstract]

Schedule of divisions and service areas
Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated natural gas distribution divisions 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.

v2.4.0.8

Accumulated Other Comprehensive Income (Table)
12 Months Ended

Sep. 30, 2013

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)
The following table provides 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, 2012
$
5,661

$
(44,273
)

$
(8,995
)

$
(47,607
)
Other comprehensive income before reclassifications
1,162

79,963

(2,057
)

79,068

Amounts reclassified from accumulated other comprehensive income
(1,375
)

2,216

6,576

7,417

Net current-period other comprehensive income (loss)
(213
)

82,179

4,519

86,485

September 30, 2013
$
5,448

$
37,906

$
(4,476
)

$
38,878

Reclassification out of Accumulated Other Comprehensive Income
The following table details reclassifications out of AOCI for the fiscal year ended September 30, 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.

Fiscal Year Ended September 30, 2013
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
$
2,166

Operation and maintenance expense

2,166

Total before tax

(791
)

Tax expense

$
1,375

Net of tax
Cash flow hedges

Interest rate agreements
$
(3,489
)

Interest charges
Commodity contracts
(10,778
)

Purchased gas cost

(14,267
)

Total before tax

5,475

Tax benefit

$
(8,792
)

Net of tax
Total reclassifications
$
(7,417
)

Net of tax

v2.4.0.8

Retirement and Post-retirement Employee Benefit Plans
12 Months Ended

Sep. 30, 2013

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, 2013

Unrecognized transition obligation
$
—

$
—

$
628

$
628

Unrecognized prior service credit
(91
)

—

(5,961
)

(6,052
)
Unrecognized actuarial loss
108,621

31,466

35,961

176,048

$
108,530

$
31,466

$
30,628

$
170,624

September 30, 2012

Unrecognized transition obligation
$
—

$
—

$
1,709

$
1,709

Unrecognized prior service credit
(232
)

—

(7,411
)

(7,643
)
Unrecognized actuarial loss
187,050

43,995

63,402

294,447

$
186,818

$
43,995

$
57,700

$
288,513

Defined Benefit Plans
Employee Pension Plans
As of September 30, 2013, 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 are held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust).
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 grandfather 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.
The Union Plan is a defined benefit plan that covers substantially all full-time union employees in our Mississippi Division. Under this plan, benefits are based upon years of benefit service and average final earnings. Participants vest in the plan after five years and will receive their benefit in an annuity.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension Protection Act of 2006 (PPA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.
During fiscal 2013 and 2012 we contributed $32.7 million and $46.5 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 subsequent to September 30, 2013, the current funded position of the Plans and the new funding requirements under the PPA, we anticipate contributing between $15 million and $25 million to the Plans in fiscal 2014. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds.
We manage the Master Trust’s assets with the objective of achieving a rate of return net of inflation of approximately four percent per year. We make investment decisions and evaluate performance 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, 2013 and 2012.

Targeted
Allocation Range

Actual
Allocation
September 30
Security Class
2013

2012
Domestic equities
35%-55%

46.5
%

42.6
%
International equities
10%-20%

16.1
%

13.9
%
Fixed income
10%-30%

14.9
%

18.6
%
Company stock
5%-15%

12.6
%

12.0
%
Other assets
5%-15%

9.9
%

12.9
%

At September 30, 2013 and 2012, the Plan held 1,169,700 shares of our common stock, which represented 12.6 percent and 12.0 percent of total Master Trust assets. These shares generated dividend income for the Plan of approximately $1.6 million and $1.6 million during fiscal 2013 and 2012.
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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the Plans were determined as of September 30, 2012, 2011 and 2010. These assumptions are presented in the following table:

Pension
Liability

Pension Cost

2013

2012

2013

2012

2011

Discount rate
4.95
%

4.04
%

4.04
%

5.05
%

5.39
%
⁽¹⁾
Rate of compensation increase
3.50
%

3.50
%

3.50
%

3.50
%

4.00
%

Expected return on plan assets
7.25
%

7.75
%

7.75
%

7.75
%

8.25
%

⁽¹⁾
The discount rate for the Pension Account Plan increased from 5.39% to 5.68% effective January 1, 2011 due to a curtailment gain recorded in fiscal 2011.
The following table presents the Plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2013 and 2012:

2013

2012

(In thousands)
Accumulated benefit obligation
$
446,133

$
468,440

Change in projected benefit obligation:

Benefit obligation at beginning of year
$
480,031

$
429,432

Service cost
17,754

15,084

Interest cost
19,334

21,568

Actuarial (gain) loss
(29,822
)

46,197

Benefits paid
(25,073
)

(24,553
)
Divestitures
(6,425
)

(7,697
)
Benefit obligation at end of year
455,799

480,031

Change in plan assets:

Fair value of plan assets at beginning of year
343,144

280,204

Actual return on plan assets
52,496

48,656

Employer contributions
32,745

46,534

Benefits paid
(25,073
)

(24,553
)
Divestitures
(6,425
)

(7,697
)
Fair value of plan assets at end of year
396,887

343,144

Reconciliation:

Funded status
(58,912
)

(136,887
)
Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Net amount recognized
$
(58,912
)

$
(136,887
)

Net periodic pension cost for the Plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic pension cost:

Service cost
$
17,754

$
15,084

$
14,384

Interest cost
19,334

21,568

22,264

Expected return on assets
(22,955
)

(21,474
)

(24,817
)
Amortization of prior service credit
(141
)

(141
)

(429
)
Recognized actuarial loss
19,066

14,451

9,498

Curtailment gain
—

—

(40
)
Net periodic pension cost
$
33,058

$
29,488

$
20,860

The following table sets forth by level, within the fair value hierarchy, the Master Trust’s assets at fair value as of September 30, 2013 and 2012. 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. Assets at September 30, 2012 include $7.7 million that were transferred to the purchaser of our Missouri, Illinois and Iowa operations during the first quarter of fiscal 2013. In addition to the assets shown below, the Master Trust had net accounts receivable of $0.4 million and $0.5 million at September 30, 2013 and 2012 which materially approximates fair value due to the short-term nature of these assets.

Assets at Fair Value as of September 30, 2013

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Common stocks — domestic equities
$
143,543

$
—

$
—

$
143,543

Money market funds
—

12,266

—

12,266

Registered investment companies:

Domestic funds
30,200

—

—

30,200

International funds
47,036

—

—

47,036

Common/collective trusts — domestic funds
—

57,627

—

57,627

Government securities:

Mortgage-backed securities
—

18,446

—

18,446

U.S. treasuries
4,117

663

—

4,780

Corporate bonds
—

35,012

—

35,012

Limited partnerships
—

47,417

—

47,417

Real estate
—

—

155

155

Total investments at fair value
$
224,896

$
171,431

$
155

$
396,482

Assets at Fair Value as of September 30, 2012

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Common stocks — domestic equities
$
114,799

$
—

$
—

$
114,799

Money market funds
—

21,010

—

21,010

Registered investment companies:

Domestic funds
19,984

—

—

19,984

International funds
36,714

—

—

36,714

Common/collective trusts — domestic funds
—

52,155

—

52,155

Government securities

Mortgage-backed securities
—

19,509

—

19,509

U.S. treasuries
7,597

487

—

8,084

Corporate bonds
—

35,960

—

35,960

Limited partnerships
140

41,786

—

41,926

Real estate
—

—

155

155

Total investments at fair value
$
179,234

$
170,907

$
155

$
350,296

The fair value of our Level 3 real estate assets was determined using a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land sales values per square foot in the range of $0.94 to $2.98 and comparable building sales values per square foot in the range of $23.13 to $30.42.
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 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.

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 Supplemental Executive Benefits Plan. In association with the retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.
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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2012, 2011 and 2010. These assumptions are presented in the following table:

Pension
Liability

Pension Cost

2013

2012

2013

2012

2011
Discount rate
4.95
%

4.04
%

4.04
%
⁽¹⁾

5.05
%

5.39
%
Rate of compensation increase
3.50
%

3.50
%

3.50
%

3.50
%

4.00
%

⁽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, 2013 and 2012:

2013

2012

(In thousands)
Accumulated benefit obligation
$
109,817

$
121,815

Change in projected benefit obligation:

Benefit obligation at beginning of year
$
130,186

$
112,115

Service cost
3,039

2,108

Interest cost
4,755

5,142

Actuarial (gain) loss
(6,451
)

15,459

Benefits paid
(4,375
)

(4,638
)
Settlements
(10,074
)

—

Benefit obligation at end of year
117,080

130,186

Change in plan assets:

Fair value of plan assets at beginning of year
—

—

Employer contribution
14,449

4,638

Benefits paid
(4,375
)

(4,638
)
Settlements
(10,074
)

—

Fair value of plan assets at end of year
—

—

Reconciliation:

Funded status
(117,080
)

(130,186
)
Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Accrued pension cost
$
(117,080
)

$
(130,186
)

Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2013 and 2012, assets held in the rabbi trusts consisted of available-for-sale securities of $44.5 million and $41.8 million, which are included in our fair value disclosures in Note 14.
Net periodic pension cost for the supplemental plans for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the following components:

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic pension cost:

Service cost
$
3,039

$
2,108

$
2,768

Interest cost
4,755

5,142

5,825

Amortization of transition asset
—

—

—

Amortization of prior service cost
—

—

—

Recognized actuarial loss
2,918

2,118

2,239

Settlements
3,160

—

—

Net periodic pension cost
$
13,872

$
9,368

$
10,832

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)
2014
$
40,640

$
22,940

2015
36,230

6,363

2016
34,752

6,226

2017
33,612

6,440

2018
33,273

6,913

2019-2023
156,367

34,260

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 will apply to all non-grandfathered participants will be determined using a new 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 $25 million and $30 million to our postretirement benefits plan during fiscal 2014.
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, 2013 and 2012.

Actual
Allocation
September 30
Security Class
2013

2012
Diversified investment funds
96.8
%

97.0
%
Cash and cash equivalents
3.2
%

3.0
%

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, 2013 and 2012 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2012, 2011 and 2010. The assumptions are presented in the following table:

Postretirement
Liability

Postretirement Cost

2013

2012

2013

2012

2011
Discount rate
4.95
%

4.04
%

4.04
%

5.05
%

5.39
%
Expected return on plan assets
4.60
%

4.70
%

4.70
%

5.00
%

5.00
%
Initial trend rate
8.00
%

8.00
%

8.00
%

8.00
%

8.00
%
Ultimate trend rate
5.00
%

5.00
%

5.00
%

5.00
%

5.00
%
Ultimate trend reached in
2020

2019

2019

2018

2016

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2013 and 2012:

2013

2012

(In thousands)
Change in benefit obligation:

Benefit obligation at beginning of year
$
308,315

$
263,694

Service cost
18,800

16,353

Interest cost
12,964

13,861

Plan participants’ contributions
3,815

3,649

Actuarial (gain) loss
(13,801
)

28,815

Benefits paid
(14,458
)

(13,197
)
Divestitures
(3,487
)

(4,860
)
Benefit obligation at end of year
312,148

308,315

Change in plan assets:

Fair value of plan assets at beginning of year
77,072

53,065

Actual return on plan assets
13,432

12,912

Employer contributions
26,552

22,139

Plan participants’ contributions
3,815

3,649

Benefits paid
(14,458
)

(13,197
)
Divestitures
—

(1,496
)
Fair value of plan assets at end of year
106,413

77,072

Reconciliation:

Funded status
(205,735
)

(231,243
)
Unrecognized transition obligation
—

—

Unrecognized prior service cost
—

—

Unrecognized net loss
—

—

Accrued postretirement cost
$
(205,735
)

$
(231,243
)

Net periodic postretirement cost for fiscal 2013, 2012 and 2011 is recorded as operating expense and included the components presented below.

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Components of net periodic postretirement cost:

Service cost
$
18,800

$
16,353

$
14,403

Interest cost
12,964

13,861

12,813

Expected return on assets
(3,988
)

(2,607
)

(2,727
)
Amortization of transition obligation
1,081

1,511

1,511

Amortization of prior service credit
(1,450
)

(1,450
)

(1,450
)
Recognized actuarial loss
4,196

2,648

347

Net periodic postretirement cost
$
31,603

$
30,316

$
24,897

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
$
4,399

$
(3,682
)
Effect on postretirement benefit obligation
$
36,680

$
(30,940
)

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, 2013 and 2012. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2. Assets at September 30, 2012 include $1.5 million that were transferred to the purchaser of our Missouri, Illinois and Iowa operations during the first quarter of fiscal 2013.

Assets at Fair Value as of September 30, 2013

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Money market funds
$
—

$
3,356

$
—

$
3,356

Registered investment companies:

Domestic funds
9,614

—

—

9,614

International funds
93,443

—

—

93,443

Total investments at fair value
$
103,057

$
3,356

$
—

$
106,413

Assets at Fair Value as of September 30, 2012

Level 1

Level 2

Level 3

Total

(In thousands)
Investments:

Money market funds
$
—

$
2,360

$
—

$
2,360

Registered investment companies:

Domestic funds
7,756

—

—

7,756

International funds
68,452

—

—

68,452

Total investments at fair value
$
76,208

$
2,360

$
—

$
78,568

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

Retiree
Payments

Subsidy
Payments

Total
Postretirement
Benefits

(In thousands)
2014
$
25,547

$
3,899

$
—

$
29,446

2015
16,628

4,915

—

21,543

2016
19,260

6,049

—

25,309

2017
21,216

7,304

—

28,520

2018
22,550

8,677

—

31,227

2019-2023
116,617

58,595

—

175,212

Defined Contribution Plans
As of September 30, 2013, we maintained three defined contribution benefit plans: the Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan), the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401K 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. In August 2010, the Board of Directors of Atmos Energy approved a proposal to close the Pension Account Plan to new participants effective October 1, 2010. New employees participate in our defined contribution plan, which was enhanced, effective January 1, 2011. Employees participating in the Pension Account Plan as of October 1, 2010 were allowed to make a one-time election to migrate from the Plan into the Retirement Savings Plan, effective January 1, 2011. Under the enhanced plan, 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.
The Union 401K Plan covers substantially all Mississippi Division employees who are members of the International Chemical Workers Union Council, United Food and Commercial Workers Union International (the Union) and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Employees of the Union automatically become participants of the Union 401K plan on the date of union membership. We match 50 percent of a participant’s contribution in cash, limited to six percent of the participant’s eligible contribution. Participants are also permitted to take out loans against their accounts subject to certain restrictions.
Matching contributions to the Retirement Savings Plan and the Union 401K Plan are expensed as incurred and amounted to $10.4 million, $10.5 million, and $10.2 million for fiscal years 2013, 2012 and 2011. 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 2013, 2012 or 2011. At September 30, 2013 and 2012, the Retirement Savings Plan held 4.9 percent and 4.9 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, $1.2 million and $1.3 million for fiscal years 2013, 2012 and 2011.

v2.4.0.8

Valuation and Qualifying Accounts (Details) (Allowance For Doubtful Accounts Member, USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Allowance For Doubtful Accounts Member

Valuation And Qualifying Accounts Disclosure [Line Items]

Balance at beginning of period $ 9,425 $ 7,440 $ 12,701

Charged to costs & expenses 14,484 8,901 2,201

Charged to other accounts 0 0 0

Valuation Allowances And Reserves Deductions 3,285 ^[1] 6,916 ^[1] 7,462 ^[1]

Balance at end of period $ 20,624 $ 9,425 $ 7,440

[1] Uncollectible accounts written off.

v2.4.0.8

Significant Accounting Policies
12 Months Ended

Sep. 30, 2013

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, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, asset retirement obligations, 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 natural gas distribution and regulated transmission and storage 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, 2013 and 2012 included the following:

September 30

2013

2012

(In thousands)
Regulatory assets:

Pension and postretirement benefit costs⁽¹⁾
$
187,977

$
296,160

Merger and integration costs, net
5,250

5,754

Deferred gas costs
15,152

31,359

Regulatory cost of removal asset
10,008

10,500

Rate case costs
6,329

4,661

Deferred franchise fees
—

2,714

Texas Rule 8.209⁽²⁾
30,364

5,370

APT annual adjustment mechanism
5,853

4,539

Recoverable loss on reacquired debt
21,435

23,944

Other
4,380

7,262

$
286,748

$
392,263

Regulatory liabilities:

Deferred gas costs
$
16,481

$
23,072

Deferred franchise fees
1,689

—

Regulatory cost of removal obligation
427,524

459,688

Other
7,887

5,637

$
453,581

$
488,397

⁽¹⁾
Includes $17.4 million and $7.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.
⁽²⁾
Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.
The amounts above do not include regulatory assets and liabilities related to our Georgia operations, which were classified as assets held for sale at September 30, 2012 as discussed in Note 16. As of September 30, 2013, we did not have any assets or liabilities classified as held for sale due to the sale of substantially all of our Georgia assets on April 1, 2013.
Currently, authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. During the fiscal years ended September 30, 2013, 2012 and 2011, we recognized $0.5 million, $0.5 million and $0.5 million in amortization expense related to these costs.
Revenue recognition — Sales of natural gas to our natural gas 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 natural gas 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 natural gas 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 transmission and storage 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 and unrealized gains and losses arising from changes in the fair value of natural gas inventory designated as a hedged item in a fair value hedge and the associated financial instruments. For the fiscal years ended September 30, 2013, 2012 and 2011, we included unrealized gains (losses) on open contracts of $9.0 million, $(8.0) million and $(10.4) million as a component of nonregulated revenues.
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 natural gas distribution operations and natural gas held by our nonregulated segment to conduct their operations. The average cost method is used for all our regulated operations, except for certain jurisdictions in the Kentucky/Mid-States Division, where it is valued on the first-in first-out method basis, in accordance with regulatory requirements. 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 $1.9 million, $2.6 million and $1.7 million was capitalized in 2013, 2012 and 2011.
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, 3.6 percent and 3.6 percent for the fiscal years ended September 30, 2013, 2012 and 2011.
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 50 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, 2013 and 2012, we had asset retirement obligations of $6.8 million and $10.5 million. Additionally, we had $3.3 million and $5.8 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.
Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.
During fiscal 2012, we recorded a pre-tax noncash impairment loss of $5.3 million related to our gathering systems in Kentucky. In fiscal 2011, we recorded pre-tax noncash impairment losses of $19.3 million related to our Fort Necessity storage project and $11.0 million related to our gathering systems in Kentucky. See Note 14 for further details.
Goodwill and intangible assets — 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.
Intangible assets are amortized over their useful lives of 10 years. These assets are reviewed for impairment as impairment indicators arise. 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. No impairment has been recognized.
Marketable securities — As of September 30, 2013 and 2012, 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 natural gas 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.
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 natural gas 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 natural gas 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 revenue 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 revenue 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.
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 revenue 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 revenue.
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, 2013 and 2012, the Company netted $24.8 million and $23.7 million of cash held in margin accounts into its current risk management assets and liabilities.
Financial Instruments Associated with Interest Rate Risk
We manage interest rate risk, typically when we plan to issue new long-term debt or to refinance existing long-term debt. Prior to fiscal 2012, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We designated these Treasury lock agreements as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income (loss). When the Treasury locks were settled, the realized gain or loss was recorded as a component of accumulated other comprehensive income (loss) and is being recognized as a component of interest expense over the life of the related financing arrangement.
During fiscal 2012, we began using interest rate swaps and forward starting interest rate swaps to mitigate interest rate risk. Unrealized gains and losses associated with the swaps are recorded as a component of accumulated other comprehensive income (loss). When the 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.
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 our 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.
As of September 30, 2013 our Master Trust owned one real estate investment with a value less than $0.2 million that qualifies as a Level 3 fair value measurement. The valuation technique used was a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land and building sales values per square foot. Currently, we have no other assets or liabilities recorded at fair value that would qualify for Level 3 reporting.
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 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 cost is 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 calculation 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 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.
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 concerning the October 2, 2013 payment from our Supplemental Executive Benefits Plan related to the retirement of one of our executives, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.
Recent accounting pronouncements — During the year ended September 30, 2013, two new accounting standards were announced that will become applicable to the Company in future periods. The first standard clarifies the enhanced disclosure of offsetting arrangements for financial instruments that will become effective for us for annual and interim periods beginning on October 1, 2013. The adoption of this standard should not have an impact on our financial position, results of operations or cash flows. The second standard changes the presentation requirements for an unrecognized tax benefit if a net operating loss carryforward or tax credit carryforward exists, which will become effective for us for annual and interim periods beginning on October 1, 2014. The adoption of this standard should not have a material impact on our financial position, results of operations or cash flows.
Beginning in our first fiscal quarter, we have presented a single statement of other comprehensive income, due to an accounting pronouncement that became effective for us on October 1, 2012. Additionally, a standard that became effective during our second fiscal quarter requires the presentation of amounts reclassified out of accumulated other comprehensive income by component as well as significant amounts reclassified out of accumulated other comprehensive income by the respective line item in the statement of net income. We have presented the disclosures relating to reclassifications out of accumulated other comprehensive income in Note 13. The adoption of these standards did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the year ended September 30, 2013.

v2.4.0.8

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (PARENTHETICAL) (USD $)
In Thousands, unless otherwise specified
12 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent, Parenthetical Disclosures [Abstract]

Unrealized holding gains (losses) on available-for-sale securities, tax $ (186) $ 1,881 $ (953)

Amortization and unrealized gain (loss) on interest rate agreements, tax 47,236 (5,388) (16,850)

Unrealized gains (losses) on commodity cash flow hedges, tax $ 2,889 $ 5,029 $ 3,355

v2.4.0.8

Retirement and Post-Retirement Employee Benefit Plans Defined Benefit Plans Disclosure (Details) (USD $)
12 Months Ended 3 Months Ended 9 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 6 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2010

Pension Plans, Defined Benefit [Member]

Sep. 30, 2011

Pension Plans, Defined Benefit [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Sep. 30, 2011

Pension Plans, Defined Benefit [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

Domestic Equity Securities [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Domestic Equity Securities [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

International Equity Securities [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

International Equity Securities [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

Fixed Income Securities [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Fixed Income Securities [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

Company Stock [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Company Stock [Member]

Sep. 30, 2013

Pension Plans, Defined Benefit [Member]

Other Investment Assets [Member]

Sep. 30, 2012

Pension Plans, Defined Benefit [Member]

Other Investment Assets [Member]

Sep. 30, 2013

Pension Account Plan, Defined Benefit [Member]

Sep. 30, 2013

Mississippi Valley Gas Union Retirement Plan, Defined Benefit [Member]

Apr. 02, 2013

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Sep. 30, 2013

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Mar. 31, 2013

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Sep. 30, 2013

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Sep. 30, 2012

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Sep. 30, 2011

Supplemental Executive Retirement Plans, Defined Benefit [Member]

Sep. 30, 2013

Supplemental Executive Benefit Plan, Defined Benefit [Member]

Sep. 30, 2013

1998 Supplemental Executive Retirement Plan, Defined Benefit [Member]

Sep. 30, 2013

2009 Supplemental Executive Retirement Plan, Defined Benefit [Member]

Sep. 30, 2013

Other Postretirement Benefit Plans, Defined Benefit [Member]

Sep. 30, 2012

Other Postretirement Benefit Plans, Defined Benefit [Member]

Sep. 30, 2011

Other Postretirement Benefit Plans, Defined Benefit [Member]

Sep. 30, 2013

Other Postretirement Benefit Plans, Defined Benefit [Member]

Diversified Investment Funds [Member]

Sep. 30, 2012

Other Postretirement Benefit Plans, Defined Benefit [Member]

Diversified Investment Funds [Member]

Sep. 30, 2013

Other Postretirement Benefit Plans, Defined Benefit [Member]

Cash and Cash Equivalents [Member]

Sep. 30, 2012

Other Postretirement Benefit Plans, Defined Benefit [Member]

Cash and Cash Equivalents [Member]

Sep. 30, 2013

Minimum [Member]

Pension Plans, Defined Benefit [Member]

Sep. 30, 2013

Maximum [Member]

Pension Plans, Defined Benefit [Member]

Sep. 30, 2013

Retirement Savings Plan [Member]

Oct. 02, 2013

Subsequent Event [Member]

Oct. 02, 2013

Subsequent Event [Member]

Supplemental Executive Benefit Plan, Defined Benefit [Member]

Net Periodic Benefit Cost Not Yet Recognized, Recorded as Regulatory Assets [Abstract]

Unrecognized transition obligation $ 628,000 $ 1,709,000 $ 0 $ 0 $ 0 $ 0 $ 628,000 $ 1,709,000

Unrecognized prior service cost (6,052,000) (7,643,000) (91,000) (232,000) 0 0 (5,961,000) (7,411,000)

Unrecognized actuarial loss 176,048,000 294,447,000 108,621,000 187,050,000 31,466,000 43,995,000 35,961,000 63,402,000

Total unrecognized in net periodic cost 170,624,000 288,513,000 108,530,000 186,818,000 31,466,000 43,995,000 30,628,000 57,700,000

Current Year Benefit Plan Contributions [Abstract]

Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year Minimum 15,000,000 25,000,000

Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year Maximum 25,000,000 30,000,000

Defined Benefit Plan, Assets, Target Allocations [Abstract]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum 35.00% 10.00% 10.00% 5.00% 5.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum 55.00% 20.00% 30.00% 15.00% 15.00%

Defined Benefit Plan, Information about Plan Assets [Abstract]

Defined Benefit Plan, Actual Plan Asset Allocations 46.50% 42.60% 16.10% 13.90% 14.90% 18.60% 12.60% 12.00% 9.90% 12.90% 96.80% 97.00% 3.20% 3.00%

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 1,600,000 1,600,000

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost Abstract

Discount rate 5.39% ^[1] 5.68% ^[1] 4.04% 5.05% 4.21% 4.21% 4.04% ^[2] 5.05% 5.39% 4.04% 5.05% 5.39%

Rate of compensation increase 3.50% 3.50% 4.00% 3.50% 3.50% 4.00%

Expected return on plan assets 7.75% 7.75% 8.25% 4.70% 5.00% 5.00%

Initial Trend 8.00% 8.00% 8.00%

Ultimate trend rate 5.00% 5.00% 5.00%

Ultimate trend rate reached in 2019 2018 2016

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation Abstract

Discount rate 4.95% 4.04% 4.95% 4.95% 4.04% 4.95% 4.04%

Rate of compensation increase 3.50% 3.50% 3.50% 3.50% 3.50%

Expected return on plan assets 7.25% 7.75% 4.60% 4.70%

Initial trend rate 8.00% 8.00%

Ultimate trend rate 5.00% 5.00%

Ultimate trend reached in 2020 2019

Interest crediting rate 4.69%

Accumulated benefit obligation 446,133,000 468,440,000 109,817,000 109,817,000 121,815,000

Defined Benefit Plan Change In Benefit Obligation Roll Forward

Benefit obligation at beginning of year 480,031,000 429,432,000 130,186,000 130,186,000 112,115,000 308,315,000 263,694,000

Service cost 17,754,000 15,084,000 14,384,000 3,039,000 2,108,000 2,768,000 18,800,000 16,353,000 14,403,000

Interest cost 19,334,000 21,568,000 22,264,000 4,755,000 5,142,000 5,825,000 12,964,000 13,861,000 12,813,000

Plan participants' contributions 3,815,000 3,649,000

Actuarial (gain) loss (29,822,000) 46,197,000 (6,451,000) 15,459,000 (13,801,000) 28,815,000

Benefits paid (25,073,000) (24,553,000) (4,375,000) (4,638,000) (14,458,000) (13,197,000) (16,800,000)

Divestitures (6,425,000) (7,697,000) (3,487,000) (4,860,000)

Settlements (10,074,000) 0

Benefit obligation at end of year 429,432,000 455,799,000 480,031,000 429,432,000 117,080,000 117,080,000 130,186,000 112,115,000 312,148,000 308,315,000 263,694,000

Funded Status Reconciliation [Abstract]

Funded status (58,912,000) (136,887,000) (117,080,000) (117,080,000) (130,186,000) (205,735,000) (231,243,000)

Unrecognized prior service cost 0 0 0 0 0 0 0

Unrecognized transition obligation 0 0

Unrecognized net loss 0 0 0 0 0 0 0

Net amount recognized (58,912,000) (136,887,000) (117,080,000) (117,080,000) (130,186,000) (205,735,000) (231,243,000)

Estimated company benefit payments

Estimated company benefit payments in year one 25,547,000

Estimated company benefit payments in year two 16,628,000

Estimated company benefit payments in year three 19,260,000

Estimated company benefit payments in year four 21,216,000

Estimated company benefit payments in year five 22,550,000

Estimated company benefit payments in five fiscal years thereafter 116,617,000

Estimated retiree benefit payments

Estimated retiree benefit payments in year one 3,899,000

Estimated retiree benefit payments in year two 4,915,000

Estimated retiree benefit payments in year three 6,049,000

Estimated retiree benefit payments in year four 7,304,000

Estimated retiree benefit payments in year five 8,677,000

Estimated retiree benefit payments in five fiscal years thereafter 58,595,000

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 40,640,000 22,940,000 22,940,000 29,446,000

Expected future benefit payments in year two, total 36,230,000 6,363,000 6,363,000 21,543,000

Expected future benefit payments in year three, total 34,752,000 6,226,000 6,226,000 25,309,000

Expected future benefit payments in year four, total 33,612,000 6,440,000 6,440,000 28,520,000

Expected future benefit payments in year five, total 33,273,000 6,913,000 6,913,000 31,227,000

Expected future benefit payments in five fiscal years thereafter, total 156,367,000 34,260,000 34,260,000 175,212,000

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 4,399,000

Effect of One Percentage Point Decrease on Service and Interest Cost Components (3,682,000)

Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation 36,680,000

Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation (30,940,000)

Subsequent Events [Abstract]

Subsequent Event, Date Oct. 02, 2013

Subsequent Event, Description due to the retirement of one of our executives, we recognized a settlement loss of $4.5 million associated with our Supplemental Executive Benefits Plan. In association with the retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.

Defined Benefit Plan, Employer Claims Paid 80.00%

Defined Benefit Plan, Employee Paid Claims 20.00%

Defined Benefit Plan, Percent of Covered Compensation 75.00% 60.00%

Defined Benefit Plan, Vesting Period 3 years 5 years 3 years 3 years

Defined Benefit Plan, Age Attained 55 years

Defined Benefit Plan, Investment Performance Review Period 3 years 5 years

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.

Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments 0 0 40,000

Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements $ 3,200,000 $ (3,160,000) $ 0 $ 0 $ 4,500,000

Defined Benefit Plan, Net Rate of Return Goal 4.00%

Defined Benefit Plan, Funds Available for Investment in Common Stock and Convertible Securities 75.00%

Defined Benefit Plan, Percent of Contributed Compensation 10.00%

Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided 15 years

Defined Benefit Plan, Percent Limit on Future Contributions 3.00%

[1] (1) The discount rate for the Pension Account Plan increased from 5.39% to 5.68% effective January 1, 2011 due to a curtailment gain recorded in fiscal 2011.

[2] (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.

v2.4.0.8

Nature of Business (Details)

Sep. 30, 2013

regulated_gas_distributions_divisions

customers

Schedule of Number of Customers, Discontinued Operations [Line Items]

Number Of Customers, Natural Gas Distribution 3,000,000

Number Of Divisions, Natural Gas Distribution 6

Georgia [Member]

Schedule of Number of Customers, Discontinued Operations [Line Items]

Number Of Customers, Natural Gas Distribution 64,000

Missouri, Illinois and Iowa [Member]

Schedule of Number of Customers, Discontinued Operations [Line Items]

Number Of Customers, Natural Gas Distribution 84,000

v2.4.0.8

Earnings Per Share (Table)
12 Months Ended

Sep. 30, 2013

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:

2013

2012

2011

(In thousands, except per share data)
Basic Earnings Per Share from continuing operations

Income from continuing operations
$
230,698

$
192,196

$
189,588

Less: Income from continuing operations allocated to participating securities
775

793

1,980

Income from continuing operations available to common shareholders
$
229,923

$
191,403

$
187,608

Basic weighted average shares outstanding
90,533

90,150

90,201

Income from continuing operations per share — Basic
$
2.54

$
2.12

$
2.08

Basic Earnings Per Share from discontinued operations

Income from discontinued operations
$
12,496

$
24,521

$
18,013

Less: Income from discontinued operations allocated to participating securities
42

101

188

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Basic weighted average shares outstanding
90,533

90,150

90,201

Income from discontinued operations per share — Basic
$
0.14

$
0.27

$
0.20

Net income per share — Basic
$
2.68

$
2.39

$
2.28

Diluted Earnings Per Share from continuing operations

Income from continuing operations available to common shareholders
$
229,923

$
191,403

$
187,608

Effect of dilutive stock options and other shares
5

4

4

Income from continuing operations available to common shareholders
$
229,928

$
191,407

$
187,612

Basic weighted average shares outstanding
90,533

90,150

90,201

Additional dilutive stock options and other shares
1,178

1,022

451

Diluted weighted average shares outstanding
91,711

91,172

90,652

Income from continuing operations per share — Diluted
$
2.50

$
2.10

$
2.07

Diluted Earnings Per Share from discontinued operations

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Effect of dilutive stock options and other shares
—

—

—

Income from discontinued operations available to common shareholders
$
12,454

$
24,420

$
17,825

Basic weighted average shares outstanding
90,533

90,150

90,201

Additional dilutive stock options and other shares
1,178

1,022

451

Diluted weighted average shares outstanding
91,711

91,172

90,652

Income from discontinued operations per share — Diluted
$
0.14

$
0.27

$
0.20

Net income per share — Diluted
$
2.64

$
2.37

$
2.27

v2.4.0.8

Leases
12 Months Ended

Sep. 30, 2013

Leases [Abstract]

Leases
Leases
Capital and Operating 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 21 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. We have also entered into capital leases for division offices and operating facilities. Property, plant and equipment included amounts for capital leases of $1.3 million at September 30, 2013 and 2012. Accumulated depreciation for these capital leases totaled $1.0 million and $0.9 million at September 30, 2013 and 2012. Depreciation expense for these assets is included in consolidated depreciation expense on the consolidated statement of income.
The related future minimum lease payments at September 30, 2013 were as follows:

Capital
Leases

Operating
Leases

(In thousands)
2014
$
186

$
16,722

2015
186

15,584

2016
186

14,692

2017
186

15,074

2018
78

15,057

Thereafter
—

89,673

Total minimum lease payments
822

$
166,802

Less amount representing interest
198

Present value of net minimum lease payments
$
624

Consolidated lease and rental expense amounted to $32.4 million, $33.6 million and $35.5 million for fiscal 2013, 2012 and 2011.

v2.4.0.8

Debt
12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Debt
Debt
Long-term debt
Long-term debt at September 30, 2013 and 2012 consisted of the following:

2013

2012

(In thousands)
Unsecured 4.95% Senior Notes, due October 2014
$
500,000

$
500,000

Unsecured 6.35% Senior Notes, due 2017
250,000

250,000

Unsecured 8.50% Senior Notes, due 2019
450,000

450,000

Unsecured 5.95% Senior Notes, due 2034
200,000

200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

400,000

Unsecured 4.15% Senior Notes, due 2043
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

Rental property term notes due in installments through 2013
—

131

Total long-term debt
2,460,000

1,960,131

Less:

Original issue discount on unsecured senior notes and debentures
4,329

3,695

Current maturities
—

131

$
2,455,671

$
1,956,305

We issued $500 million Unsecured 4.15% Senior Notes on January 11, 2013. The effective rate of these notes is 4.67%, after giving effect to offering costs and the settlement of the associated Treasury lock agreements discussed in Note 12. Of the net proceeds of approximately $494 million, $234 million was used to partially repay our commercial paper borrowings and for general corporate purposes. The remaining $260 million was used to repay a short-term financing facility that was scheduled to mature on February 1, 2013. This facility was executed on September 27, 2012, with interest rates at a LIBOR based rate plus a company specific spread, to repay commercial paper borrowings that were used to redeem our $250 million Unsecured 5.125% Senior Notes were scheduled to mature in January 2013.
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 $950 million 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 billion of working capital funding. At September 30, 2013 and 2012, there was $368.0 million and $310.9 million outstanding under our commercial paper program with weighted average interest rates of 0.25% and 0.48%, 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 $985 million of working capital funding. The first facility is a five-year unsecured facility that was amended on December 7, 2012 to increase the borrowing capacity from $750 million to $950 million with an accordion feature, which, if utilized would increase the borrowing capacity to $1.2 billion. On August 22, 2013 the terms of the facility were amended to extend the expiration date from May 2016 to August 2018. 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 two percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At September 30, 2013, there were no borrowings under this facility, but we had $368.0 million of commercial paper outstanding leaving $582.0 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, 2013. At September 30, 2013, there were no borrowings outstanding under this facility.
The third facility which was renewed on September 30, 2013 for $10 million is a committed revolving credit facility used primarily to issue letters of credit that bears interest at a LIBOR-based rate plus 1.5 percent. At September 30, 2013, 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, 2013, 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 each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2013, our total-debt-to-total-capitalization ratio, as defined, was 54 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, 2013. There was $278.0 million outstanding under this facility at September 30, 2013.
Nonregulated Operations
Prior to December 5, 2012, Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, had a three-year $200 million committed revolving credit facility, expiring in December 2014, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility was primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. This facility
was collateralized by substantially all of the assets of AEM and was guaranteed by AEH. AEM terminated the committed
revolving credit facility on December 5, 2012, to reduce external credit expense. AEM incurred no penalties in connection with
the termination. This facility was replaced with two $25 million, 364-day bilateral credit facilities, one of which is a committed
facility. 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 $37.4 million at September 30, 2013.

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 or (ii) the rate for AEM’s borrowings under its committed line of credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013. There were no borrowings outstanding under this facility at September 30, 2013.
Shelf Registration
On March 28, 2013, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $1.75 billion in common stock and/or debt securities available for issuance, which replaced our registration statement that expired on March 31, 2013. As of September 30, 2013, $1.75 billion was available under the shelf registration statement.
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, 2013. 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, 2013 were as follows (in thousands):
2014
$
—

2015
500,000

2016
—

2017
250,000

2018
—

Thereafter
1,710,000

$
2,460,000

v2.4.0.8

Financial Instruments
12 Months Ended

Sep. 30, 2013

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 natural gas distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.
Our financial instruments do not contain any credit-risk-related or other contingent features that could cause 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, 2013 and 2012:

Natural Gas
Distribution

Nonregulated

Total

(In thousands)
September 30, 2013

Assets from risk management activities, current⁽¹⁾
$
1,837

$
16,262

$
18,099

Assets from risk management activities, noncurrent
109,354

—

109,354

Liabilities from risk management activities, current⁽¹⁾
(1,543
)

—

(1,543
)
Liabilities from risk management activities, noncurrent
—

(6,133
)

(6,133
)
Net assets (liabilities)
$
109,648

$
10,129

$
119,777

September 30, 2012⁽³⁾

Assets from risk management activities, current⁽²⁾
$
6,934

$
17,773

$
24,707

Assets from risk management activities, noncurrent
2,283

—

2,283

Liabilities from risk management activities, current⁽²⁾
(85,366
)

(15
)

(85,381
)
Liabilities from risk management activities, noncurrent
—

(9,206
)

(9,206
)
Net assets (liabilities)
$
(76,149
)

$
8,552

$
(67,597
)

⁽¹⁾
Includes $24.8 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $8.6 million was used to offset current risk management liabilities under master netting arrangements and the remaining $16.2 million is classified as current risk management assets.
⁽²⁾
Includes $23.7 million of cash held on deposit to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.
⁽³⁾
The September 30, 2012 amounts are presented net of assets and liabilities held for sale in conjunction with the sale of our Georgia operations. At September 30, 2012, assets and liabilities held for sale included $0.1 million of current assets from risk management activities and $0.3 million of current liabilities from risk management activities.
Regulated Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 22.8 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $4.03 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.
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 deliver gas to customers. These financial instruments have maturity dates ranging from one to 55 months. We use financial instruments, designated as fair value hedges, to hedge natural gas inventory used in these operations. We also use storage and basis swaps, futures and various over-the-counter and exchange-traded options primarily to protect the economic value of our fixed price and storage books. These financial instruments have not been designated as hedges.

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, 2013, our nonregulated segment had net open positions (including existing storage and related financial contracts) of 0.1 Bcf.
Interest Rate Risk Management Activities
We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used Treasury locks to mitigate interest rate risk; however, in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.
In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million out of a total $500 million of senior notes that were issued on January 11, 2013. This offering is discussed in Note 5. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with a payment of $66.6 million to the counterparties due to a decrease in the 30-year Treasury rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.6 million unrealized loss 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 the fourth quarter of fiscal 2012 we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility through December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.
In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated 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.
In September 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $300 million of a total $400 million of senior notes that were issued in June 2011. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on June 7, 2011 with the receipt of $20.1 million from the counterparties due to an increase in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the net $12.6 million unrealized 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.
Additionally, our original fiscal 2011 financing plans included the issuance of $250 million of 30-year unsecured notes in November 2011 to fund our capital expenditure program. In September 2010, we entered into two Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuance of these senior notes, which were designated as cash flow hedges. Due primarily to stronger than anticipated cash flows primarily resulting from the extension of the Bush tax cuts that allow the continued use of bonus depreciation on qualifying expenditures through December 31, 2011, the need to issue $250 million of debt in November was eliminated and the related Treasury lock agreements were unwound in March 2011. As a result of unwinding these Treasury locks, we recognized a pre-tax cash gain of $27.8 million during the second quarter of fiscal 2011.
In prior years, 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 2043.
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, 2013, 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, 2013, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type

Hedge
Designation

Natural
Gas
Distribution

Nonregulated

Quantity (MMcf)
Commodity contracts

Fair Value

—

(13,033
)

Cash Flow

—

31,195

Not designated

29,185

75,683

29,185

93,845

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, 2013 and 2012. As required by authoritative accounting literature, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $24.8 million and $23.7 million of cash held on deposit in margin accounts as of September 30, 2013 and 2012 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 14.

Balance Sheet Location

Natural
Gas
Distribution

Nonregulated

Total

(In thousands)

September 30, 2013

Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

$
—

$
9,094

$
9,094

Noncurrent commodity contracts

Deferred charges and other assets

107,512

416

107,928

Liability Financial Instruments

Current commodity contracts

Other current liabilities

—

(12,173
)

(12,173
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(1,639
)

(1,639
)
Total

107,512

(4,302
)

103,210

Not Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

1,837

65,388

67,225

Noncurrent commodity contracts

Deferred charges and other assets

1,842

40,982

42,824

Liability Financial Instruments

Current commodity contracts

Other current liabilities

(1,543
)

(70,876
)

(72,419
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(45,892
)

(45,892
)
Total

2,136

(10,398
)

(8,262
)
Total Financial Instruments

$
109,648

$
(14,700
)

$
94,948

Balance Sheet Location

Natural
Gas
Distribution

Nonregulated

Total

(In thousands)
September 30, 2012

Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets

$
—

$
19,301

$
19,301

Noncurrent commodity contracts

Deferred charges and other assets

—

1,923

1,923

Liability Financial Instruments

Current commodity contracts

Other current liabilities

(85,040
)

(23,787
)

(108,827
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(4,999
)

(4,999
)
Total

(85,040
)

(7,562
)

(92,602
)
Not Designated As Hedges:

Asset Financial Instruments

Current commodity contracts

Other current assets⁽¹⁾

7,082

98,393

105,475

Noncurrent commodity contracts

Deferred charges and other assets

2,283

60,932

63,215

Liability Financial Instruments

Current commodity contracts

Other current liabilities⁽²⁾

(585
)

(99,824
)

(100,409
)
Noncurrent commodity contracts

Deferred credits and other liabilities

—

(67,062
)

(67,062
)
Total

8,780

(7,561
)

1,219

Total Financial Instruments

$
(76,260
)

$
(15,123
)

$
(91,383
)

⁽¹⁾
Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.
⁽²⁾
Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the years ended September 30, 2013, 2012 and 2011, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $18.2 million, $23.1 million and $24.8 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, 2013, 2012 and 2011 is presented below.

Fiscal Year Ended September 30

2013

2012

2011

(In thousands)
Commodity contracts
$
2,165

$
30,266

$
16,552

Fair value adjustment for natural gas inventory designated as the hedged item
15,938

(5,797
)

9,824

Total decrease in purchased gas cost
$
18,103

$
24,469

$
26,376

The decrease in purchased gas cost is comprised of the following:

Basis ineffectiveness
$
(208
)

$
1,170

$
803

Timing ineffectiveness
18,311

23,299

25,573

$
18,103

$
24,469

$
26,376

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. During the year ended September 30, 2012, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market. We did not record a writedown for nonqualifying natural gas inventory for the years ended September 30, 2013 and 2011.
Cash Flow Hedges
The impact of cash flow hedges on our consolidated income statements for the years ended September 30, 2013, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

Fiscal Year Ended September 30, 2013

Natural
Gas
Distribution

Regulated
Transmission
and Storage

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
)

Fiscal Year Ended September 30, 2012

Natural
Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Consolidated

(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

$
—

$
(62,678
)

$
(62,678
)
Loss arising from ineffective portion of commodity contracts
—

—

(1,369
)

(1,369
)
Total impact on purchased gas cost
—

—

(64,047
)

(64,047
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,009
)

—

—

(2,009
)
Total impact from cash flow hedges
$
(2,009
)

$
—

$
(64,047
)

$
(66,056
)

Fiscal Year Ended September 30, 2011

Natural
Gas
Distribution

Regulated
Transmission
and Storage

Nonregulated

Consolidated

(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

$
—

$
(28,430
)

$
(28,430
)
Loss arising from ineffective portion of commodity contracts
—

—

(1,585
)

(1,585
)
Total impact on purchased gas cost
—

—

(30,015
)

(30,015
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(2,455
)

—

—

(2,455
)
Gain on unwinding of interest rate agreement reclassified from AOCI into miscellaneous income
21,803

6,000

—

27,803

Total impact from cash flow hedges
$
19,348

$
6,000

$
(30,015
)

$
(4,667
)

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, 2013 and 2012. 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

2013

2012

(In thousands)
Increase (decrease) in fair value:

Interest rate agreements
$
79,963

$
(11,458
)
Forward commodity contracts
(2,057
)

(30,366
)
Recognition of (gains) losses in earnings due to settlements:

Interest rate agreements
2,216

1,342

Forward commodity contracts
6,576

38,232

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾
$
86,698

$
(2,250
)

⁽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, 2013. However, the table below does not include the expected recognition in earnings of the interest rate agreements entered into in October 2012 as those financial instruments have not yet settled.

Interest Rate
Agreements

Commodity
Contracts

Total

(In thousands)
2014
$
(2,686
)

$
(3,748
)

$
(6,434
)
2015
(804
)

(425
)

(1,229
)
2016
(634
)

(163
)

(797
)
2017
(735
)

(109
)

(844
)
2018
(936
)

(31
)

(967
)
Thereafter
(24,569
)

—

(24,569
)
Total⁽¹⁾
$
(30,364
)

$
(4,476
)

$
(34,840
)

⁽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, 2013, 2012 and 2011 was an increase (decrease) in purchased gas cost of $3.0 million, $(2.5) million and $(1.4) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.

v2.4.0.8

Commitments and Contingencies
12 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies
Commitments and Contingencies
Litigation
Since April 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.
Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.
During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.
A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals (Court), appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments were held in the case on August 27, 2012.
In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.
The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and to the landowners’ motion on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have been engaged in discovery activities in this case.
Tennessee Business License Tax
Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. The Company anticipates a decision by the Chancery Court on the remaining issues in fiscal 2014. AEM has been assessed $6.1 million in business taxes and $3.7 million in penalties and interest for the period from December 2002 through March 31, 2012. We have accrued what we believe to be an adequate amount for the anticipated resolution of this matter and we will continue to review and if appropriate adjust this reserve until this matter is resolved. We continue to believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
We are a party to other litigation and claims that have arisen in the ordinary course of our business. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims 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 natural gas distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. At September 30, 2013, the estimated commitments under these contracts are $230.5 million for fiscal 2014.
Our nonregulated segment has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2013, we were committed to purchase 78.0 Bcf within one year, 21.9 Bcf within one to three years and 1.0 Bcf after three years under indexed contracts. We are committed to purchase 6.1 Bcf within one year and 0.2 Bcf within one to three years under fixed price contracts with prices ranging from $3.32 to $6.36 per Mcf. Purchases under these contracts totaled $1,246.1 million, $978.8 million and $1,498.6 million for 2013, 2012 and 2011.
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, 2013 are as follows (in thousands):
2014
$
12,662

2015
5,113

2016
743

2017
170

2018
142

Thereafter
356

$
19,186

Other Contingencies
In December 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines.
The Company and the Commission entered into a stipulation and consent agreement, which was approved by the Commission on December 9, 2011, thereby resolving this investigation. The Commission’s findings of violations were limited to the nonregulated operations of the Company. Under the terms of the agreement, the Company paid to the United States Treasury a total civil penalty of approximately $6.4 million and to energy assistance programs approximately $5.6 million in disgorgement of unjust profits plus interest for violations identified during the investigation. The resolution of this matter did not have a material adverse impact on the Company’s financial position, results of operations or cash flows and none of the payments were charged to any of the Company’s customers. In addition, none of the services the Company provides to any of its regulated or nonregulated customers were affected by the agreement.
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.

v2.4.0.8

Document and Entity Information (USD $)
12 Months Ended

Sep. 30, 2013

Nov. 08, 2013

Mar. 31, 2013

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, 2013

Document Fiscal Year Focus 2013

Document Fiscal Period Focus FY

Amendment Flag false

Entity Common Stock Shares Outstanding 90,912,251

Entity Well Known Seasoned Issuer Yes

Entity Voluntary Filers No

Entity Current Reporting Status Yes

Entity Public Float $ 3,816,801,052

v2.4.0.8

Income Taxes
12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes
Income Taxes
The components of income tax expense from continuing operations for 2013, 2012 and 2011 were as follows:

2013

2012

2011

(In thousands)
Current

Federal
$
—

$
631

$
(13,298
)
State
8,178

6,888

6,841

Deferred

Federal
124,836

103,971

107,950

State
9,605

(13,237
)

5,498

Investment tax credits
(20
)

(27
)

(172
)

$
142,599

$
98,226

$
106,819

Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2013, 2012 and 2011 are set forth below:

2013

2012

2011

(In thousands)
Tax at statutory rate of 35%
$
130,655

$
101,648

$
103,743

Common stock dividends deductible for tax reporting
(2,153
)

(2,096
)

(1,930
)
Penalties
153

66

2,292

Recognition (settlement) of uncertain tax positions
1,341

1,831

(4,950
)
State taxes (net of federal benefit)
10,687

(5,958
)

8,109

Other, net
1,916

2,735

(445
)
Income tax expense
$
142,599

$
98,226

$
106,819

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, 2013 and 2012 are presented below:

2013

2012

(In thousands)
Deferred tax assets:

Accruals not currently deductible for tax purposes
$
11,496

$
7,906

Customer advances
4,279

4,721

Nonqualified benefit plans
52,051

48,513

Postretirement benefits
63,919

62,802

Treasury lock agreements
—

25,448

Unamortized investment tax credit
6

14

Tax net operating loss and credit carryforwards
206,996

164,419

Difference between book and tax on mark to market accounting
2,271

2,342

Other, net
—

7,223

Total deferred tax assets
341,018

323,388

Deferred tax liabilities:

Difference in net book value and net tax value of assets
(1,445,450
)

(1,254,698
)
Pension funding
(23,480
)

(32,812
)
Gas cost adjustments
(19,182
)

(21,806
)
Interest rate agreements
(21,726
)

—

Cost expensed for tax purposes and capitalized for book purposes
(2,815
)

(2,065
)
Other, net
(7,115
)

—

Total deferred tax liabilities
(1,519,768
)

(1,311,381
)
Net deferred tax liabilities
$
(1,178,750
)

$
(987,993
)
Deferred credits for rate regulated entities
$
(51
)

$
140

At September 30, 2013, we had $10.1 million of federal alternative minimum tax credit carryforwards, $185.3 million of federal net operating loss carryforwards, $11.0 million of state net operating loss carryforwards and $0.6 million of state tax credits. The alternative minimum tax credit carryforwards do not expire. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. Depending on the jurisdiction in which the state net operating loss was generated, the state net operating loss carryforwards will begin to expire between 2016 and 2030. The state tax credits will begin to expire in 2018. We believe it is more likely than not that the benefit from certain charitable contribution carryforwards will not be realized. In recognition of this risk, we have established a valuation allowance of $1.1 million for deferred tax assets relating to these charitable contribution carryforwards.
At September 30, 2013, we had recorded liabilities associated with uncertain tax positions totaling $3.2 million. The realization of these tax benefits would reduce our income tax expense by approximately $3.2 million.
Additionally, results for fiscal 2012 were favorably impacted by a state tax benefit of $13.6 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.
At September 30, 2010, we had accrued liabilities associated with uncertain tax positions totaling $6.7 million. During the fiscal year ended September 30, 2011, the IRS completed its audit of fiscal years 2005-2007. All uncertain tax positions were effectively settled upon completion of the audit. As a result of the settlement, we reduced our unrecognized tax benefits by $6.7 million in the second quarter of fiscal 2011. Income tax expense was reduced by $5.0 million in the second quarter due to the realization of the tax positions which were previously uncertain.
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.

v2.4.0.8

Income Taxes (Details) (USD $)
3 Months Ended 12 Months Ended

Mar. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2010

Current income taxes

Federal $ 0 $ 631,000 $ (13,298,000)

State 8,178,000 6,888,000 6,841,000

Deferred income taxes

Federal 124,836,000 103,971,000 107,950,000

State 9,605,000 (13,237,000) 5,498,000

Investment tax credits (20,000) (27,000) (172,000)

Income tax expense 142,599,000 98,226,000 106,819,000

Deferred tax assets

Accruals not currently deductible for tax purposes 11,496,000 7,906,000

Customer advances 4,279,000 4,721,000

Nonqualified benefit plans 52,051,000 48,513,000

Postretirement benefits 63,919,000 62,802,000

Treasury lock agreements 0 25,448,000

Unamortized investment tax credit 6,000 14,000

Tax net operating loss and credit carryforwards 206,996,000 164,419,000

Difference between book and tax on mark to market accounting 2,271,000 2,342,000

Other, net 0 7,223,000

Total deferred tax assets 341,018,000 323,388,000

Deferred tax liabilities

Difference in net book value and net tax value of assets (1,445,450,000) (1,254,698,000)

Pension funding (23,480,000) (32,812,000)

Gas Cost Adjustments (19,182,000) (21,806,000)

Interest rate agreements (21,726,000) 0

Cost expensed for tax purposes and capitalized for book purposes (2,815,000) (2,065,000)

Other, net (7,115,000) 0

Total deferred tax liabilities (1,519,768,000) (1,311,381,000)

Net deferred tax liabilities (1,178,750,000) (987,993,000)

Operating Loss Carryforwards [Line Items]

Liabilities associated with uncertain tax positions 3,200,000 6,700,000

Liability for Uncertain Tax Positions, Decrease due to Settlement 6,700,000

Settlement of uncertain tax positions 5,000,000

Deferred credits for rate regulated entities (51,000) 140,000

Other Information Pertaining to Income Taxes results for fiscal 2012 were favorably impacted by a state tax benefit of $13.6 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.

State tax benefit 13,600,000

Deferred Tax Assets, Valuation Allowance 1,100,000

Internal Revenue Service IRS [Member]

Operating Loss Carryforwards [Line Items]

Amount 185,300,000

State and Local Jurisdiction [Member]

Operating Loss Carryforwards [Line Items]

Amount 11,000,000

Federal Alternative Minimum Tax Credit Carryforward [Member]

Other Tax Carryforward [Line Items]

Amount 10,100,000

State Tax Credit Carryforward [Member]

Other Tax Carryforward [Line Items]

Amount $ 600,000

v2.4.0.8

Commitments and Contingencies (Details) (USD $)
0 Months Ended 12 Months Ended

Jan. 25, 2013

Dec. 09, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Loss Contingency Information About Litigation Matters [Abstract]

Loss Contingency, Compensatory Damages Awarded, Value $ 10,000

Description of Pending Litigation Since April 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate. Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases. During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries. A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals (Court), appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments were held in the case on August 27, 2012. In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and to the landowners’ motion on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have been engaged in discovery activities in this case.

Business License Tax [Abstract]

Business License Tax Examination, Description Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. The Company anticipates a decision by the Chancery Court on the remaining issues in fiscal 2014. AEM has been assessed $6.1 million in business taxes and $3.7 million in penalties and interest for the period from December 2002 through March 31, 2012. We have accrued what we believe to be an adequate amount for the anticipated resolution of this matter and we will continue to review and if appropriate adjust this reserve until this matter is resolved. We continue to believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

Long Term Purchase Commitment [Abstract]

Significant Purchase Commitment Remaining Minimum Amount Committed Next Fiscal Year 230,500,000

Long Term Purchase Commitment [Line Items]

Significant Purchase Commitment Amount Description 1,246,100,000 978,800,000 1,498,600,000

Estimated Contractual Demand Fees [Abstract]

2014 12,662,000

2015 5,113,000

2016 743,000

2017 170,000

2018 142,000

Thereafter 356,000

Total Estimated Contractual Demand Fees 19,186,000

Loss Contingency, Settlement [Abstract]

Loss Contingency, Civil Penalty Paid to United States Treasury 6,400,000

Loss Contingency, Civil Penalty Paid to Energy Assistance Programs $ 5,600,000

Inventories Under Indexed Contracts [Member]

Long Term Purchase Commitment [Line Items]

Long Term Purchase Commitment Minimum Quantity Required Within One Year 78.0

Long Term Purchase Commitment Minimum Quantity Required One To Three Years 21.9

Long Term Purchase Commitment Minimum Quantity Required After Three Years 1.0

Inventories Under Fixed Price Contracts [Member]

Long Term Purchase Commitment [Line Items]

Long Term Purchase Commitment Minimum Quantity Required Within One Year 6.1

Long Term Purchase Commitment Minimum Quantity Required One To Three Years 0.2

Purchase Commitment Amount Minimum 3.32

Purchase Commitment Amount Maximum 6.36

Retirement and Post-Retirement Employee Benefit Plans Fair Value Disclosures (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	$ 72,682,000	$ 64,398,000
Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	40,094,000	40,212,000
Fair Value Inputs Level 2 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	32,588,000	24,186,000
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	396,482,000	350,296,000
Fair value of accounts receivable	400,000	500,000
Pension Plans, Defined Benefit [Member] \| Equity Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	143,543,000	114,799,000
Pension Plans, Defined Benefit [Member] \| Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	12,266,000	21,010,000
Pension Plans, Defined Benefit [Member] \| Registered Investment Companies, Domestic [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	30,200,000	19,984,000
Pension Plans, Defined Benefit [Member] \| Registered Investment Companies, International [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	47,036,000	36,714,000
Pension Plans, Defined Benefit [Member] \| Common Collective Trusts [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	57,627,000	52,155,000
Pension Plans, Defined Benefit [Member] \| Mortgage-backed securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	18,446,000	19,509,000
Pension Plans, Defined Benefit [Member] \| U.S. Treasuries [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	4,780,000	8,084,000
Pension Plans, Defined Benefit [Member] \| Corporate Debt Securities [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	35,012,000	35,960,000
Pension Plans, Defined Benefit [Member] \| Limited Partnership Interest [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	47,417,000	41,926,000
Pension Plans, Defined Benefit [Member] \| Real Estate Investment [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	155,000	155,000
Pension Plans, Defined Benefit [Member] \| Fair Value Inputs Level 1 [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	224,896,000	179,234,000
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	143,543,000	114,799,000
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	30,200,000	19,984,000
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	47,036,000	36,714,000
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	4,117,000	7,597,000
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	140,000
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	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	171,431,000	170,907,000
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	12,266,000	21,010,000
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	57,627,000	52,155,000
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	18,446,000	19,509,000
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	663,000	487,000
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	35,012,000	35,960,000
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	47,417,000	41,786,000
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	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	155,000	155,000
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	155,000	155,000
Defined Benefit Plan, Plan Assets at Fair Value, Valuation Inputs	The fair value of our Level 3 real estate assets was determined using a real estate appraisal obtained from an independent third party that consisted of several unobservable inputs such as comparable land sales values per square foot in the range of $0.94 to $2.98 and comparable building sales values per square foot in the range of $23.13 to $30.42.
Other Postretirement Benefit Plans, Defined Benefit [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	106,413,000	78,568,000
Other Postretirement Benefit Plans, Defined Benefit [Member] \| Money Market Funds [Member]
Schedule of Total Investments at Fair Value [Line Items]
Investments, Fair Value Disclosure	3,356,000	2,360,000
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	9,614,000	7,756,000
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	93,443,000	68,452,000
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	103,057,000	76,208,000
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	9,614,000	7,756,000
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	93,443,000	68,452,000
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	3,356,000	2,360,000
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	3,356,000	2,360,000
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
Supplemental Executive Retirement Plans, Defined Benefit [Member]
Schedule of Total Investments at Fair Value [Line Items]
Available-for-sale Securities	$ 44,500,000	$ 41,800,000
Minimum [Member]
Schedule of Total Investments at Fair Value [Line Items]
Comparable Land Sale Values	0.94
Comparable Building Sales Values	23.13
Maximum [Member]
Schedule of Total Investments at Fair Value [Line Items]
Comparable Land Sale Values	2.98
Comparable Building Sales Values	30.42

CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Operating revenues
Operating revenues	$ 685,171	$ 857,935	$ 1,308,996	$ 1,034,155	$ 552,566	$ 576,414	$ 1,225,509	$ 1,083,994	$ 3,886,257	$ 3,438,483	$ 4,286,435
Purchased gas cost
Purchased gas cost									2,474,207	2,114,744	2,985,615
Gross profit	300,440	316,497	432,751	362,362	249,389	293,171	425,787	355,392	1,412,050	1,323,739	1,300,820
Operating expenses
Operation and maintenance									488,020	453,613	442,965
Depreciation and amortization									235,079	237,525	223,832
Taxes, other than income									187,072	181,073	177,767
Asset impairments									0	5,288	30,270
Total operating expenses									910,171	877,499	874,834
Operating income	50,383	86,396	210,178	154,922	22,791	81,546	202,432	139,471	501,879	446,240	425,986
Miscellaneous income (expense), net									(197)	(14,644)	21,184
Interest charges									128,385	141,174	150,763
Income from continuing operations before income taxes									373,297	290,422	296,407
Income tax expense									142,599	98,226	106,819
Income from continuing operations	7,536	33,474	112,340	77,348	(286)	28,014	102,084	62,384	230,698	192,196	189,588
Income from discontinued operations, net of tax	0	0	4,085	3,117	1,904	3,118	7,027	6,123	7,202	18,172	18,013
Gain on sale of discontinued operations, net of tax	0	5,294	0	0	6,349	0	0	0	5,294	6,349	0
Net income	7,536	38,768	116,425	80,465	7,967	31,132	109,111	68,507	243,194	216,717	207,601
Income per share from continuing operations - basic (usd per share)	$ 0.08	$ 0.37	$ 1.24	$ 0.85	$ 0.00	$ 0.31	$ 1.12	$ 0.68	$ 2.54	$ 2.12	$ 2.08
Income per share from discontinued operations - basic (usd per share)	$ 0.00	$ 0.06	$ 0.04	$ 0.04	$ 0.09	$ 0.03	$ 0.08	$ 0.07	$ 0.14	$ 0.27	$ 0.20
Net income per share — basic (usd per share)	$ 0.08	$ 0.43	$ 1.28	$ 0.89	$ 0.09	$ 0.34	$ 1.20	$ 0.75	$ 2.68	$ 2.39	$ 2.28
Income per share from continuing operations - diluted (usd per share)	$ 0.08	$ 0.36	$ 1.23	$ 0.85	$ 0.00	$ 0.31	$ 1.12	$ 0.68	$ 2.50	$ 2.10	$ 2.07
Income per share from discontinued operations - diluted (usd per share)	$ 0.00	$ 0.06	$ 0.04	$ 0.03	$ 0.09	$ 0.03	$ 0.08	$ 0.07	$ 0.14	$ 0.27	$ 0.20
Net income per share — diluted (usd per share)	$ 0.08	$ 0.42	$ 1.27	$ 0.88	$ 0.09	$ 0.34	$ 1.20	$ 0.75	$ 2.64	$ 2.37	$ 2.27
Weighted average shares outstanding:
Basic (shares)									90,533	90,150	90,201
Diluted (shares)									91,711	91,172	90,652
Natural Gas Distribution Segment [Member]
Operating revenues
Operating revenues	360,386	467,144	905,176	666,787	282,516	315,634	871,067	676,113	2,399,493	2,145,330	2,470,664
Purchased gas cost
Purchased gas cost									1,318,257	1,122,587	1,452,721
Gross profit									1,081,236	1,022,743	1,017,943
Operating expenses
Operation and maintenance									375,188	353,879	341,758
Depreciation and amortization									195,581	202,026	193,642
Taxes, other than income									167,374	162,377	160,455
Asset impairments										0	0
Total operating expenses									738,143	718,282	695,855
Operating income									343,093	304,461	322,088
Miscellaneous income (expense), net									2,535	(12,657)	16,242
Interest charges									98,296	110,642	115,740
Income from continuing operations before income taxes									247,332	181,162	222,590
Income tax expense									96,476	57,314	77,885
Income from continuing operations									150,856	123,848	144,705
Income from discontinued operations, net of tax									7,202	18,172	18,013
Gain on sale of discontinued operations, net of tax									5,649	6,349
Net income									163,707	148,369	162,718
Regulated Transmission and Storage Segment [Member]
Operating revenues
Operating revenues	72,330	74,041	61,848	60,681	65,482	67,073	58,037	56,759	268,900	247,351	219,373
Purchased gas cost
Purchased gas cost									0	0	0
Gross profit									268,900	247,351	219,373
Operating expenses
Operation and maintenance									76,686	71,521	70,401
Depreciation and amortization									35,302	31,438	25,997
Taxes, other than income									17,059	15,568	14,700
Asset impairments										0	0
Total operating expenses									129,047	118,527	111,098
Operating income									139,853	128,824	108,275
Miscellaneous income (expense), net									(2,285)	(1,051)	4,715
Interest charges									30,678	29,414	31,432
Income from continuing operations before income taxes									106,890	98,359	81,558
Income tax expense									38,630	35,300	29,143
Income from continuing operations									68,260	63,059	52,415
Income from discontinued operations, net of tax									0	0	0
Gain on sale of discontinued operations, net of tax									0	0
Net income									68,260	63,059	52,415
Nonregulated Segment [Member]
Operating revenues
Operating revenues	348,061	421,808	428,948	399,894	280,114	256,250	370,763	444,176	1,598,711	1,351,303	2,024,893
Purchased gas cost
Purchased gas cost									1,535,380	1,296,179	1,959,893
Gross profit									63,331	55,124	65,000
Operating expenses
Operation and maintenance									37,569	29,697	32,308
Depreciation and amortization									4,196	4,061	4,193
Taxes, other than income									2,639	3,128	2,612
Asset impairments										5,288	30,270
Total operating expenses									44,404	42,174	69,383
Operating income									18,927	12,950	(4,383)
Miscellaneous income (expense), net									2,316	1,035	657
Interest charges									2,168	3,084	4,015
Income from continuing operations before income taxes									19,075	10,901	(7,741)
Income tax expense									7,493	5,612	(209)
Income from continuing operations									11,582	5,289	(7,532)
Income from discontinued operations, net of tax									0	0	0
Gain on sale of discontinued operations, net of tax									(355)	0
Net income									11,227	5,289	(7,532)
Intersegment Elimination [Member]
Operating revenues
Operating revenues	(95,606)	(105,058)	(86,976)	(93,207)	(75,546)	(62,543)	(74,358)	(93,054)	(380,847)	(305,501)	(428,495)
Purchased gas cost
Purchased gas cost									(379,430)	(304,022)	(426,999)
Gross profit									(1,417)	(1,479)	(1,496)
Operating expenses
Operation and maintenance									(1,423)	(1,484)	(1,502)
Depreciation and amortization									0	0	0
Taxes, other than income									0	0	0
Asset impairments										0	0
Total operating expenses									(1,423)	(1,484)	(1,502)
Operating income									6	5	6
Miscellaneous income (expense), net									(2,763)	(1,971)	(430)
Interest charges									(2,757)	(1,966)	(424)
Income from continuing operations before income taxes									0	0	0
Income tax expense									0	0	0
Income from continuing operations									0	0	0
Income from discontinued operations, net of tax									0	0	0
Gain on sale of discontinued operations, net of tax									0	0
Net income									$ 0	$ 0	$ 0

Stock and Other Compensation Plans (Details) (USD $)	0 Months Ended			12 Months Ended
Stock and Other Compensation Plans (Details) (USD $)	Sep. 28, 2011	Apr. 04, 2011	Jul. 10, 2010	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Jul. 02, 2010
Accelerated Share Repurchase Agreement [Abstract]
Accelerated Share Repurchases Payment			$ 100,000,000	$ 100,000,000			$ 100,000,000
Stock repurchased and retired, shares		375,468	2,958,580	3,334,048
Accelerated Share Repurchases, Final Price Paid Per Share				$ 29.99
Stock Repurchase Program [Abstract]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased				5,000,000
Stock Repurchase Program, Period in Force	5 years 0 months 0 days
Stock Repurchased During Period, Shares				387,991
Stock Repurchased During Period, Value				12,500,000
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Stock Based Compensation Expense				17,800,000	19,200,000	11,600,000
Authorized Shares				8,700,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available				1,403,439
Stock option, expiration period				10 years
Summary Of Stock Option Activity [Abstract]
Exercisable at end of year-Options				7,930
Exercisable at end of year-Weighted Average				$ 25.96
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Nonvested at beginning of year-Shares				1,262,582	1,264,142	1,293,960
Nonvested at beginning of year-Weighted Average				$ 32.46	$ 29.56	$ 27.28
Granted-Shares				473,775	532,711	491,345
Granted-Weighted Average				$ 40.48	$ 33.44	$ 33.10
Vested-Shares				(657,795)	(494,308)	(464,321)
Vested-Weighted Average				$ 32.20	$ 26.32	$ 27.21
Forfeited-Shares				(25,718)	(39,963)	(56,842)
Forfeited-Weighted Average				$ 33.42	$ 29.83	$ 27.56
Nonvested at end of year-Shares				1,052,844	1,262,582	1,264,142
Nonvested at end of year-Weighted Average				$ 36.20	$ 32.46	$ 29.56
Unrecognized Compensation Cost				5,100,000
Weighted Average Recognized Period				1 year 7 months 6 days
Fair Value Restricted Stock Vested				21,200,000	13,000,000	12,600,000
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
Minimum [Member]
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Stock option, vesting period				1 year
Maximum [Member]
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Stock option, vesting period				3 years

Financial Instruments Descriptions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Sep. 30, 2013 MMcf Bcf	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2011 Interest Rate Hedges, Senior Notes 2011 Anticipated Issuance [Member]	Sep. 30, 2011 Interest Rate Hedges, Senior Notes 2011 Issuance [Member]	Sep. 30, 2013 Interest Rate Hedges, Senior Notes 2013 Issuance [Member]	Aug. 31, 2011 Interest Rate Hedges, Senior Notes 2013 Issuance [Member]	Sep. 30, 2013 Interest Rate Hedges, Short-term Note 2012 Issuance [Member]	Sep. 30, 2013 Interest Rate Hedges, Senior Notes 2015 Issuance [Member]	Sep. 30, 2013 Interest Rate Hedges, Senior Notes 2017 Issuance [Member]
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Minimum Hedge Percentage Of Anticipated Heating Season Gas	25.00%
Maximum Hedge Percentage Of Anticipated Heating Season Gas	50.00%
Hedge Percentage Of Actual Heating Season Gas	33.00%
Hedge Volume Of Actual Heating Season Gas	22,800
Weighted Average Cost Of Actual Heating Season Gas	4.03
Minimum Length Of Time Hedged In Cash Flow Hedge	0 years 1 month 0 days
Maximum Length of Time Hedged in Cash Flow Hedge	0 years 55 months 0 days
Net Open Positions	0.1
Cash Collateral Right To Reclaim Cash	$ 24.8	$ 23.7
Gain Loss On Hedge Ineffectiveness	18.2	23.1	24.8
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	3.0	(2.5)	(1.4)
Natural Gas Inventory [Abstract]
Inventory Write-down		1.7
Derivative [Line Items]
Derivative, Notional Amount				250	300		350	260	500	250
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)					(20.1)	66.6
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Net of Tax, Accumulated Other Comprehensive Income (Loss)					12.6
Gain (Loss) on Interest Rate Agreements Settlements				$ 27.8

Concentration of Credit Risk	12 Months Ended
Concentration of Credit Risk	Sep. 30, 2013
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 natural gas 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.

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock [Member]	Additional Paid In Capital [Member]	Accumulated Other Comprehensive Income [Member]	Retained Earnings [Member]
Common shareholders' equity, beginning balance at Sep. 30, 2010	$ 2,178,348	$ 451	$ 1,714,364	$ (23,372)	$ 486,905
Common stock shares outstanding, balance at Sep. 30, 2010		90,164,103
Net income	207,601				207,601
Other comprehensive income (loss)	(25,088)			(25,088)
Repurchase of common stock, shares		(375,468)
Repurchase of common stock, amount	0	(2)	2
Repurchase of equity awards, shares		(169,793)
Repurchase of equity awards, amount	(5,299)	(1)	(5,298)
Cash dividends	(124,011)				(124,011)
Common stock issued:
Direct stock purchase plan, shares		0
Direct stock purchase plan, amount	(54)	0	(54)
1998 Long-term incentive plan, shares		675,255
1998 Long-term incentive plan, amount	13,889	3	13,886		0
Employee stock-based compensation	9,958		9,958
Outside directors stock-for-fee plan, shares		2,385
Outside directors stock-for-fee-plan, amount	77		77
Common shareholders' equity, ending balance at Sep. 30, 2011	2,255,421	451	1,732,935	(48,460)	570,495
Common stock shares outstanding, ending balance at Sep. 30, 2011		90,296,482
Net income	216,717				216,717
Other comprehensive income (loss)	853			853
Repurchase of common stock, shares		(387,991)
Repurchase of common stock, amount	(12,535)	(2)	(12,533)
Repurchase of equity awards, shares		(153,255)
Repurchase of equity awards, amount	(5,219)	0	(5,219)
Cash dividends	(125,796)				(125,796)
Common stock issued:
Direct stock purchase plan, amount	(65)	0	(65)
1998 Long-term incentive plan, shares		482,289
1998 Long-term incentive plan, amount	12,037	2	12,519		(484)
Employee stock-based compensation	17,752		17,752
Outside directors stock-for-fee plan, shares		2,375
Outside directors stock-for-fee-plan, amount	78		78
Common shareholders' equity, ending balance at Sep. 30, 2012	2,359,243	451	1,745,467	(47,607)	660,932
Common stock shares outstanding, ending balance at Sep. 30, 2012		90,239,900
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, 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 shareholders' equity, ending balance at Sep. 30, 2013	$ 2,580,409	$ 453	$ 1,765,811	$ 38,878	$ 775,267
Common stock shares outstanding, ending balance at Sep. 30, 2013		90,640,211

Fair Value Measurements Available-For-Sale Securities (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 64,023,000	$ 55,339,000
Available For Sale Securities Gross Unrealized Gain Accumulated In Investments	8,706,000	9,061,000
Available For Sale Securities Gross Unrealized Loss Accumulated In Investments	(47,000)	(2,000)
Fair value	72,682,000	64,398,000
Available-for-sale Securities, Other Disclosure Items [Abstract]
Available-for-sale Securities, Supplemental Executive Benefit Plans	44,500,000	41,800,000
Available-for-sale Securities, Gross Realized Gains	2,200,000
Equity Funds Domestic [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	27,043,000	25,779,000
Available For Sale Securities Gross Unrealized Gain Accumulated In Investments	7,476,000	8,183,000
Available For Sale Securities Gross Unrealized Loss Accumulated In Investments	(23,000)	0
Fair value	34,496,000	33,962,000
Equity Funds Foreign [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	4,536,000	5,568,000
Available For Sale Securities Gross Unrealized Gain Accumulated In Investments	1,062,000	682,000
Available For Sale Securities Gross Unrealized Loss Accumulated In Investments	0	0
Fair value	5,598,000	6,250,000
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	28,016,000	22,358,000
Available For Sale Securities Gross Unrealized Gain Accumulated In Investments	168,000	196,000
Available For Sale Securities Gross Unrealized Loss Accumulated In Investments	(24,000)	(2,000)
Fair value	28,160,000	22,552,000
Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	4,428,000	1,634,000
Available For Sale Securities Gross Unrealized Gain Accumulated In Investments	0	0
Available For Sale Securities Gross Unrealized Loss Accumulated In Investments	0	0
Fair value	$ 4,428,000	$ 1,634,000

Fair Value Measurements (Details) (USD $)	12 Months Ended
Fair Value Measurements (Details) (USD $)	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	$ 27,138,000		$ 127,453,000
Hedged portion of gas stored underground	67,192,000		44,758,000
Available-for-sale Securities	64,398,000		72,682,000
Total assets	158,728,000		244,893,000
Financial instruments, liabilities	94,846,000		7,676,000
Fair Value [Abstract]
Cash Collateral Right To Reclaim Cash	23,700,000		24,800,000
Cash Held In Margin Accounts Offset Current Risk Management Liabilities	5,900,000		8,600,000
Cash Held In Margin Accounts Classified Current Risk Management Asset	17,800,000		16,200,000
Debt Instrument Carrying Amount	1,960,131,000		2,460,000,000
Debt Instrument Fair Value			2,676,487,000
Other Matters [Abstract]
Asset Impairment Charges Park City	5,300,000	11,000,000
Nonrecurring fair value measurement	500,000
Asset Impairment Charges Fort Necessity		19,300,000
Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	1,634,000		4,428,000
Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	40,212,000		40,094,000
Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	22,552,000		28,160,000
Natural Gas Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	9,365,000		111,191,000
Financial instruments, liabilities	85,625,000		1,543,000
Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	17,773,000		16,262,000
Financial instruments, liabilities	9,221,000		6,133,000
Fair Value [Abstract]
Cash Collateral Right To Reclaim Cash	23,700,000		24,800,000
Cash Held In Margin Accounts Offset Current Risk Management Liabilities	5,900,000		8,600,000
Cash Held In Margin Accounts Classified Current Risk Management Asset	17,800,000		16,200,000
Fair Value Inputs Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	714,000		745,000
Hedged portion of gas stored underground	67,192,000		44,758,000
Available-for-sale Securities	40,212,000		40,094,000
Total assets	108,118,000		85,597,000
Financial instruments, liabilities	4,563,000		158,000
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	40,212,000		40,094,000
Fair Value Inputs Level 1 [Member] \| Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	0		0
Fair Value Inputs Level 1 [Member] \| Natural Gas Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	0		0
Financial instruments, liabilities	0		0
Fair Value Inputs Level 1 [Member] \| Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	714,000		745,000
Financial instruments, liabilities	4,563,000		158,000
Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	189,200,000		226,326,000
Hedged portion of gas stored underground	0		0
Available-for-sale Securities	24,186,000		32,588,000
Total assets	213,386,000		258,914,000
Financial instruments, liabilities	276,734,000		131,965,000
Fair Value Inputs Level 2 [Member] \| Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	1,634,000		4,428,000
Fair Value Inputs Level 2 [Member] \| Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	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	22,552,000		28,160,000
Fair Value Inputs Level 2 [Member] \| Natural Gas Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	9,365,000		111,191,000
Financial instruments, liabilities	85,625,000		1,543,000
Fair Value Inputs Level 2 [Member] \| Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	179,835,000		115,135,000
Financial instruments, liabilities	191,109,000		130,422,000
Fair Value Inputs Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	0		0
Hedged portion of gas stored underground	0		0
Available-for-sale Securities	0		0
Total assets	0		0
Financial instruments, liabilities	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] \| Natural Gas Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	0		0
Financial instruments, liabilities	0		0
Fair Value Inputs Level 3 [Member] \| Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	0		0
Financial instruments, liabilities	0		0
Netting And Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	(162,776,000)		(99,618,000)
Hedged portion of gas stored underground	0		0
Available-for-sale Securities	0		0
Total assets	(162,776,000)		(99,618,000)
Financial instruments, liabilities	(186,451,000)		(124,447,000)
Netting And Collateral [Member] \| Money Market Funds [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	0		0
Netting And Collateral [Member] \| Equity Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	0		0
Netting And Collateral [Member] \| Debt Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Available-for-sale Securities	0		0
Netting And Collateral [Member] \| Natural Gas Distribution Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	0		0
Financial instruments, liabilities	0		0
Netting And Collateral [Member] \| Nonregulated Segment [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	(162,776,000)		(99,618,000)
Financial instruments, liabilities	$ (186,451,000)		$ (124,447,000)

Retirement and Post-Retirement Employee Benefit Plans Net Periodic Cost (Details) (USD $)	0 Months Ended	12 Months Ended
	Apr. 02, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 17,754,000	$ 15,084,000	$ 14,384,000
Interest cost		19,334,000	21,568,000	22,264,000
Expected return on assets		(22,955,000)	(21,474,000)	(24,817,000)
Amortization of prior service cost		(141,000)	(141,000)	(429,000)
Recognized actuarial loss		19,066,000	14,451,000	9,498,000
Curtailment loss		0	0	(40,000)
Net periodic cost		33,058,000	29,488,000	20,860,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		18,800,000	16,353,000	14,403,000
Interest cost		12,964,000	13,861,000	12,813,000
Expected return on assets		(3,988,000)	(2,607,000)	(2,727,000)
Amortization of transition asset		1,081,000	1,511,000	1,511,000
Amortization of prior service cost		(1,450,000)	(1,450,000)	(1,450,000)
Recognized actuarial loss		4,196,000	2,648,000	347,000
Net periodic cost		31,603,000	30,316,000	24,897,000
Supplemental Executive Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		3,039,000	2,108,000	2,768,000
Interest cost		4,755,000	5,142,000	5,825,000
Amortization of transition asset		0	0	0
Amortization of prior service cost		0	0	0
Recognized actuarial loss		2,918,000	2,118,000	2,239,000
Settlements	(3,200,000)	3,160,000	0	0
Net periodic cost		13,872,000	9,368,000	10,832,000
Effect on Net Periodic Cost Due To Discount Rate Change, Remaining Fiscal Year	$ 100,000

CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 20,624	$ 9,425
Common Stock, Par Value Per Share	$ 0	$ 0
Common Stock, Stated Value Per Share	$ 0.005	$ 0.005
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	90,640,211	90,239,900

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
ASSETS
Property, plant and equipment	$ 7,446,272	$ 6,860,358
Construction in progress	275,747	274,112
Total property, plant and equipment and construction in progress	7,722,019	7,134,470
Less accumulated depreciation and amortization	1,691,364	1,658,866
Net property, plant and equipment	6,030,655	5,475,604
Current assets
Cash and cash equivalents	66,199	64,239
Accounts receivable, less allowance for doubtful accounts of $20,624 in 2013 and $9,425 in 2012	301,992	234,526
Gas stored underground	244,741	256,415
Other current assets	70,334	272,782
Total current assets	683,266	827,962
Goodwill and intangible assets	741,484	740,847
Deferred charges and other assets	484,996	451,262
Total assets	7,940,401	7,495,675
Shareholders' equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2013 — 90,640,211 shares, 2012 — 90,239,900 shares	453	451
Additional paid-in capital	1,765,811	1,745,467
Accumulated other comprehensive income (loss)	38,878	(47,607)
Retained earnings	775,267	660,932
Shareholders' equity	2,580,409	2,359,243
Long-term debt	2,455,671	1,956,305
Total capitalization	5,036,080	4,315,548
Current liabilities
Accounts payable and accrued liabilities	241,611	215,229
Other current liabilities	368,891	489,665
Short-term debt	367,984	570,929
Current maturities of long-term debt	0	131
Total current liabilities	978,486	1,275,954
Deferred income taxes	1,164,053	1,015,083
Regulatory cost of removal obligation	359,299	381,164
Pension and postretirement liabilities	358,787	457,196
Deferred credits and other liabilities	43,696	50,730
Total shareholders' equity and liabilities	$ 7,940,401	$ 7,495,675

Debt (Details) (USD $)	12 Months Ended					12 Months Ended		12 Months Ended					0 Months Ended				12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		3 Months Ended	12 Months Ended		12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended
Debt (Details) (USD $)	Sep. 30, 2013 credit_facility	Sep. 30, 2012	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Regulated Facilities [Member]	Sep. 30, 2013 First Facility Regulated Operations [Member]	Sep. 30, 2012 First Facility Regulated Operations [Member]	Sep. 30, 2013 Second Facility Regulated Operations [Member]	Sep. 30, 2013 Third Facility Regulated Operations [Member]	Sep. 30, 2013 Intercompany Facility Regulated Operations [Member]	Sep. 30, 2013 Nonregulated Facilities [Member]	Dec. 05, 2012 Nonregulated Facilities [Member] credit_facility	Dec. 05, 2012 Committed Facility Nonregulated Operations [Member]	Sep. 30, 2013 Committed Facility Nonregulated Operations [Member]	Sep. 30, 2012 Committed Facility Nonregulated Operations [Member]	Sep. 30, 2013 Uncommitted Facility Nonregulated Operations [Member] credit_facility	Sep. 30, 2013 Intercompany Facility Nonregulated Operations [Member]	Sep. 30, 2012 Intercompany Facility Nonregulated Operations [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2014 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2014 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2017 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2017 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2019 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2019 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2034 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2034 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2041 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2041 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2043 [Member]	Sep. 30, 2013 Unsecured Senior Notes Due 2043 [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2043 [Member]	Sep. 30, 2013 Bridge Loan [Member]	Sep. 30, 2013 Medium Term Notes Due 2025 [Member]	Sep. 30, 2012 Medium Term Notes Due 2025 [Member]	Sep. 30, 2013 Unsecured Debentures Due 2028 [Member]	Sep. 30, 2012 Unsecured Debentures Due 2028 [Member]	Sep. 30, 2013 Rental Property Term Note [Member]	Sep. 30, 2012 Rental Property Term Note [Member]	Sep. 30, 2012 Unsecured Senior Notes Due 2013 [Member]
Debt Instrument [Line Items]
Debt Instrument Interest Rate Stated Percentage																			4.95%		6.35%		8.50%		5.95%		5.50%		4.15%	4.15%			6.67%		6.75%
Debt Instrument Maturity Date																			Oct. 15, 2014		Jun. 15, 2017		Mar. 15, 2019		Oct. 15, 2034		Jun. 15, 2041			Jan. 15, 2043			Dec. 15, 2025		Jul. 15, 2028		Jul. 01, 2013
Debt Instrument Carrying Amount	$ 2,460,000,000	$ 1,960,131,000																	$ 500,000,000	$ 500,000,000	$ 250,000,000	$ 250,000,000	$ 450,000,000	$ 450,000,000	$ 200,000,000	$ 200,000,000	$ 400,000,000	$ 400,000,000	$ 500,000,000	$ 500,000,000	$ 0		$ 10,000,000	$ 10,000,000	$ 150,000,000	$ 150,000,000	$ 0	$ 131,000
Debt Instrument Unamortized Discount	4,329,000	3,695,000
Current maturities of long-term debt	0	131,000
Long-term debt	2,455,671,000	1,956,305,000
Debt Instrument Interest Rate Effective Percentage																													4.67%	4.67%
Net Proceeds From Issuance of Debt																													494,000,000
Remaining Proceeds From Issuance Of Debt																														234,000,000
Extinguishment of Debt, Amount																																260,000,000							250,000,000
Extinguishment of Debt, Interest Terms	LIBOR based rate plus a company specific spread,																																						0.05125
Line Of Credit Facility [Line Items]
Number of Credit Facilities	4											2				1
Line Of Credit Facility Maximum Borrowing Capacity	1,000,000,000				985,000,000	950,000,000	750,000,000	25,000,000	10,000,000	500,000,000				25,000,000	200,000,000	25,000,000	500,000,000
Line of Credit Facility, Term						5 years					364 days		3 years
Line Of Credit Facility Interest Rate Description						a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to two percent, based on the Company’s credit ratings		a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin	LIBOR-based rate plus 1.5 percent.	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							a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s borrowings under its committed line of credit facility plus 0.75 percent
Line Of Credit Facility Amount Outstanding						0		0	0	278,000,000							0
Line of Credit Facility, Current Available Borrowing Capacity						582,000,000					37,400,000
Line of Credit Facility, Maximum Borrowing Capacity with Accordion Feature						1,200,000,000												500,000,000
Debt Instrument, Covenant, Excess Debt Trigger			15,000,000	100,000,000
Long-term Debt, Other Disclosures [Abstract]
Authorized Commercial Paper	950,000,000
Commercial Paper	368,000,000	310,900,000
Commercial Paper Weighted Average Interest Rate	0.25%	0.48%
Debt Covenant, Total Debt To Total Capital Ratio	70.00%
Ratio of Total Debt to Total Capital	54.00%
Regulated Operations Letters of Credit Outstanding, Amount	5,900,000
Debt and Equity Securities Authorized for Issuance	1,750,000,000
Debt Instrument Covenant Compliance	We were in compliance with all of our debt covenants as of September 30, 2013
Debt And Equity Securities Available For Issuance	1,750,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
2014	0
2015	500,000,000
2016	0
2017	250,000,000
2018	0
Thereafter	1,710,000,000
Debt Instrument Carrying Amount	$ 2,460,000,000	$ 1,960,131,000																	$ 500,000,000	$ 500,000,000	$ 250,000,000	$ 250,000,000	$ 450,000,000	$ 450,000,000	$ 200,000,000	$ 200,000,000	$ 400,000,000	$ 400,000,000	$ 500,000,000	$ 500,000,000	$ 0		$ 10,000,000	$ 10,000,000	$ 150,000,000	$ 150,000,000	$ 0	$ 131,000

Financial Instruments Commodity Contract Volumes (Details)	Sep. 30, 2013 MMcf
Natural Gas Distribution Segment [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	29,185
Natural Gas Distribution Segment [Member] \| Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	29,185
Natural Gas Distribution Segment [Member] \| Fair Value Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	0
Natural Gas 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	93,845
Nonregulated Segment [Member] \| Not Designated as Hedging Instrument [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	75,683
Nonregulated Segment [Member] \| Fair Value Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	(13,033)
Nonregulated Segment [Member] \| Cash Flow Hedging [Member]
Commodity Contract Outstanding Volumes [Line Items]
Investment Contract Volume	31,195

Nature of Business (Details)	Sep. 30, 2013 regulated_gas_distributions_divisions customers
Schedule of Number of Customers, Discontinued Operations [Line Items]
Number Of Customers, Natural Gas Distribution	3,000,000
Number Of Divisions, Natural Gas Distribution	6
Georgia [Member]
Schedule of Number of Customers, Discontinued Operations [Line Items]
Number Of Customers, Natural Gas Distribution	64,000
Missouri, Illinois and Iowa [Member]
Schedule of Number of Customers, Discontinued Operations [Line Items]
Number Of Customers, Natural Gas Distribution	84,000

Leases (Details) (USD $)				12 Months Ended
Leases (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Maximum [Member]
Operating Leased Assets [Line Items]
Operating Lease, Term				1 year	21 years
Capital Leases of Lessee [Abstract]
Capital Leased Assets Gross	$ 1,300,000	$ 1,300,000
Capital Leases Accumulated Depreciation	1,000,000	900,000
Capital Leases, 2014	186,000
Capital Leases, 2015	186,000
Capital Leases, 2016	186,000
Capital Leases, 2017	186,000
Capital Leases, 2018	78,000
Capital Leases, thereafter	0
Total Capital Minimum Lease Payments	822,000
Capital Leases, less amount representing interest	198,000
Present value of net minimum lease payments	624,000
Operating Leases, 2014	16,722,000
Operating Leases, 2015	15,584,000
Operating Leases, 2016	14,692,000
Operating Leases, 2017	15,074,000
Operating Leases, 2018	15,057,000
Operating Leases, Thereafter	89,673,000
Total Operating Lease Payments	166,802,000
Lease and Rental Expense	$ 32,400,000	$ 33,600,000	$ 35,500,000

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Sep. 30, 2013	Nov. 08, 2013	Mar. 31, 2013
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock Shares Outstanding		90,912,251
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 3,816,801,052

Income Taxes (Details) (USD $)	3 Months Ended	12 Months Ended
Income Taxes (Details) (USD $)	Mar. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Current income taxes
Federal		$ 0	$ 631,000	$ (13,298,000)
State		8,178,000	6,888,000	6,841,000
Deferred income taxes
Federal		124,836,000	103,971,000	107,950,000
State		9,605,000	(13,237,000)	5,498,000
Investment tax credits		(20,000)	(27,000)	(172,000)
Income tax expense		142,599,000	98,226,000	106,819,000
Deferred tax assets
Accruals not currently deductible for tax purposes		11,496,000	7,906,000
Customer advances		4,279,000	4,721,000
Nonqualified benefit plans		52,051,000	48,513,000
Postretirement benefits		63,919,000	62,802,000
Treasury lock agreements		0	25,448,000
Unamortized investment tax credit		6,000	14,000
Tax net operating loss and credit carryforwards		206,996,000	164,419,000
Difference between book and tax on mark to market accounting		2,271,000	2,342,000
Other, net		0	7,223,000
Total deferred tax assets		341,018,000	323,388,000
Deferred tax liabilities
Difference in net book value and net tax value of assets		(1,445,450,000)	(1,254,698,000)
Pension funding		(23,480,000)	(32,812,000)
Gas Cost Adjustments		(19,182,000)	(21,806,000)
Interest rate agreements		(21,726,000)	0
Cost expensed for tax purposes and capitalized for book purposes		(2,815,000)	(2,065,000)
Other, net		(7,115,000)	0
Total deferred tax liabilities		(1,519,768,000)	(1,311,381,000)
Net deferred tax liabilities		(1,178,750,000)	(987,993,000)
Operating Loss Carryforwards [Line Items]
Liabilities associated with uncertain tax positions		3,200,000			6,700,000
Liability for Uncertain Tax Positions, Decrease due to Settlement	6,700,000
Settlement of uncertain tax positions				5,000,000
Deferred credits for rate regulated entities		(51,000)	140,000
Other Information Pertaining to Income Taxes		results for fiscal 2012 were favorably impacted by a state tax benefit of $13.6 million. Due to the completion of the sale of our Missouri, Iowa and Illinois service areas in the fiscal fourth quarter, the Company updated its analysis of the tax rate at which deferred taxes would reverse in the future to reflect the sale of these service areas. The updated analysis supported a reduction in the deferred tax rate which when applied to the balance of taxable income deferred to future periods resulted in a reduction of the Company’s overall deferred tax liability.
State tax benefit			13,600,000
Deferred Tax Assets, Valuation Allowance		1,100,000
Internal Revenue Service IRS [Member]
Operating Loss Carryforwards [Line Items]
Amount		185,300,000
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Amount		11,000,000
Federal Alternative Minimum Tax Credit Carryforward [Member]
Other Tax Carryforward [Line Items]
Amount		10,100,000
State Tax Credit Carryforward [Member]
Other Tax Carryforward [Line Items]
Amount		$ 600,000

Commitments and Contingencies (Details) (USD $)	0 Months Ended		12 Months Ended
Commitments and Contingencies (Details) (USD $)	Jan. 25, 2013	Dec. 09, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Loss Contingency Information About Litigation Matters [Abstract]
Loss Contingency, Compensatory Damages Awarded, Value	$ 10,000
Description of Pending Litigation			Since April 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate. Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases. During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries. A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals (Court), appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments were held in the case on August 27, 2012. In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed a response to the motion filed by the investors/working owners on March 27, 2013 and to the landowners’ motion on April 17, 2013. The decision of the Court of Appeals will not become final until the appellate process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have been engaged in discovery activities in this case.
Business License Tax [Abstract]
Business License Tax Examination, Description			Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. AEM has challenged the assessment of the business tax. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. The Company anticipates a decision by the Chancery Court on the remaining issues in fiscal 2014. AEM has been assessed $6.1 million in business taxes and $3.7 million in penalties and interest for the period from December 2002 through March 31, 2012. We have accrued what we believe to be an adequate amount for the anticipated resolution of this matter and we will continue to review and if appropriate adjust this reserve until this matter is resolved. We continue to believe the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.
Long Term Purchase Commitment [Abstract]
Significant Purchase Commitment Remaining Minimum Amount Committed Next Fiscal Year			230,500,000
Long Term Purchase Commitment [Line Items]
Significant Purchase Commitment Amount Description			1,246,100,000	978,800,000	1,498,600,000
Estimated Contractual Demand Fees [Abstract]
2014			12,662,000
2015			5,113,000
2016			743,000
2017			170,000
2018			142,000
Thereafter			356,000
Total Estimated Contractual Demand Fees			19,186,000
Loss Contingency, Settlement [Abstract]
Loss Contingency, Civil Penalty Paid to United States Treasury		6,400,000
Loss Contingency, Civil Penalty Paid to Energy Assistance Programs		$ 5,600,000
Inventories Under Indexed Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year			78.0
Long Term Purchase Commitment Minimum Quantity Required One To Three Years			21.9
Long Term Purchase Commitment Minimum Quantity Required After Three Years			1.0
Inventories Under Fixed Price Contracts [Member]
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Minimum Quantity Required Within One Year			6.1
Long Term Purchase Commitment Minimum Quantity Required One To Three Years			0.2
Purchase Commitment Amount Minimum			3.32
Purchase Commitment Amount Maximum			6.36