Edgar Filing: ATMOS ENERGY CORP

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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, 2011
		OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)


Texas and Virginia		75-1743247
(State or other jurisdiction of incorporation or organization)		(IRS employer identification no.)
Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas (Address of principal executive offices)		75240 (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 o

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 o 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 o

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 o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(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 o 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, 2011, was $3,008,806,271.

As of November 14, 2011, the registrant had 90,364,061 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 8, 2012, are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


			Page

Glossary of Key Terms				3

Part I
	Item 1.	Business		4
	Item 1A.	Risk Factors		22
	Item 1B.	Unresolved Staff Comments		27
	Item 2.	Properties		28
	Item 3.	Legal Proceedings		29

Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30
	Item 6.	Selected Financial Data		33
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		64
	Item 8.	Financial Statements and Supplementary Data		65
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		134
	Item 9A.	Controls and Procedures		134
	Item 9B.	Other Information		136

Part III
	Item 10.	Directors, Executive Officers and Corporate Governance		136
	Item 11.	Executive Compensation		137
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		137
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		137
	Item 14.	Principal Accountant Fees and Services		137

Part IV
	Item 15.	Exhibits and Financial Statement Schedules		137
EX-10.14
EX-12
EX-21
EX-23.1
EX-31
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation
AEH		Atmos Energy Holdings, Inc.
AEM		Atmos Energy Marketing, LLC
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
COSO		Committee of Sponsoring Organizations of the Treadway Commission
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
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
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
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
Settled Cities		Represents 439 of the 440 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.
SRF		Stable Rate Filing
WNA		Weather Normalization Adjustment

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, is engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as other nonregulated natural gas businesses. Since our incorporation in Texas in 1983, we have grown primarily through a series of acquisitions, the most recent of which was the acquisition in October 2004 of the natural gas distribution and pipeline operations of TXU Gas Company. We are also incorporated in the state of Virginia.

Today, we distribute natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in 12 states located primarily in the South, which makes us one of the country’s largest natural-gas-only distributors based on number of customers. In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 84,000 customers. After the closing of this transaction, we will operate in nine states. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.

Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers principally in the Midwest and Southeast and natural gas transportation along with storage services to certain of our natural gas distribution divisions and third parties.

Our overall strategy is to:


	•	deliver superior shareholder value,

	•	improve the quality and consistency of earnings growth, while safely operating our regulated and nonregulated businesses exceptionally well and

	•	enhance and strengthen a culture built on our core values.

We have continued to grow our earnings after giving effect to our acquisitions and have experienced more than 25 consecutive years of increasing dividends. Historically, we achieved this record of growth through acquisitions while efficiently managing our operating and maintenance expenses and leveraging our technology to achieve more efficient operations. In recent years, we have also 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.

Natural Gas Distribution Segment Overview

Our natural gas distribution segment consists of the following six regulated divisions, presented in order of total rate base, covering service areas in 12 states:


	•	Atmos Energy Mid-Tex Division,

	•	Atmos Energy Kentucky/Mid-States Division,

	•	Atmos Energy Louisiana Division,

	•	Atmos Energy West Texas Division,

	•	Atmos Energy Mississippi Division and

	•	Atmos Energy Colorado-Kansas Division

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.

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. Our primary service areas are located in Colorado, Kansas, Kentucky, Louisiana, Mississippi, Tennessee and Texas. We have more limited service areas in Georgia, Illinois, Iowa, Missouri and Virginia. See Note 6 in the consolidated financial statements for a complete description of the anticipated sale of our Illinois, Iowa and Missouri service areas. 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 utility 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 utilities 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.

Finally, regulatory authorities have approved weather normalization adjustments (WNA) for approximately 94 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 lower gas usage when weather is warmer than normal and decrease customers’ bills to offset higher gas usage when weather is colder than normal.

As of September 30, 2011 we had WNA for our residential and commercial meters in the following service areas for the following periods:


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

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 cost. Major suppliers during fiscal 2011 were Anadarko Energy Services, BP Energy Company, ConocoPhillips, Devon Gas Services, L.P., Enbridge Marketing (US) L.P., Iberdrola Renewables, Inc., National Fuel Marketing Company, LLC, ONEOK Energy Services Company L.P., Tenaska Marketing 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 2011 was on February 2, 2011, when sales to customers reached approximately 4.4 Bcf.

Currently, our natural gas distribution divisions, except for our Mid-Tex Division, utilize 45 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.

Below, we briefly describe our six natural gas distribution divisions. 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, 2011, we held 1,116 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. Additional information concerning our natural gas distribution divisions is presented under the caption “Operating Statistics”.

Atmos Energy Mid-Tex Division. Our Mid-Tex Division serves approximately 550 incorporated and unincorporated communities in the north-central, eastern and western parts of Texas, including the Dallas/Fort Worth Metroplex. The governing body of each municipality we serve has original jurisdiction over all gas distribution rates, operations and services within its city limits, except with respect to sales of natural gas for vehicle fuel and agricultural use. The Railroad Commission of Texas (RRC) has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality.

Prior to fiscal 2008, this division operated under one system-wide rate structure. However, in fiscal 2008, we reached a settlement with cities representing approximately 80 percent of this division’s customers (Settled Cities) that has allowed us, beginning in fiscal 2008, to update rates for customers in these cities through an annual rate review mechanism (RRM). Rates for the remaining 20 percent of this division’s customers, primarily the City of Dallas, continue to be 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. In June 2011, we reached an agreement with the City of Dallas to enter into the Dallas Annual Rate Review (DARR). This rate review provides for an annual rate review without the necessity of filing a general rate case. The first filing made under this mechanism will be in January 2012.

Atmos Energy Kentucky/Mid-States Division. Our Kentucky/Mid-States Division operates in more than 420 communities across Georgia, Illinois, Iowa, Kentucky, Missouri, Tennessee and Virginia. The service areas in these states are primarily rural; however, this division serves Franklin, Tennessee and other suburban areas of Nashville. We update our rates in this division through periodic formal rate filings made with each state’s public service commission.

In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa, representing approximately 189 communities, some of which of the Missouri communities are located in our Atmos Energy Colorado-Kansas Division.

Atmos Energy Louisiana Division. In Louisiana, we serve nearly 300 communities, including the suburban areas of New Orleans, the metropolitan area of Monroe and western Louisiana. Direct sales of natural gas to industrial customers in Louisiana, who use gas for fuel or in manufacturing processes, and sales of natural gas for vehicle fuel are exempt from regulation and are recognized in our nonregulated segment. Our rates in this division are updated annually through a rate stabilization clause filing without filing a formal rate case.

Atmos Energy West Texas Division. Our West Texas Division serves approximately 80 communities in West Texas, including the Amarillo, Lubbock and Midland areas. Like our Mid-Tex Division, each municipality we serve has original jurisdiction over all gas distribution rates, operations and services within its city limits, with the RRC having exclusive appellate jurisdiction over the municipalities and exclusive original jurisdiction over rates and services provided to customers not located within the limits of a municipality. Prior to fiscal 2008, rates were updated in this division through formal rate proceedings. However, the West Texas Division entered into agreements with its West Texas service areas during fiscal 2008 and its Amarillo and Lubbock service areas during fiscal 2009 to update rates for customers in these service areas through an RRM.

Atmos Energy Mississippi Division. In Mississippi, we serve about 110 communities throughout the northern half of the state, including the Jackson metropolitan area. Our rates in the Mississippi Division are updated annually through a stable rate filing without filing a formal rate case.

Atmos Energy Colorado-Kansas Division. Our Colorado-Kansas Division serves approximately 170 communities throughout Colorado and Kansas and parts of Missouri, including the cities of Olathe, Kansas, a suburb of Kansas City and Greeley, Colorado, located near Denver. We update our rates in this division through periodic formal rate filings made with each state’s public service commission.

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.


		Effective			Authorized	Authorized
		Date of Last		Rate Base	Rate of	Return
Division	Jurisdiction	Rate/GRIP Action		(thousands)⁽¹⁾	Return⁽¹⁾	on Equity⁽¹⁾

Atmos Pipeline — Texas	Texas		05/01/2011	$807,733	9.36%	11.80%
Atmos Pipeline — Texas — GRIP	Texas		08/01/2011	816,976	9.36%	11.80%
Colorado-Kansas	Colorado		01/04/2010	86,189	8.57%	10.25%
	Kansas		08/01/2010	144,583	(2)	(2)
Kentucky/Mid-States	Georgia		03/31/2010	96,330⁽³⁾	8.61%	10.70%
	Illinois		11/01/2000	24,564	9.18%	11.56%
	Iowa		03/01/2001	5,000	(2)	11.00%
	Kentucky		06/01/2010	208,702⁽⁴⁾	(2)	(2)
	Missouri		09/01/2010	66,459	(2)	(2)
	Tennessee		04/01/2009	190,100	8.24%	10.30%
	Virginia		11/23/2009	36,861	8.48%	9.50% - 10.50%
Louisiana	Trans LA		04/01/2011	93,260	8.37%	10.00% - 10.80%
	LGS		07/01/2011	273,775	8.56%	10.40%
Mid-Tex — Settled Cities	Texas		09/01/2011	1,389,187⁽⁵⁾	8.29%	9.70%
Mid-Tex — Dallas	Texas		06/22/2011	1,268,601⁽⁵⁾	8.45%	10.10%
Mid-Tex — Environs GRIP	Texas		06/27/2011	1,268,601⁽⁵⁾	8.60%	10.40%
Mississippi	Mississippi		04/05/2011	239,197	(2)	9.86%
West Texas	Amarillo		08/01/2011	(2)	(2)	9.60%
	Lubbock		09/09/2011	60,892	8.19%	9.60%
	West Texas		08/01/2011	146,039	8.19%	9.60%

Authorized Debt/

Bad Debt

Performance-Based

Customer

Division

Jurisdiction

Equity Ratio

Rider⁽⁶⁾

WNA

Rate Program⁽⁷⁾

Meters

Atmos Pipeline — Texas

Texas

50/50

N/A

Colorado-Kansas

Colorado

50/50

Yes

⁽⁸⁾

110,709

Kansas

(2)

Yes

128,679

Kentucky/Mid-States

Georgia

52/48

Yes

63,897

Illinois

67/33

22,778

Iowa

57/43

4,334

Kentucky

(2)

Yes

176,246

Missouri

49/51

56,643

Tennessee

52/48

Yes

133,634

Virginia

51/49

Yes

23,310

Louisiana

Trans LA

52/48

Yes

75,813

LGS

52/48

Yes

277,838

Mid-Tex — Settled Cities

Texas

50/50

Yes

1,259,042

Mid-Tex — Dallas & Environs

Texas

51/49

Yes

314,760

Mississippi

50/50

Yes

266,074

West Texas

Amarillo

52/48

Yes

70,431

Lubbock

52/48

Yes

73,748

West Texas

52/48

Yes

155,255


⁽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⁾		Georgia rate base consists of $60.2 million included in the March 2010 rate case and $36.1 million included in the October 2011 Pipeline Replacement Program (PRP) surcharge. A total of $36.1 million of the Georgia rate base amount was awarded in the latest PRP annual filing with an effective date of October 1, 2011, an authorized rate of return of 8.56 percent and an authorized return on equity of 10.70 percent.

⁽⁴⁾		Kentucky rate base consists of $184.7 million included in the June 2010 rate case and $24.0 million included in the October 2011 PRP surcharge. A total of $24.0 million of the Kentucky rate base amount was awarded in the latest PRP annual filing with an effective date of October 1, 2011, an authorized rate of return of 8.74 percent and an authorized return on equity of 10.50 percent.

⁽⁵⁾		The Mid-Tex Rate Base amounts for the Settled Cities and Dallas & Environs areas represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.

⁽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 utility companies to minimize purchased gas costs by allowing the utility company and its customers to share the purchased gas costs savings.

⁽⁸⁾		The recovery of the gas portion of uncollectible accounts gas cost adjustment has been approved for a two-year pilot program.

Natural Gas Distribution Sales and Statistical Data - Continuing Operations


	Fiscal Year Ended September 30
	2011		2010		2009		2008		2007

METERS IN SERVICE, end of year
Residential		2,855,998		2,836,483		2,826,814		2,834,884		2,815,974
Commercial		261,220		253,339		256,384		259,154		262,260
Industrial		2,008		2,029		2,136		2,183		2,281
Public authority and other		10,212		10,178		9,211		9,197		19,143

Total meters		3,129,438		3,102,029		3,094,545		3,105,418		3,099,658

SALES VOLUMES — MMcf⁽²⁾
Gas Sales Volumes
Residential		161,012		185,143		154,475		157,816		161,493
Commercial		91,215		99,924		88,445		90,992		92,601
Industrial		18,757		18,714		18,242		21,352		22,479
Public authority and other		10,482		10,107		12,393		13,739		12,265

Total gas sales volumes		281,466		313,888		273,555		283,899		288,838
Transportation volumes		132,357		128,965		123,972		133,997		127,066

Total throughput		413,823		442,853		397,527		417,896		415,904

OPERATING REVENUES (000’s)⁽²⁾
Gas Sales Revenues
Residential	$	1,570,723	$	1,784,051	$	1,768,082	$	2,068,040	$	1,924,523
Commercial		698,366		787,433		807,109		1,044,768		941,827
Industrial		106,569		110,280		132,487		208,681		190,812
Public authority and other		69,176		70,402		88,972		137,585		114,087

Total gas sales revenues		2,444,834		2,752,166		2,796,650		3,459,074		3,171,249
Transportation revenues		60,430		59,381		56,961		57,405		56,814
Other gas revenues		26,599		31,091		31,185		35,183		35,448

Total operating revenues	$	2,531,863	$	2,842,638	$	2,884,796	$	3,551,662	$	3,263,511

Natural Gas Distribution Sales and Statistical Data - Discontinued Operations


	Fiscal Year Ended September 30
	2011		2010		2009		2008		2007

Meters in service, end of period		83,753		84,011		84,299		86,361		87,469
Sales volumes — MMcf
Total gas sales volumes		8,461		8,740		8,562		8,777		8,489
Transportation volumes		6,190		6,900		6,719		7,086		8,043

Total throughput		14,651		15,640		15,281		15,863		16,532

Operating revenues (000’s)	$	80,028	$	69,855	$	99,969	$	103,468	$	95,254

See footnotes following these tables.

Natural Gas Distribution Sales and Statistical Data - Other Consolidated Statistics


	Fiscal Year Ended September 30
	2011			2010			2009			2008			2007

Inventory storage balance — Bcf		55.0			54.3			57.0			58.3			58.0
Heating degree days⁽¹⁾
Actual (weighted average)		2,733			2,780			2,713			2,820			2,879
Percent of normal		99	%		102	%		100	%		100	%		100	%
Average transportation revenue per Mcf	$	0.46		$	0.46		$	0.46		$	0.43		$	0.44
Average cost of gas per Mcf sold	$	5.30		$	5.77		$	6.95		$	9.05		$	8.09
Employees		4,753			4,714			4,691			4,558			4,472

Natural Gas Distribution Sales and Statistical Data by Division


	Fiscal Year Ended September 30, 2011
				Kentucky/						West						Colorado-
	Mid-Tex			Mid-States			Louisiana			Texas			Mississippi			Kansas			Other⁽³⁾			Total

METERS IN SERVICE FROM CONTINUING OPERATIONS
Residential		1,449,673			349,993			331,272			271,346			237,059			216,655			—			2,855,998
Commercial		123,993			43,875			22,379			24,773			25,617			20,583			—			261,220
Industrial		136			798			—			482			501			91			—			2,008
Public authority and other		—			2,423			—			2,833			2,897			2,059			—			10,212

Total meters		1,573,802			397,089			353,651			299,434			266,074			239,388			—			3,129,438

SALES VOLUMES FROM CONTINUING OPERATIONS — MMcf⁽²⁾
Gas Sales Volumes
Residential		77,075			22,273			13,939			16,280			14,077			17,368			—			161,012
Commercial		50,056			13,407			7,448			6,932			6,630			6,742			—			91,215
Industrial		3,105			5,626			—			4,108			5,823			95			—			18,757
Public authority and other		—			1,395			—			3,294			3,418			2,375			—			10,482

Total		130,236			42,701			21,387			30,614			29,948			26,580			—			281,466
Transportation volumes		46,594			38,801			5,893			24,162			5,237			11,670			—			132,357

Total throughput		176,830			81,502			27,280			54,776			35,185			38,250			—			413,823

OPERATING MARGIN FROM CONTINUING OPERATIONS (000’s)⁽²⁾	$	490,484		$	152,293		$	125,894		$	99,353		$	93,042		$	83,298		$	—		$	1,044,364
OPERATING EXPENSES FROM CONTINUING OPERATIONS (000’s)⁽²⁾
Operation and maintenance	$	147,967		$	58,315		$	42,219		$	35,908		$	39,895		$	31,684		$	(7,905	)	$	348,083
Depreciation and amortization	$	95,798		$	29,644		$	24,460		$	16,735		$	13,188		$	17,084		$	—		$	196,909
Taxes, other than income	$	102,515		$	10,828		$	8,773		$	17,024		$	13,621		$	8,610		$	—		$	161,371
OPERATING INCOME FROM CONTINUING OPERATIONS (000’s)⁽²⁾	$	144,204		$	53,506		$	50,442		$	29,686		$	26,338		$	25,920		$	7,905		$	338,001
CONSOLIDATED CAPITAL EXPENDITURES (000’s)	$	220,032		$	65,766		$	41,489		$	40,387		$	37,115		$	31,399		$	60,711		$	496,899
PROPERTY, PLANT AND EQUIPMENT, EXCLUDING ASSETS HELD FOR SALE (000’s)	$	1,965,351		$	663,837		$	431,773		$	393,545		$	308,891		$	311,013		$	173,788		$	4,248,198
OTHER CONSOLIDATED STATISTICS
Heating Degree Days⁽¹⁾
Actual		2,100			3,920			1,431			3,541			2,707			5,692			—			2,733
Percent of normal		100	%		99	%		94	%		99	%		101	%		101	%		—			99	%
Miles of pipe		29,296			12,215			8,333			7,712			6,563			6,750			—			70,869
Employees		1,668			568			438			351			363			287			1,078			4,753

See footnotes following these tables.


	Fiscal Year Ended September 30, 2010
				Kentucky/						West						Colorado-
	Mid-Tex			Mid-States			Louisiana			Texas			Mississippi			Kansas			Other⁽³⁾			Total

METERS IN SERVICE FROM CONTINUING OPERATIONS
Residential		1,429,287			350,238			331,784			271,418			237,304			216,452			—			2,836,483
Commercial		116,240			43,554			22,420			24,919			25,520			20,686			—			253,339
Industrial		145			801			—			484			513			86			—			2,029
Public authority and other		—			2,411			—			2,809			2,896			2,062			—			10,178

Total meters		1,545,672			397,004			354,204			299,630			266,233			239,286			—			3,102,029

SALES VOLUMES FROM CONTINUING OPERATIONS — MMcf⁽²⁾
Gas Sales Volumes
Residential		92,489			22,897			15,810			19,772			15,775			18,400			—			185,143
Commercial		55,916			13,948			7,821			7,892			7,209			7,138			—			99,924
Industrial		3,227			5,615			—			4,317			5,424			131			—			18,714
Public authority and other		—			1,422			—			3,482			3,103			2,100			—			10,107

Total		151,632			43,882			23,631			35,463			31,511			27,769			—			313,888
Transportation volumes		45,822			36,882			5,626			22,429			5,551			12,655			—			128,965

Total throughput		197,454			80,764			29,257			57,892			37,062			40,424			—			442,853

OPERATING MARGIN FROM CONTINUING OPERATIONS (000’s)⁽²⁾	$	475,852		$	143,347		$	123,344		$	105,476		$	94,203		$	79,789		$	—		$	1,022,011
OPERATING EXPENSES FROM CONTINUING OPERATIONS (000’s)⁽²⁾
Operation and maintenance	$	145,166		$	56,481		$	43,604		$	36,696		$	41,542		$	30,892		$	976		$	355,357
Depreciation and amortization	$	89,411		$	28,066		$	22,986		$	15,881		$	12,621		$	16,182		$	—		$	185,147
Taxes, other than income	$	106,620		$	12,562		$	10,995		$	19,390		$	13,599		$	8,172		$	—		$	171,338
OPERATING INCOME FROM CONTINUING OPERATIONS (000’s)⁽²⁾	$	134,655		$	46,238		$	45,759		$	33,509		$	26,441		$	24,543		$	(976	)	$	310,169
CONSOLIDATED CAPITAL EXPENDITURES (000’s)	$	196,109		$	62,808		$	47,193		$	39,387		$	28,538		$	29,792		$	33,988		$	437,815
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (000’s)	$	1,761,087		$	750,225		$	413,189		$	319,053		$	284,195		$	300,380		$	130,983		$	3,959,112
OTHER CONSOLIDATED STATISTICS
Heating Degree Days⁽¹⁾
Actual		2,100			3,924			1,532			3,537			2,734			5,909			—			2,780
Percent of normal		103	%		100	%		96	%		99	%		102	%		106	%		—			102	%
Miles of pipe		29,156			12,196			8,381			7,666			6,546			7,175			—			71,120
Employees		1,650			587			439			344			371			284			1,039			4,714

Natural Gas Distribution Sales and Statistical Data by Division - Discontinued Operations


	Fiscal Year Ended September 30, 2011						Fiscal Year Ended September 30, 2010
	Kentucky/		Colorado-				Kentucky/		Colorado-
	Mid-States		Kansas		Total		Mid-States		Kansas		Total

Meters in service, end of period		83,325		428		83,753		83,577		434		84,011
Sales volumes — MMcf
Total gas sales volumes		7,963		498		8,461		8,251		489		8,740
Transportation volumes		6,190		—		6,190		6,900		—		6,900

Total throughput		14,153		498		14,651		15,151		489		15,640

Operating income (000’s)	$	13,395	$	1,020	$	14,415	$	11,628	$	657	$	12,285

Notes to preceding tables:


⁽¹⁾		A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days.


		Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on National Weather Service data for selected locations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.

⁽²⁾		Sales volumes, revenues, operating margins, operating expense and operating income reflect segment operations, including intercompany sales and transportation amounts.

⁽³⁾		The Other column represents our shared services function, which provides administrative and other support to the Company. Certain costs incurred by this function are not allocated.

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. 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 in the pipeline industry including parking and lending arrangements and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands. 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.

These operations include 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. Nine basins located in Texas are believed to contain a substantial portion of the nation’s remaining onshore natural gas reserves. This pipeline system provides access to all of these basins.

Regulated Transmission and Storage Sales and Statistical Data


	Fiscal Year Ended September 30
	2011		2010		2009		2008		2007

CUSTOMERS, end of year
Industrial		71		65		68		62		65
Other		156		176		168		189		196

Total		227		241		236		251		261

PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾		620,904		634,885		706,132		782,876		699,006
OPERATING REVENUES (000’s)⁽¹⁾	$	219,373	$	203,013	$	209,658	$	195,917	$	163,229
Employees, at year end		64		62		62		60		54


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

Nonregulated Segment Overview

Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.

AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. In addition, AEH utilizes proprietary and customer-owned transportation and storage assets to provide various delivered gas services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, AEH’s gas delivery and related services margins arise from the types of commercial transactions we have structured with our customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.

AEH’s storage and transportation margins arise from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during peak periods.

AEH also seeks to enhance its gross profit margin by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity it owns or controls in our natural gas distribution and by its subsidiaries. We attempt to meet these objectives by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEH has access and selling financial instruments at advantageous prices to lock in a gross profit margin. Certain of these arrangements are with regulatory affiliates, which have been approved by applicable state regulatory commissions.

Due to the nature of these operations, natural gas prices and differences in natural gas prices between the various markets that we serve (commonly referred to as basis differentials) have a significant impact on our nonregulated businesses. Within our delivered gas activities, basis differentials impact our ability to create value from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Further, higher natural gas prices 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. Higher gas prices, as well as competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher natural gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.

Volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility often has a significant impact on the spreads between the market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. Volatility could also impact the basis differentials we capture in our delivered gas activities. However, increased 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.

Nonregulated Sales and Statistical Data


	Fiscal Year Ended September 30
	2011		2010		2009		2008		2007

CUSTOMERS, end of year
Industrial		697		652		631		624		677
Municipal		65		61		63		55		68
Other		362		339		321		312		281

Total		1,124		1,052		1,015		991		1,026

INVENTORY STORAGE BALANCE — Bcf		15.7		17.9		19.9		12.4		21.3
NONREGULATED DELIVERED GAS SALES VOLUMES — MMcf⁽¹⁾		446,903		420,203		441,081		457,952		423,895
OPERATING REVENUES (000’s)⁽¹⁾	$	2,024,893	$	2,146,658	$	2,283,988	$	4,117,299	$	2,901,879


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

Ratemaking Activity

Overview

The method of determining regulated rates varies among the states in which our natural gas distribution divisions 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. Atmos Energy has annual ratemaking mechanisms in place in three states that provide for an annual rate review and adjustment to rates for approximately 73 percent of our gross margin. We also have accelerated recovery of capital for approximately 11 percent of our gross margin. Combined, we have rate structures with accelerated recovery of all or a portion of our expenditures for approximately 84 percent of our gross margin. Additionally, we have WNA mechanisms in eight states that serve to minimize the effects of weather on approximately 94 percent of our gross margin. Finally, we have the ability to recover the gas cost portion of bad debts for approximately 73 percent of our gross margin. These mechanisms work in tandem to provide substantial insulation from volatile margins, both for the Company and our customers.

We will also continue to address various rate design changes, including the recovery of bad debt gas costs and inclusion of other taxes in gas costs in future rate filings. These design changes would address cost variations that are related to pass-through energy costs beyond our control.

Although substantial progress has been made in recent years by improving rate design across Atmos Energy’s operating areas, 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 natural gas distribution revenues in the fiscal years ended September 30, 2011, 2010 and 2009 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 $72.4 million, $56.8 million and $54.4 million, became effective in fiscal 2011, 2010 and 2009 as summarized below:


	Annual Increase to Operating
	Income For the Fiscal Year Ended September 30
Rate Action	2011		2010		2009
	(In thousands)

Rate case filings	$	20,502	$	23,663	$	2,959
Infrastructure programs		15,033		18,989		12,049
Annual rate filing mechanisms		35,216		13,757		38,764
Other ratemaking activity		1,675		392		631

	$	72,426	$	56,801	$	54,403

Additionally, the following ratemaking efforts were initiated during fiscal 2011 but had not been completed as of September 30, 2011:


			Operating Income
Division	Rate Action	Jurisdiction	Requested
			(In thousands)

Kentucky/Mid-States	PRP⁽¹⁾⁽²⁾	Georgia	$	1,192
	PRP⁽¹⁾⁽³⁾	Kentucky		2,529
Mississippi	Stable Rate Filing	Mississippi		5,303
West Texas & Lubbock Environs	Rate Case⁽⁴⁾	Railroad Commission of Texas (RRC)		545

			$	9,569


⁽¹⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽²⁾		The Georgia Commission issued a final order on October 5, 2011 approving a $1.2 million increase to operating income.

⁽³⁾		The Kentucky Commission approved an increase of $2.5 million effective October 1, 2011.

⁽⁴⁾		On September 30, 2011 the Company and Commission Staff signed a settlement and submitted to the Commission for their approval.

Our recent ratemaking activity is discussed in greater detail below.

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:


		Increase in Annual
Division	State	Operating Income		Effective Date
		(In thousands)

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

2010 Rate Case Filings:
Kentucky/Mid-States	Missouri	$	3,977		09/01/2010
Colorado-Kansas	Kansas		3,855		08/01/2010
Kentucky/Mid-States	Kentucky		6,636		06/01/2010
Kentucky/Mid-States	Georgia		2,935		03/31/2010
Mid-Tex	Texas⁽¹⁾		2,963		01/26/2010
Colorado-Kansas	Colorado		1,900		01/04/2010
Kentucky/Mid-States	Virginia		1,397		11/23/2009

Total 2010 Rate Case Filings		$	23,663

2009 Rate Case Filings:
Kentucky/Mid-States	Tennessee	$	2,513		04/01/2009
West Texas	Texas		446		Various

Total 2009 Rate Case Filings		$	2,959


⁽¹⁾		In its final order, the RRC approved a $3.0 million increase in operating income from customers in the Dallas & Environs portion of the Mid-Tex Division. Operating income should increase $0.2 million, net of the GRIP 2008 rates that will be superseded. The ruling also provided for regulatory accounting treatment for certain costs related to storage assets and costs moving from our Mid-Tex Division within our natural gas distribution segment to our regulated transmission and storage segment.

Infrastructure Programs

As discussed above in “Natural Gas Distribution Segment Overview,” infrastructure programs such as GRIP allow natural gas distribution companies 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, Georgia, Missouri and Kentucky. The following table summarizes our infrastructure program filings with effective dates during the fiscal years ended September 30, 2011, 2010 and 2009:


				Increase in
		Incremental Net		Annual
		Utility Plant		Operating		Effective
Division	Period End	Investment		Income		Date
		(In thousands)		(In thousands)

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 ⁽¹⁾	09/2011		3,329		468	06/01/2011
Kentucky/Mid-States-Missouri⁽²⁾	09/2010		2,367		277	02/14/2011
Kentucky/Mid-States-Georgia⁽¹⁾	09/2009		5,359		764	10/01/2010

Total 2011 Infrastructure Programs		$	209,552	$	15,033

2010 Infrastructure Programs:
Mid-Tex⁽³⁾	12/2009	$	16,957	$	2,983	09/01/2010
West Texas	12/2009		19,158		363	06/14/2010
Atmos Pipeline — Texas	12/2009		95,504		13,405	04/20/2010
Kentucky/Mid-States-Missouri⁽²⁾	06/2009		3,578		563	03/02/2010
Colorado-Kansas-Kansas⁽⁴⁾	08/2009		6,917		766	12/12/2009
Kentucky/Mid-States-Georgia⁽¹⁾	09/2008		6,327		909	10/01/2009

Total 2010 Infrastructure Programs		$	148,441	$	18,989

2009 Infrastructure Programs:
Mid-Tex⁽⁵⁾	12/2008	$	105,777	$	2,732	09/09/2009
Atmos Pipeline — Texas	12/2008		51,308		6,342	04/28/2009
Mid-Tex⁽³⁾	12/2007		57,385		1,837	01/26/2009
Kentucky/Mid-States-Missouri⁽²⁾	03/2008		3,367		408	11/04/2008
Kentucky/Mid-States-Georgia⁽¹⁾	09/2007		748		198	10/01/2008
West Texas⁽⁶⁾	2007/08		27,425		532	Various

Total 2009 Infrastructure Programs		$	246,010	$	12,049


⁽¹⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽²⁾		Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

⁽³⁾		Increase relates to the City of Dallas and Environs areas of the Mid-Tex Division.

⁽⁴⁾		Gas System Reliability Surcharge (GSRS) relates to safety related investments made since the previous rate case.

⁽⁵⁾		Increase relates only to the City of Dallas area of the Mid-Tex Division.

⁽⁶⁾		The West Texas Division files GRIP applications related only to the Lubbock Environs and the West Texas Cities Environs. GRIP implemented for this division include investments that related to both calendar years 2007 and 2008. The incremental investment is based on system-wide plant and additional annual operating revenue is applicable to environs customers only.

Annual Rate Filing Mechanisms

As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. As discussed above in “Natural Gas Distribution Segment Overview,” we currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in significant portions of our Mid-Tex and West Texas divisions. These mechanisms are referred to as rate review mechanisms in our Mid-Tex and West Texas divisions, 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:

Increase

(Decrease) in

Annual

Operating

Effective

Division

Jurisdiction

Test Year Ended

Income

Date

(In thousands)

2011 Filings:

Mid-Tex

Settled 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

09/30/2010

350

04/01/2011

Mid-Tex

Settled Cities

12/31/2009

23,122

10/01/2010

Total 2011 Filings

35,216

2010 Filings:

West Texas

Lubbock

12/31/2009

(902

)

09/01/2010

West Texas

WT Cities

12/31/2009

700

08/15/2010

West Texas

Amarillo

12/31/2009

1,200

08/01/2010

Louisiana

LGS

12/31/2009

3,854

07/01/2010

Louisiana

TransLa

09/30/2009

1,733

04/01/2010

Mississippi

06/30/2009

3,183

12/15/2009

West Texas

Lubbock

12/31/2008

2,704

10/01/2009

West Texas

Amarillo

12/31/2008

1,285

10/01/2009

Total 2010 Filings

13,757

2009 Filings:

Mid-Tex

Settled Cities

12/31/2008

1,979

08/01/2009

West Texas

WT Cities

12/31/2008

6,599

08/01/2009

Louisiana

LGS

12/31/2008

3,307

07/01/2009

Louisiana

TransLa

09/30/2008

611

04/01/2009

Mississippi

06/30/2008

—

N/A

Mid-Tex

Settled Cities

12/31/2007

21,800

11/08/2008

West Texas

WT Cities

12/31/2007

4,468

11/20/2008

Total 2009 Filings

38,764

In June 2011, we reached an agreement with the City of Dallas to enter into the DARR. This rate review provides for an annual rate review without the necessity of filing a general rate case. The first filing made under this mechanism will be in January 2012.

In August 2010, we reached an agreement to extend the RRM in our Mid-Tex Division for an additional two-year period beginning October 1, 2010; however, the Mid-Tex Division will be required to file a general system-wide rate case on or before June 1, 2013. This extension provides for an annual rate adjustment to reflect changes in the Mid-Tex Division’s costs of service and additions to capital investment from year to year, without the necessity of filing a general rate case.

The settlement also allows us to expand our existing program to replace steel service lines in the Mid-Tex Division’s natural gas delivery system. On October 13, 2010, the City of Dallas approved the recovery of the return, depreciation and taxes associated with the replacement of 100,000 steel service lines across the Mid-Tex Division by September 30, 2012. The RRM in the Mid-Tex Division was entered into as a result of a settlement in the September 20, 2007 Statement of Intent case filed with all Mid-Tex Division cities. Of the 440 incorporated cities served by the Mid-Tex Division, 439 of these cities are part of the RRM process.

The West Texas RRM was entered into in August 2008 as a result of a settlement with the West Texas Coalition of Cities. The Lubbock and Amarillo RRMs were entered into in the spring of 2009. The West Texas Coalition of Cities agreed to extend its RRM for one additional cycle as part of the settlement of this fiscal year’s filing.

During fiscal 2011, the RRC’s Division of Public Safety issued a new rule requiring natural gas distribution companies 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 expense associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses.

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2011, 2010 and 2009:


			Increase in
			Annual
			Operating		Effective
Division	Jurisdiction	Rate Activity	Income		Date
			(In thousands)

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

2010 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	$	392	01/05/2010

Total 2010 Other Rate Activity			$	392

2009 Other Rate Activity:
Colorado-Kansas	Kansas	Tax Surcharge⁽³⁾	$	631	02/01/2009

Total 2009 Other Rate Activity			$	631


⁽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.

⁽³⁾		In the state of Kansas, the tax surcharge represents a true-up of ad valorem taxes paid versus what is designed to be recovered through base rates.

Other Regulation

Each of our natural gas distribution divisions 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 gas distribution facilities. In addition, our distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time we receive inquiries regarding various environmental matters. We believe that our properties and operations substantially comply with, and are operated in substantial conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. Our environmental claims have arisen primarily from former manufactured gas plant sites in Tennessee, Iowa and Missouri.

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, as well as 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, 2011, we had 4,949 employees, consisting of 4,817 employees in our regulated operations and 132 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 2011, Kim R. Cocklin, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on the Corporate Governance page of our website. We will also provide copies of all corporate governance documents free of charge upon request to Shareholder Relations at the address listed above.


ITEM 1A.	*Risk Factors.*

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

Further disruptions in the credit markets could limit our ability to access capital and increase our costs of capital.

We rely upon access to both short-term and long-term credit markets to satisfy our liquidity requirements. The global credit markets have experienced significant disruptions and volatility during the last few years to a greater degree than has been seen in decades. In some cases, the ability or willingness of traditional sources of capital to provide financing has been reduced.

Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation, Moody’s Investors Services, Inc. and Fitch Ratings, Ltd. If adverse credit conditions were to cause a significant limitation on our access to the private and public credit 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 public and/or private credit markets and increase the costs of borrowing under each source of credit.

Further, if our credit ratings were downgraded, we could be required to provide additional liquidity to our nonregulated segment because the commodity financial instruments markets could become unavailable to us. Our nonregulated segment depends primarily upon a committed credit facility to finance its working capital needs, which it uses primarily to issue standby letters of credit to its natural gas suppliers. A significant reduction in the availability of this facility could require us to provide extra liquidity to support its operations or reduce some of the activities of our nonregulated segment. Our ability to provide extra liquidity is limited by the terms of our existing lending arrangements with AEH, which are 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 further deterioration of current conditions in the credit markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.

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 few 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 improving current economic conditions, including the 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.

The costs of providing pension and postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results. In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of the health care benefits for our employees.

We provide a cash-balance pension plan and postretirement healthcare benefits to eligible full-time employees. Our costs of providing such benefits and related funding requirements are subject to changes in the market value of the assets funding our pension and postretirement healthcare plans. The fluctuations over the last few years in the values of investments that fund our pension and postretirement healthcare plans may significantly differ from or alter the values and actuarial assumptions we use to calculate our future pension plan expense and postretirement healthcare costs and funding requirements under the Pension Protection Act. Any significant declines in the value of these investments could increase the expenses of our pension and postretirement healthcare plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to 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, as well as various actuarial calculations and assumptions, which may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates and interest rates and other factors. Also, our costs of providing such benefits are subject to the continuing recovery of these costs through rates.

In addition, the costs of providing health care benefits to our employees could significantly increase over the next five to ten years. Although the full effects of the Health Care Reform Act should not impact the Company until 2014, the future cost of compliance with the provisions of this legislation is difficult to measure at this time.

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

Our risk management operations are subject to market risks beyond our control, including market liquidity, commodity price volatility caused by market supply and demand dynamics and counterparty creditworthiness. Although we maintain a risk management policy, we may not be able to completely offset the price risk associated with volatile gas prices, particularly in our nonregulated business segments, which could lead to volatility in our earnings.

Physical trading in our nonregulated business segments also introduces price risk on any net open positions at the end of each trading day, as well as volatility resulting from intra-day fluctuations of gas prices and the potential for daily price movements between the time natural gas is purchased or sold for future delivery and the time the related purchase or sale is hedged. 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. Although we manage our business to maintain no open positions, there are times when limited net open positions related to our physical storage 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.

Further, the timing of the recognition for financial accounting purposes of gains or losses resulting from changes in the fair value of derivative financial instruments designated as hedges usually does not match the timing of the economic profits or losses on the item being hedged. This volatility may occur with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated. Also, if the local physical markets in which we trade 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.

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.

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

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 various regulated returns on our rate base in each jurisdiction in which we operate. We monitor the allowed rates of return and our effectiveness in earning such rates and initiate rate proceedings or operating changes as we believe they are needed. In addition, in the normal course of business in the regulatory environment, assets may be placed in service and historical test periods established before rate cases can be filed that could result in an adjustment of our allowed returns. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we must 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.” Rate cases also involve a risk of rate reduction, because once rates have been approved, they are still subject to challenge for their reasonableness by appropriate regulatory authorities. In addition, regulators may review our purchases of natural gas and can adjust the amount of our gas costs that we pass through to our customers. Finally, our debt and equity financings are also subject to approval by regulatory commissions in several states, which could limit our ability to access or take advantage of rapid changes in the capital markets.

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 76,000 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 12 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 recent unfortunate pipeline incident in California, we anticipate companies in the natural gas distribution business may be subjected to even greater federal, state and local oversight of the safety of their operations in the future. Although we believe these costs are ultimately recoverable through our rates, 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 that affects 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. Under legislation passed by Congress in 2005, 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. We are currently under investigation by FERC for possible violations of its posting and competitive bidding regulations for pre-arranged released firm capacity on interstate natural gas pipelines. Should FERC conclude that we have committed such violations of its regulations and levies substantial fines and/or penalties against us, our business, financial condition or financial results could be adversely affected. 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 legal requirements 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 new federal and state legislative and regulatory initiatives proposed in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. For example, in June 2009, the U.S. House of Representatives approved The American Clean Energy and Security Act of 2009, also known as the Waxman-Markey bill or “cap and trade” bill. However, neither this bill nor a related bill in the U.S. Senate, the Clean Energy and Emissions Power Act was passed by Congress. 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.

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.

Adverse weather conditions could affect our operations or financial results.

Since the 2006-2007 winter heating season, we have had weather-normalized rates for over 90 percent of our residential and commercial meters, which has substantially mitigated 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.

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.

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 during the next fiscal year in executing our steel service line replacement program in the Mid-Tex Division. 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.

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. 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.

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

Our natural gas distribution business involves a number of hazards and operating risks that cannot be completely avoided, such as leaks, accidents and operational problems, which could cause loss of human life, as well as substantial financial losses resulting from property damage, damage to the environment and to our operations. We do have liability and property insurance coverage in place for many of these hazards and risks. However, because 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.

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, 2011, our natural gas distribution segment owned an aggregate of 70,869 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. Our regulated transmission and storage segment owned 5,861 miles of gas transmission and gathering lines and our nonregulated segment owned 105 miles of gas transmission and gathering lines.

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, 2011:


							Maximum
			Cushion		Total		Daily Delivery
	Usable Capacity		Gas		Capacity		Capability
State	(Mcf)		(Mcf)⁽¹⁾		(Mcf)		(Mcf)

Natural Gas Distribution Segment
Kentucky		4,442,696		6,322,283		10,764,979		109,100
Kansas		3,239,000		2,300,000		5,539,000		45,000
Mississippi		2,211,894		2,442,917		4,654,811		48,000
Georgia		490,000		10,000		500,000		30,000

Total		10,383,590		11,075,200		21,458,790		232,100
Regulated Transmission and Storage Segment — Texas		46,143,226		15,878,025		62,021,251		1,235,000
Nonregulated Segment
Kentucky		3,492,900		3,295,000		6,787,900		71,000
Louisiana		438,583		300,973		739,556		56,000

Total		3,931,483		3,595,973		7,527,456		127,000

Total		60,458,299		30,549,198		91,007,497		1,594,100


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

Additionally, we contract for storage service in underground storage facilities on many of the interstate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2011:


				Maximum
		Maximum		Daily
		Storage		Withdrawal
		Quantity		Quantity
Segment	Division/Company	(MMBtu)		(MDWQ)⁽¹⁾

Natural Gas Distribution Segment⁽²⁾
	Colorado-Kansas Division		4,243,909		108,039
	Kentucky/Mid-States Division		16,835,380		444,339
	Louisiana Division		2,643,192		161,473
	Mississippi Division		3,875,429		165,402
	West Texas Division		2,375,000		81,000

Total			29,972,910		960,253
Nonregulated Segment
	Atmos Energy Marketing, LLC		8,026,869		250,937
	Trans Louisiana Gas Pipeline, Inc.		1,674,000		67,507

Total			9,700,869		318,444

Total Contracted Storage Capacity			39,673,779		1,278,697


⁽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.

⁽²⁾		On October 1, 2011, our Mid-Tex Division signed a new storage contract with a maximum storage quantity of 500,000 MMBtu and maximum daily withdrawal quantity of 50,000 MMBtu.

Offices

Our administrative offices and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our distribution system, 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 13 to the consolidated financial statements.

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 2011 and 2010 are listed below. The high and low prices listed are the closing NYSE quotes, as reported on the NYSE composite tape, for shares of our common stock:


	Fiscal 2011						Fiscal 2010
					Dividends						Dividends
	High		Low		Paid		High		Low		Paid

Quarter ended:
December 31	$	31.72	$	29.10	$	.340	$	30.06	$	27.39	$	.335
March 31		34.98		31.51		.340		29.52		26.52		.335
June 30		34.94		31.34		.340		29.98		26.41		.335
September 30		34.32		28.87		.340		29.81		26.82		.335

					$	1.36					$	1.34

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, 2011 was 18,746. 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 2011 that were not registered under the Securities Act of 1933, as amended.

Performance Graph

The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the Standard and Poor’s 500 Stock Index and the cumulative total return of a customized peer company group, the Comparison Company Index, which is comprised of natural gas distribution companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2006 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 Indices


	Cumulative Total Return
	9/30/06		9/30/07		9/30/08		9/30/09		9/30/10		9/30/11

Atmos Energy Corporation		100.00		103.36		101.92		113.82		123.97		143.45
S&P 500		100.00		116.44		90.85		84.58		93.17		94.24
Peer Group		100.00		116.52		103.24		104.34		128.20		157.38

The Comparison Company Index contains a hybrid group of utility companies, primarily natural gas distribution companies, recommended by a global management 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, EQT Corporation, Integrys Energy Group, Inc., National Fuel Gas, Nicor Inc., NiSource Inc., ONEOK Inc., Piedmont Natural Gas Company, Inc., 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, 2011.

Number of

Number of Securities Remaining

Securities to be Issued

Weighted-Average

Available for Future Issuance

Upon Exercise of

Exercise Price of

Under Equity Compensation

Outstanding Options,

Plans (Excluding Securities

Warrants and Rights

Reflected in Column (a))

(a)

(b)

(c)

Equity compensation plans approved by security holders:

1998 Long-Term Incentive Plan

86,766

22.16

319,700

Total equity compensation plans approved by security holders

86,766

22.16

319,700

Equity compensation plans not approved by security holders

—

Total

86,766

22.16

319,700


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
	2011⁽¹⁾			2010			2009⁽¹⁾			2008			2007 ⁽¹⁾
	(In thousands, except per share data and ratios)

Results of Operations
Operating revenues	$	4,347,634		$	4,719,835		$	4,869,111		$	7,117,837		$	5,803,177
Gross profit		1,327,241			1,337,505			1,319,678			1,293,922			1,221,078
Operating expenses⁽¹⁾		885,342			860,354			883,312			878,399			835,353
Operating income		441,899			477,151			436,366			415,523			385,725
Miscellaneous income (expense)		21,499			(156	)		(3,067	)		3,017			9,227
Interest charges		150,825			154,360			152,638			137,218			145,019
Income from continuing operations before income taxes		312,573			322,635			280,661			281,322			249,933
Income tax expense		113,689			124,362			97,362			107,837			89,105
Income from continuing operations		198,884			198,273			183,299			173,485			160,828
Income from discontinued operations, net of tax		8,717			7,566			7,679			6,846			7,664
Net income	$	207,601		$	205,839		$	190,978		$	180,331		$	168,492
Weighted average diluted shares outstanding		90,652			92,422			91,620			89,941			87,486
Income per share from continuing operations — diluted	$	2.17		$	2.12		$	1.98		$	1.91		$	1.82
Income per share from discontinued operations — diluted		0.10			0.08			0.09			0.08			0.09
Diluted net income per share	$	2.27		$	2.20		$	2.07		$	1.99		$	1.91
Cash flows from operations	$	582,844		$	726,476		$	919,233		$	370,933		$	547,095
Cash dividends paid per share	$	1.36		$	1.34		$	1.32		$	1.30		$	1.28
Natural gas distribution throughput from continuing operations (MMcf)⁽²⁾		409,369			438,535			393,604			413,491			411,337
Natural gas distribution throughput from discontinued operations (MMcf)⁽²⁾		14,651			15,640			15,281			15,863			16,532
Total regulated transmission and storage transportation volumes (MMcf)⁽²⁾		435,012			428,599			528,689			595,542			505,493
Total nonregulated delivered gas sales volumes (MMcf)⁽²⁾		384,799			353,853			370,569			389,392			370,668
Financial Condition
Net property, plant and equipment⁽⁵⁾	$	5,147,918		$	4,793,075		$	4,439,103		$	4,136,859		$	3,836,836
Working capital⁽⁶⁾		143,355			(290,887	)		91,519			78,017			149,217
Total assets		7,282,871			6,763,791			6,367,083			6,386,699			5,895,197
Short-term debt, inclusive of current maturities of long-term debt		208,830			486,231			72,681			351,327			154,430
Capitalization:
Shareholders’ equity		2,255,421			2,178,348			2,176,761			2,052,492			1,965,754
Long-term debt (excluding current maturities)		2,206,117			1,809,551			2,169,400			2,119,792			2,126,315

Total capitalization		4,461,538			3,987,899			4,346,161			4,172,284			4,092,069
Capital expenditures		622,965			542,636			509,494			472,273			392,435
Financial Ratios
Capitalization ratio⁽³⁾		48.3	%		48.7	%		49.3	%		45.4	%		46.3	%
Return on average shareholders’ equity⁽⁴⁾		9.1	%		9.1	%		8.9	%		8.8	%		8.8	%


⁽¹⁾		Financial results for fiscal years 2011, 2009 and 2007 include a $30.3 million, $5.4 million and a $6.3 million pre-tax loss for the impairment of certain assets.

⁽²⁾		Net of intersegment eliminations.

⁽³⁾		The capitalization ratio is calculated by dividing shareholders’ equity by the sum of total capitalization and short-term debt, inclusive of current maturities of long-term debt.

⁽⁴⁾		The return on average shareholders’ equity is calculated by dividing current year net income by the average of shareholders’ equity for the previous five quarters.

⁽⁵⁾		Amount shown for fiscal 2011 are net of assets held for sale.

⁽⁶⁾		Amount shown for fiscal 2011 includes 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; the impact of adverse economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; 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 concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, 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 AND ESTIMATES

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 based our estimates on historical experience and various

other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, fair value measurements, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Our critical accounting policies are reviewed by the Audit Committee periodically. Actual results may differ from 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. We meet the criteria established within accounting principles generally accepted in the United States of a cost-based, rate-regulated entity, which requires us to reflect the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in our financial statements in accordance with applicable authoritative accounting standards. We apply the provisions of this standard to our regulated operations and record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable and regulatory liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. 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. 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. 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. The impact of regulation on our regulated operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.

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 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.

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 utility companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of the utility company’s non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of cost, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility company’s other costs, (ii) represents a large component of the utility company’s cost of service and (iii) is generally outside the control of the gas utility company. There is no gross profit generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in utility gas costs. Although substantially all natural gas distribution sales to our customers fluctuate with the cost of gas that we purchase, our gross profit is generally not affected by fluctuations in the cost of gas as a result of the purchased gas cost adjustment mechanism. 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 natural gas marketing 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.

Allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collections experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. 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.

Financial instruments and hedging activities — We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically use financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to meet the needs of our regulated and nonregulated businesses.

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 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, our customers are exposed to the effect 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. The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk in this segment 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 to our natural gas distribution segment as a result of the use of financial instruments.

Our nonregulated segment aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. We also perform asset optimization activities in which we seek to maximize the economic value associated with storage and transportation capacity we own or control in both our natural gas distribution and nonregulated businesses. As a result of these activities, our nonregulated operations are exposed to risks associated with changes in the market price of natural gas. We manage our exposure to the risk of natural gas price changes through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties.

In our nonregulated segment, we have designated 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. Changes in the spreads

between the forward natural gas prices used to value the financial instruments designated against our physical inventory (NYMEX) and the market (spot) prices used to value our physical storage (Gas Daily) result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. The difference in the spot price used to value our physical inventory and the forward price used to value the related financial instruments can result in volatility in our reported income as a component of unrealized margins. We have elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized. Over time, we expect gains and losses on the sale of storage gas inventory to be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

We have elected to treat fixed-price forward contracts used in our nonregulated segment to deliver 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 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. Hedge ineffectiveness, to the extent incurred, is reported as a component of revenue.

We also use storage swaps and futures to capture additional storage arbitrage opportunities in our nonregulated segment that arise after the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges.

Financial Instruments Associated with Interest Rate Risk

We periodically manage interest rate risk, typically when we issue new or refinance existing long-term debt with Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these Treasury lock agreements as cash flow hedges at the time the agreements are executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements are recorded as a component of accumulated other comprehensive income (loss). The realized gain or loss recognized upon settlement of each Treasury lock agreement is initially recorded as a component of accumulated other comprehensive income (loss) and is recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness, to the extent incurred, is reported as a component of interest expense.

Impairment assessments — We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. As of September 30, 2011, we had no indefinite-lived intangible assets.

We annually evaluate our goodwill balances for impairment during our second fiscal quarter or as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. We have determined our reporting units to be each of our natural gas distribution divisions and wholly-owned subsidiaries and goodwill is allocated to the reporting units responsible for the acquisition that gave rise to the goodwill. The discounted cash flow calculations used to assess goodwill impairment 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.

We annually assess whether the cost of our intangible assets subject to amortization or other long-lived assets is recoverable or that the remaining useful lives may warrant revision. We perform this assessment more frequently when specific events or circumstances have occurred that suggest the recoverability of the cost of the intangible and other long-lived assets is at risk.

When such events or circumstances are present, we assess the recoverability of these assets by determining whether the carrying value will be recovered through expected future cash flows from the operating division or subsidiary to which these assets relate. These cash flow projections consider various factors such as the timing of the future cash flows and the discount rate and are based upon the best information available at the time the estimate is made. Changes in these factors could materially affect the cash flow projections and result in the recognition of an impairment charge. An impairment charge is recognized as the difference between the carrying amount and the fair value if the sum of the undiscounted cash flows is less than the carrying value of the related asset.

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 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 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.

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 $1.9 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $0.8 million.

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.

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 a practical expedient 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 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.

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. Adverse developments in the global financial and credit markets in the last few years have made it more difficult and more expensive for companies to access the short-term capital markets, which may negatively impact the creditworthiness of our counterparties. A further tightening of the credit markets could cause more of our counterparties to fail to perform. 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, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions, 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.

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. This generally results 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 62 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years.

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 2011, we earned $207.6 million, or $2.27 per diluted share, which represents a one percent increase in net income and a three percent increase in diluted net income per share over fiscal 2010. During fiscal 2011, recent improvements in rate designs in our natural gas distribution segment and a successful regulatory outcome in our regulated transmission and storage segment offset a seven percent year-over-year decline in consolidated natural gas distribution throughput due to warmer weather and a 108 percent decrease in asset optimization margins as a result of weak natural gas market fundamentals. Results for fiscal 2011 were influenced by several non-recurring items, which increased diluted earnings per share by $0.03. The increase in fiscal 2011 earnings per share also reflects the favorable impact of our accelerated share buyback

agreement initiated in the fourth quarter of fiscal 2010 and completed in the second quarter of fiscal 2011, which increased diluted earnings per share by $0.08.

On May 12, 2011, we entered into a definitive agreement to sell all of our natural gas distribution assets located in Missouri, Illinois and Iowa to Liberty Energy (Midstates) Corporation, an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $124 million. The agreement contains terms and conditions customary for transactions of this type, including typical adjustments to the purchase price at closing, if applicable. The closing of the transaction is subject to the satisfaction of customary conditions including the receipt of applicable regulatory approvals. Due to the pending sales transaction, the results of operations for these three service areas are shown in discontinued operations.

On June 10, 2011 we issued $400 million of 5.50% senior notes. The effective interest rate on these notes is 5.381 percent, after giving effect to offering costs and the settlement of the $300 million Treasury locks associated with the offering. Substantially all of the net proceeds of approximately $394 million were used to repay $350 million of outstanding commercial paper. The remainder of the net proceeds was used for general corporate purposes. 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 will be recognized as a component of interest expense over the 30-year life of the senior notes.

During the year ended September 30, 2011, we executed on our strategy to streamline our credit facilities, as follows:


	•	On May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion.

	•	In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and AEM’s ability to access an intercompany facility that was increased in fiscal 2011; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million.

	•	In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement.

After giving effect to these changes, we now have $985 million of liquidity available to us from our commercial paper program and four committed credit facilities and have reduced our financing costs. We believe this availability provides sufficient liquidity to fund our working capital needs.

Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2011, 2010 and 2009.


	For the Fiscal Year Ended September 30
	2011		2010			2009
	(In thousands, except per share data)

Operating revenues	$	4,347,634	$	4,719,835		$	4,869,111
Gross profit		1,327,241		1,337,505			1,319,678
Operating expenses		885,342		860,354			883,312
Operating income		441,899		477,151			436,366
Miscellaneous income (expense)		21,499		(156	)		(3,067	)
Interest charges		150,825		154,360			152,638
Income from continuing operations before income taxes		312,573		322,635			280,661
Income tax expense		113,689		124,362			97,362
Income from continuing operations		198,884		198,273			183,299
Income from discontinued operations, net of tax		8,717		7,566			7,679
Net income	$	207,601	$	205,839		$	190,978
Diluted net income per share from continuing operations	$	2.17	$	2.12		$	1.98
Diluted net income per share from discontinued operations	$	0.10	$	0.08		$	0.09
Diluted net income per share	$	2.27	$	2.20		$	2.07

Historically, our regulated operations arising from our natural gas distribution and regulated transmission and storage operations contributed 65 to 85 percent of our consolidated net income. Regulated operations contributed 104 percent, 81 percent and 83 percent to our consolidated net income for fiscal years 2011, 2010, and 2009. 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
	2011			2010		2009
	(In thousands)

Natural gas distribution segment	$	162,718		$	125,949	$	116,807
Regulated transmission and storage segment		52,415			41,486		41,056
Nonregulated segment		(7,532	)		38,404		33,115

Net income	$	207,601		$	205,839	$	190,978

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
	2011			2010		2009
	(In thousands, except per share data)

Regulated operations	$	215,133		$	167,435	$	157,863
Nonregulated operations		(7,532	)		38,404		33,115

Consolidated net income	$	207,601		$	205,839	$	190,978

Diluted EPS from regulated operations	$	2.35		$	1.79	$	1.71
Diluted EPS from nonregulated operations		(0.08	)		0.41		0.36

Consolidated diluted EPS	$	2.27		$	2.20	$	2.07

We reported net income of $207.6 million, or $2.27 per diluted share for the year ended September 30, 2011, compared with net income of $205.8 million or $2.20 per diluted share in the prior year. Income from continuing operations was $198.9 million, or $2.17 per diluted share compared with $198.3 million, or $2.12 per diluted share in the prior-year period. Income from discontinued operations was $8.7 million or $0.10 per diluted share for the year, compared with $7.6 million or $0.08 per diluted share in the prior year. Unrealized losses in our nonregulated operations during the current year reduced net income by $6.6 million or $0.07 per diluted share compared with net losses recorded in the prior year of $4.3 million, or $0.05 per diluted share. Additionally, net income in both periods was impacted by nonrecurring items. In the prior year, net income included the net positive impact of a state sales tax refund of $4.6 million, or $0.05 per diluted share. In the current year, net income includes the net positive impact of several one-time items totaling $3.2 million, or $0.03 per diluted share related to the following pre-tax amounts:


	•	$27.8 million favorable impact related to the cash gain recorded in association with the unwinding of two Treasury locks in conjunction with the cancellation of a planned debt offering in November 2011.

	•	$30.3 million unfavorable impact related to the non-cash impairment of certain assets in our nonregulated business.

	•	$5.0 million favorable impact related to the administrative settlement of various income tax positions.

Net income during fiscal 2010 increased eight percent over fiscal 2009. Net income from our regulated operations increased six percent during fiscal 2010. The increase primarily reflects colder than normal weather in most of our service areas during fiscal 2010 as well as the net favorable impact of various ratemaking activities in our natural gas distribution segment. Net income in our nonregulated operations increased $5.3 million during fiscal 2010 primarily due to the impact of unrealized margins. Non-cash, net unrealized losses totaled $4.3 million which reduced earnings per share by $0.05 per diluted share in fiscal 2010 compared to fiscal 2009, when net unrealized losses totaled $21.6 million, which reduced earnings per share by $0.23 per diluted share.

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 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 receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the 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.

As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, 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 73 percent of our residential and commercial margins.

In May 2011, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Missouri, Illinois and Iowa. The results of these operations have been separately reported in the following tables and exclude general corporate overhead and interest expense that would normally be allocated to these operations.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2011, 2010 and 2009 are presented below.


	For the Fiscal Year Ended September 30
	2011		2010		2009		2011 vs. 2010			2010 vs. 2009
			(In thousands, unless otherwise noted)

Gross profit	$	1,044,364	$	1,022,011	$	997,604	$	22,353		$	24,407
Operating expenses		706,363		711,842		719,626		(5,479	)		(7,784	)

Operating income		338,001		310,169		277,978		27,832			32,191
Miscellaneous income		16,557		1,567		6,002		14,990			(4,435	)
Interest charges		115,802		118,319		123,863		(2,517	)		(5,544	)

Income from continuing operations before income taxes		238,756		193,417		160,117		45,339			33,300
Income tax expense		84,755		75,034		50,989		9,721			24,045

Income from continuing operations		154,001		118,383		109,128		35,618			9,255
Income from discontinued operations, net of tax		8,717		7,566		7,679		1,151			(113	)

Net Income	$	162,718	$	125,949	$	116,807	$	36,769		$	9,142

Consolidated natural gas distribution sales volumes from continuing operations — MMcf		281,466		313,888		273,555		(32,422	)		40,333
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf		127,903		124,647		120,049		3,256			4,598

Consolidated natural gas distribution throughput from continuing operations — MMcf		409,369		438,535		393,604		(29,166	)		44,931
Consolidated natural gas distribution throughput from discontinued operations — MMcf		14,651		15,640		15,281		(989	)		359

Total consolidated natural gas distribution throughput — MMcf		424,020		454,175		408,885		(30,155	)		45,290

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.47	$	0.47	$	0.47	$	—		$	—
Consolidated natural gas distribution average cost of gas per Mcf sold	$	5.30	$	5.77	$	6.95	$	(0.47	)	$	(1.18	)

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, 2011, 2010 and 2009. 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
	2011		2010			2009		2011 vs. 2010			2010 vs. 2009
	(In thousands)

Mid-Tex	$	144,204	$	134,655		$	127,625	$	9,549		$	7,030
Kentucky/Mid-States		53,506		46,238			37,683		7,268			8,555
Louisiana		50,442		45,759			43,434		4,683			2,325
West Texas		29,686		33,509			23,338		(3,823	)		10,171
Mississippi		26,338		26,441			21,287		(103	)		5,154
Colorado-Kansas		25,920		24,543			20,580		1,377			3,963
Other		7,905		(976	)		4,031		8,881			(5,007	)

Total	$	338,001	$	310,169		$	277,978	$	27,832		$	32,191

Fiscal year ended September 30, 2011 compared with fiscal year ended September 30, 2010

The $22.4 million increase in natural gas distribution gross profit primarily reflects a $40.4 million net increase in rate adjustments, primarily in the Mid-Tex, Louisiana, Kentucky and Kansas service areas.

These increases were partially offset by:


	•	$12.0 million decrease due to a seven percent decrease in consolidated throughput caused principally by lower residential and commercial consumption combined with warmer weather this fiscal year compared to the same period last year in most of our service areas.

	•	$8.1 million decrease in revenue-related taxes, primarily due to lower revenues on which the tax is calculated.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income decreased $5.5 million, primarily due to the following:


	•	$10.0 million decrease in taxes, other than income, due to lower revenue-related taxes.

	•	$6.4 million decrease in employee-related expenses.

These decreases were partially offset by:


	•	$5.4 million increase due to the absence of a state sales tax reimbursement received in the prior year.

	•	$11.8 million increase in depreciation and amortization expense.

	•	$1.8 million increase in vehicles and equipment expense.

Net income for this segment for the year-to-date period was also favorably impacted by a $21.8 million pre-tax gain recognized in March 2011 as a result of unwinding two Treasury locks and a $5.0 million income tax benefit related to the administrative settlement of various income tax positions.

Fiscal year ended September 30, 2010 compared with fiscal year ended September 30, 2009

The $24.4 million increase in natural gas distribution gross profit primarily reflects rate adjustments and increased throughput as follows:


	•	$33.4 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana, Kentucky, Tennessee, Virginia and Mississippi service areas.


	•	$10.6 million increase as a result of an 11 percent increase in consolidated throughput primarily associated with higher residential and commercial consumption and colder weather in most of our service areas.

These increases were partially offset by:


	•	$7.6 million decrease due to a non-recurring adjustment recorded in the prior-year period to update the estimate for gas delivered to customers but not yet billed to reflect base rate changes.

	•	$7.0 million decrease related to a prior-year reversal of an accrual for estimated unrecoverable gas costs that did not recur in the current year.

	•	$1.6 million decrease in revenue-related taxes, primarily due to a decrease in revenues on which the tax is calculated.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income and asset impairments decreased $7.8 million, primarily due to the following:


	•	$5.4 million decrease due to a state sales tax reimbursement received in March 2010.

	•	$4.6 million decrease due to the absence of an impairment charge for available-for-sale securities recorded in the prior year.

	•	$4.5 million decrease in contract labor expenses.

	•	$4.6 million decrease in travel, legal and other administrative costs.

These decreases were partially offset by:


	•	$7.5 million increase in employee-related expenses.

	•	$4.5 million increase in taxes, other than income.

Miscellaneous income decreased $4.4 million due to lower interest income. Interest charges decreased $5.5 million primarily due to lower short-term debt balances and interest rates.

Additionally, results for the fiscal year ended September 30, 2009, were favorably impacted by a one-time tax benefit of $10.5 million. During the second quarter of fiscal 2009, the Company completed a study of the calculations used to estimate its deferred tax rate, and concluded that revisions to these calculations to include more specific jurisdictional tax rates would result in a more accurate calculation of the tax rate at which deferred taxes would reverse in the future. Accordingly, the Company modified the tax rate used to calculate deferred taxes from 38 percent to an individual rate for each legal entity. These rates vary from 36-41 percent depending on the jurisdiction of the legal entity.

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.

Similar to our natural gas distribution segment, 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.

Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the fiscal years ended September 30, 2011, 2010, and 2009 are presented below.


	For the Fiscal Year Ended September 30
	2011		2010		2009		2011 vs. 2010			2010 vs. 2009
			(In thousands, unless otherwise noted)

Mid-Tex Division transportation	$	125,973	$	102,891	$	89,348	$	23,082		$	13,543
Third-party transportation		73,676		73,648		95,314		28			(21,666	)
Storage and park and lend services		7,995		10,657		11,858		(2,662	)		(1,201	)
Other		11,729		15,817		13,138		(4,088	)		2,679

Gross profit		219,373		203,013		209,658		16,360			(6,645	)
Operating expenses		111,098		105,975		116,495		5,123			(10,520	)

Operating income		108,275		97,038		93,163		11,237			3,875
Miscellaneous income		4,715		135		1,433		4,580			(1,298	)
Interest charges		31,432		31,174		30,982		258			192

Income before income taxes		81,558		65,999		63,614		15,559			2,385
Income tax expense		29,143		24,513		22,558		4,630			1,955

Net income	$	52,415	$	41,486	$	41,056	$	10,929		$	430

Gross pipeline transportation volumes — MMcf		620,904		634,885		706,132		(13,981	)		(71,247	)

Consolidated pipeline transportation volumes — MMcf		435,012		428,599		528,689		6,413			(100,090	)

Fiscal year ended September 30, 2011 compared with fiscal year ended September 30, 2010

On April 18, 2011, the Railroad Commission of Texas (RRC) issued an order in the rate case of Atmos Pipeline — Texas (APT) that was originally filed in September 2010. The RRC approved an annual operating income increase of $20.4 million as well as the following major provisions that went into effect with bills rendered on and after May 1, 2011:


	•	Authorized return on equity of 11.8 percent.

	•	A capital structure of 49.5 percent debt/50.5 percent equity

	•	Approval of a rate base of $807.7 million, compared to the $417.1 million rate base from the prior rate case.

	•	An annual adjustment mechanism, which was approved for a three-year pilot program, that will adjust regulated rates up or down by 75 percent of the difference between APT’s non-regulated annual revenue and a pre-defined base credit.

	•	Approval of a straight fixed variable rate design, under which all fixed costs associated with transportation and storage services are recovered through monthly customer charges.

The $16.4 million increase in regulated transmission and storage gross profit was attributable primarily to the following:


	•	$23.4 million net increase as a result of the rate case that was finalized and became effective in May 2011.

	•	$3.2 million increase associated with our most recent GRIP filing.

These increases were partially offset by the following:


	•	$4.8 million decrease due to the absence of the sale of excess gas, which occurred in the prior year.

	•	$4.4 million decrease due to a decline in throughput to our Mid-Tex Division primarily due to warmer than normal weather during fiscal 2011.

Operating expenses increased $5.1 million primarily due to the following:


	•	$4.6 million increase due to higher depreciation expense.

	•	$2.0 million increase due to the absence of a state sales tax reimbursement received in the prior year.

These increases were partially offset by the following:


	•	$0.8 million decrease related to lower levels of pipeline maintenance activities.

	•	$0.7 million decrease due to lower employee-related expenses.

Miscellaneous income includes a $6.0 million gain recognized in March 2011 as a result of unwinding two Treasury locks.

Fiscal year ended September 30, 2010 compared with fiscal year ended September 30, 2009

The $6.6 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$13.3 million decrease due to lower transportation fees on through-system deliveries due to narrower basis spreads.

	•	$2.6 million decrease due to decreased through-system volumes primarily associated with market conditions that resulted in reduced wellhead production, decreased drilling activity and increased competition, partially offset by increased deliveries to our Mid-Tex Division.

	•	$1.6 million net decrease in market-based demand fees, priority reservation fees and compression activity associated with lower throughput.

These decreases were partially offset by the following:


	•	$9.3 million increase associated with our GRIP filings.

	•	$2.0 million increase of excess inventory sales in the current-year period.

Operating expenses decreased $10.5 million primarily due to:


	•	$11.8 million decrease related to reduced contract labor.

	•	$2.0 million decrease due to a state sales tax reimbursement received in March 2010.

These decreases were partially offset by a $2.1 million increase in taxes, other than income due to higher ad valorem and payroll taxes.

Miscellaneous income decreased $1.3 million due primarily to a decline in intercompany interest income.

Nonregulated Segment

AEH continually manages its net physical position to attempt to increase the future economic profit that was created when the original transaction was executed. Therefore, AEH may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market conditions. If AEH elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to offset the original financial instruments. If AEH elects to defer the withdrawal of gas, it will execute new financial instruments to correspond to the revised withdrawal schedule and allow the original financial instrument to settle as contracted.

We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The hedged natural gas 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 and losses in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.

AEH also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.

nonregulated businesses. Within our delivered gas activities, basis differentials impact our ability to create value from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access. Further, higher natural gas prices 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. Higher gas prices, as well as competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.

Volatility in natural gas prices also has a significant impact on our nonregulated segment. Increased price volatility often has a significant impact on the spreads between the market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. Volatility could also impact the basis differentials we capture in our delivered gas activities. However, increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could cause an increase in the amount of cash required to collateralize our risk management liabilities.

Review of Financial and Operating Results

Financial and operational highlights for our nonregulated segment for the fiscal years ended September 30, 2011, 2010 and 2009 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers, margins earned from storage and transportation services and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.

Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. Generally, if the physical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. 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.


	For the Fiscal Year Ended September 30
	2011			2010			2009			2011 vs. 2010			2010 vs. 2009
				(In thousands, unless otherwise noted)

Realized margins
Gas delivery and related services	$	58,990		$	59,523		$	75,341		$	(533	)	$	(15,818	)
Storage and transportation services		14,570			13,206			12,784			1,364			422
Other		5,265			5,347			9,365			(82	)		(4,018	)

		78,825			78,076			97,490			749			(19,414	)
Asset optimization⁽¹⁾		(3,424	)		43,805			52,507			(47,229	)		(8,702	)

Total realized margins		75,401			121,881			149,997			(46,480	)		(28,116	)
Unrealized margins		(10,401	)		(7,790	)		(35,889	)		(2,611	)		28,099

Gross profit		65,000			114,091			114,108			(49,091	)		(17	)
Operating expenses, excluding asset impairment		39,113			44,147			49,046			(5,034	)		(4,899	)
Asset impairment		30,270			—			181			30,270			(181	)

Operating income (loss)		(4,383	)		69,944			64,881			(74,327	)		5,063
Miscellaneous income		657			3,859			6,399			(3,202	)		(2,540	)
Interest charges		4,015			10,584			14,350			(6,569	)		(3,766	)

Income (loss) before income taxes		(7,741	)		63,219			56,930			(70,960	)		6,289
Income tax expense (benefit)		(209	)		24,815			23,815			(25,024	)		1,000

Net income (loss)	$	(7,532	)	$	38,404		$	33,115		$	(45,936	)	$	5,289

Gross nonregulated delivered gas sales volumes — MMcf		446,903			420,203			441,081			26,700			(20,878	)

Consolidated nonregulated delivered gas sales volumes — MMcf		384,799			353,853			370,569			30,946			(16,716	)

Net physical position (Bcf)		21.0			15.7			15.9			5.3			(0.2	)


⁽¹⁾		Net of storage fees of $15.2 million, $13.2 million and $10.8 million.

Fiscal year ended September 30, 2011 compared with fiscal year ended September 30, 2010

Realized margins for gas delivery, storage and transportation services and other services were $78.8 million during the year ended September 30, 2011 compared with $78.1 million for the prior-year period. The increase primarily reflects the following:


	•	$1.4 million increase in margins from storage and transportation services, primarily attributable to new drilling projects in the Barnett Shale area.

	•	$0.6 million decrease in gas delivery and other services primarily due to lower per-unit margins partially offset by a nine percent increase in consolidated delivered gas sales volumes due to new customers in the power generation market. Per-unit margins were $0.13/Mcf in the current year compared with $0.14/Mcf in the prior year. The year-over-year decrease in per-unit margins reflects the impact of increased competition and lower basis spreads.

The $47.2 million decrease in realized asset optimization margins from the prior year primarily reflects the unfavorable impact of weak natural gas market fundamentals which provided fewer favorable trading opportunities.

Unrealized margins decreased $2.6 million in the current period compared to the prior-year period primarily due to the timing of year-over-year realized margins.

Operating expenses decreased $5.0 million primarily due to lower employee-related expenses and ad valorem taxes.

During fiscal 2011, our nonregulated segment recognized $30.3 million of non-cash asset impairment charges associated with two projects. In March 2011, we recorded a $19.3 million charge to substantially write off our investment in Fort Necessity. This project began in February 2008 when 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. At that time, we evaluated our strategic alternatives and concluded the project’s returns did not meet our investment objectives. Additionally, during the third quarter of fiscal 2011, we recorded an $11.0 million non-cash charge to impair certain natural gas gathering assets of Atmos Gathering Company. The charge reflected a reduction in the value of the project due to the current low natural gas price environment and the adverse impact of an ongoing lawsuit associated with the project.

Interest charges decreased $6.6 million primarily due to a decrease in intercompany borrowings.

Asset Optimization Activities

AEH monitors the impact of its asset optimization efforts by estimating the gross profit, before related fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic value, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement and related fees is referred to as the potential gross profit.

We define potential gross profit as the change in AEH’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include other operating expenses and associated income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic value or the potential gross profit will be fully realized in the future.

We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone. Because there is no assurance that the economic value or potential gross profit will be realized in the future, corresponding future GAAP amounts are not available.

The following table presents AEH’s economic value and its potential gross profit (loss) at September 30, 2011 and 2010.


	September 30
	2011			2010
	(In millions, unless otherwise noted)

Economic value	$	4.9		$	(7.5	)
Associated unrealized losses		14.7			12.8

Subtotal		19.6			5.3
Related fees⁽¹⁾		(17.7	)		(10.6	)

Potential gross profit (loss)	$	1.9		$	(5.3	)

Net physical position (Bcf)		21.0			15.7


⁽¹⁾		Related fees represent the contractual costs to acquire the storage capacity utilized in our nonregulated segment’s asset optimization operations. The fees primarily consist of demand fees and contractual obligations to sell gas below market index in exchange for the right to manage and optimize third party storage assets for the positions we have entered into as of September 30, 2011 and 2010.

During the 2011 fiscal year, our nonregulated segment’s economic value increased from a negative economic value of ($7.5) million, or ($0.48)/Mcf at September 30, 2010 to $4.9 million, or $0.23/Mcf at September 30, 2011.

The increase in economic value was attributable to several factors including an increase in the captured spread value resulting from realizing financial instruments with lower spread values, entering into financial hedges with higher average prices and rolling financial instruments to forward periods to capture incremental value. Additionally, as a result of falling gas prices throughout the year, we injected a net 5.3 Bcf, which reduced the overall weighted average cost of gas held in storage.

The economic value is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEH actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic value or the potential gross profit as of September 30, 2011 will be fully realized in the future nor can we predict in what time periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted.

Fiscal year ended September 30, 2010 compared with fiscal year ended September 30, 2009

Realized margins for gas delivery, storage and transportation services and other services contributed 64 percent to total realized margins during fiscal 2010, with asset optimization activities contributing the remaining 36 percent. In fiscal 2009, gas delivery, storage and transportation services and other services represented 65 percent of the nonregulated segment’s realized margins with asset optimization contributing the remaining 35 percent. The $28.1 million decrease in realized gross profit reflected:


	•	$19.4 million decrease in gas delivery, storage and transportation services and other services as a result of narrowing basis spreads, combined with lower delivered sales volumes. Per-unit delivered gas margins were $0.14/Mcf in fiscal 2010, compared with $0.17/Mcf in fiscal 2009, while delivered gas volumes were 5 percent lower in fiscal 2010 when compared with fiscal 2009.

	•	$8.7 million decrease in asset optimization due to lower margins earned on storage optimization activities, lower basis gains earned from utilizing leased capacity and lower margins earned on asset management plans, partially offset by higher realized storage and trading gains during fiscal 2010.

The decrease in realized gross profit was offset by a $28.1 million increase in unrealized margins due to the period-over-period timing of storage withdrawal gains and the associated reversal of unrealized gains into realized gains.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income taxes, and asset impairments decreased $5.1 million primarily due a decrease in employee and other administrative costs, partially offset by an increase in gas gathering activities.

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 have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require. During fiscal 2011, we executed on our strategy of consolidating our short-term facilities used for our regulated operations into a single line of credit, including the following:


	•	On May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion.

	•	In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and AEM’s ability to access an intercompany facility that was increased during fiscal 2011; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million.

	•	In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement.

As a result of these changes, we now have $985 million of availability from our commercial paper program and four committed revolving credit facilities with third parties.

Our $350 million 7.375% senior notes were paid on their maturity date on May 15, 2011 using commercial paper borrowings. In effect, we refinanced this debt on a long-term basis through the issuance of $400 million 5.50% 30-year unsecured senior notes on June 10, 2011. On September 30, 2010, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost of financing the anticipated issuances of senior notes. 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 lock and settlement. The effective interest rate on these notes is 5.381 percent, after giving effect to offering costs and the settlement of the $300 million Treasury locks. Substantially all of the net proceeds of approximately $394 million were used to repay $350 million of outstanding commercial paper. The remainder of the net proceeds was used for general corporate purposes.

Additionally, we had planned to issue $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. A pretax cash gain of approximately $28 million was recorded in March 2011.

Finally, we intend to refinance our $250 million unsecured 5.125% Senior Notes that mature in January 2013 through the issuance of $350 million 30-year unsecured notes. In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with the anticipated issuances of these senior notes. We designated all of these Treasury locks as cash flow hedges.

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 2012.

Cash Flows

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

Cash flows from operating, investing and financing activities for the years ended September 30, 2011, 2010 and 2009 are presented below.


	For the Fiscal Year Ended September 30
	2011			2010			2009			2011 vs. 2010			2010 vs. 2009
							(In thousands)

Total cash provided by (used in)
Operating activities	$	582,844		$	726,476		$	919,233		$	(143,632	)	$	(192,757	)
Investing activities		(627,386	)		(542,702	)		(517,201	)		(84,684	)		(25,501	)
Financing activities		44,009			(163,025	)		(337,546	)		207,034			174,521

Change in cash and cash equivalents		(533	)		20,749			64,486			(21,282	)		(43,737	)
Cash and cash equivalents at beginning of period		131,952			111,203			46,717			20,749			64,486

Cash and cash equivalents at end of period	$	131,419		$	131,952		$	111,203		$	(533	)	$	20,749

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, 2011 compared with fiscal year ended September 30, 2010

For the fiscal year ended September 30, 2011, we generated operating cash flow of $582.8 million from operating activities compared with $726.5 million in the prior year. The year-over-year decrease reflects the absence of an $85 million income tax refund received in the prior year coupled with the timing of gas cost recoveries under our purchased gas cost mechanisms and other net working capital changes.

Fiscal Year ended September 30, 2010 compared with fiscal year ended September 30, 2009

For the fiscal year ended September 30, 2010, we generated operating cash flow of $726.5 million from operating activities compared with $919.2 million in fiscal 2009, primarily due to the fluctuation in gas costs. Gas costs, which reached historically high levels during the 2008 injection season, declined sharply when the economy slipped into the recession and have remained relatively stable since that time. Operating cash flows for the fiscal 2010 period reflect the recovery of lower gas costs through purchased gas recovery mechanisms

and sales. This is in contrast to the fiscal 2009 period, where operating cash flows were favorably influenced by the recovery of high gas costs during a period of falling prices.

Cash flows from investing activities

In recent fiscal years, a substantial portion of our cash resources has been used to fund our ongoing construction program and improvements to information technology systems. Our ongoing construction 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, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are focusing our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

In early fiscal 2010, two coalitions of cities, representing the majority of the cities our Mid-Tex Division serves, agreed to a program of installing, beginning in the first quarter of fiscal 2011, 100,000 steel service line replacements during fiscal 2011 and 2012, with approved recovery of the associated return, depreciation and taxes. During fiscal 2011, we replaced 35,852 lines for a cost of $49.7 million. The program is progressing on schedule for completion in September 2012. As a result of this project and spending to replace our regulated customer service systems and our nonregulated energy trading risk management system, we anticipate capital expenditures will remain elevated during the next fiscal year.

For the fiscal year ended September 30, 2011, we incurred $623.0 million for capital expenditures compared with $542.6 million for the fiscal year ended September 30, 2010 and $509.5 million for the fiscal year ended September 30, 2009.

The $80.4 million increase in capital expenditures in fiscal 2011 compared to fiscal 2010 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 the construction of a new customer contact center in Amarillo, Texas, partially offset by costs incurred in the prior fiscal year to relocate the company’s information technology data center.

The $33.1 million increase in capital expenditures in fiscal 2010 compared to fiscal 2009 primarily reflects spending for the relocation of our information technology data center to a new facility, the construction of two service centers and the steel service line replacement program in our Mid-Tex Division.

Cash flows from financing activities

For the fiscal year ended September 30, 2011, our financing activities generated $44.0 million in cash, while financing activities for the fiscal year ended September 30, 2010 used $163.0 million in cash compared with cash of $337.5 million used for the fiscal year ended September 30, 2009. Our significant financing activities for the fiscal years ended September 30, 2011, 2010 and 2009 are summarized as follows:

2011

During the fiscal year ended September 30, 2011, we:


	•	Received $394.5 million net cash proceeds in June 2011 related to the issuance of $400 million 5.50% senior notes due 2041.

	•	Borrowed a net $83.3 million under our short-term facilities to fund working capital needs.

	•	Received $27.8 million cash in March 2011 related to the unwinding of two Treasury locks.

	•	Received $20.1 million cash in June 2011 related to the settlement of three Treasury locks associated with the $400 million 5.50% senior notes offering.

	•	Received $7.8 million net proceeds related to the issuance of 0.3 million shares of common stock.


	•	Paid $360.1 million for scheduled long-term debt repayments, including our $350 million 7.375% senior notes that were paid on their maturity date on May 15, 2011.

	•	Paid $124.0 million in cash dividends which reflected a payout ratio of 60 percent of net income.

	•	Paid $5.3 million for the repurchase of equity awards.

2010

During the fiscal year ended September 30, 2010, we:


	•	Paid $124.3 million in cash dividends which reflected a payout ratio of 61 percent of net income.

	•	Paid $100.5 million for the repurchase of common stock under an accelerated share repurchase agreement.

	•	Borrowed a net $54.3 million under our short-term facilities due to the impact of seasonal natural gas purchases.

	•	Received $8.8 million net proceeds related to the issuance of 0.4 million shares of common stock, which is a 68 percent decrease compared to the prior year due primarily to the fact that beginning in fiscal 2010 shares were purchased on the open market rather than being issued by us to the Direct Stock Purchase Plan and the Retirement Savings Plan.

	•	Paid $1.2 million to repurchase equity awards.

2009

During the fiscal year ended September 30, 2009, we:


	•	Paid $407.4 million to repay our $400 million 4.00% unsecured notes.

	•	Repaid a net $284.0 million short-term borrowings under our credit facilities.

	•	Paid $121.5 million in cash dividends which reflected a payout ratio of 64 percent of net income.

	•	Received $445.6 million in net proceeds related to the March 2009 issuance of $450 million of 8.50% Senior Notes due 2019. The net proceeds were used to repay the $400 million 4.00% unsecured notes.

	•	Received $27.7 million net proceeds related to the issuance of 1.2 million shares of common stock.

	•	Received $1.9 million net proceeds related to the settlement of the Treasury lock agreement associated with the March 2009 issuance of the $450 million of 8.50% Senior Notes due 2019.

The following table shows the number of shares issued for the fiscal years ended September 30, 2011, 2010 and 2009:


	For the Fiscal Year Ended September 30
	2011		2010		2009

Shares issued:
Direct stock purchase plan		—		103,529		407,262
Retirement savings plan		—		79,722		640,639
1998 Long-term incentive plan		675,255		421,706		686,046
Outside directors stock-for-fee plan		2,385		3,382		3,079

Total shares issued		677,640		608,339		1,737,026

The number of shares issued in fiscal 2011 compared with the number of shares issued in fiscal 2010 primarily reflects an increased number of shares issued under our 1998 Long-Term Incentive Plan due to the exercise of stock options during the current fiscal year. This increase was partially offset by the fact that we

are purchasing shares in the open market rather than issuing new shares for the Direct Stock Purchase Plan and the Retirement Savings Plan. During fiscal 2011, we cancelled and retired 169,793 shares attributable to federal withholdings on equity awards and repurchased and retired 375,468 shares attributable to our 2010 accelerated share repurchase agreement described below, which are not included in the table above.

The year-over-year decrease in the number of shares issued in fiscal 2010 compared with the number of shares issued in fiscal 2009, primarily reflects the fact that in fiscal 2010, we began to purchase shares in the open market rather than issuing new shares for the Direct Stock Purchase Plan and the Retirement Savings Plan. Further, a higher average stock price during the second and third quarters of fiscal 2010 compared to the second and third quarters of 2009 enabled us to issue fewer shares during fiscal 2010. Additionally, during fiscal 2010, we cancelled and retired 37,365 shares attributable to federal withholdings on equity awards and repurchased and retired 2,958,580 common shares as part of our 2010 accelerated share repurchase agreement described below, which are not included in the table above.

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 for shares of Atmos Energy common stock in a share forward transaction and received 2,958,580 shares. 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 the Board of Directors approved a new program authorizing the repurchase of up to five million shares of common stock over a five-year period. 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. The program is primarily intended to minimize the dilutive effect of equity grants under various benefit related incentive compensation plans of the company.

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. However, our short-term borrowings typically reach their highest levels in the winter months.

As of September 30, 2011, we financed our short-term borrowing requirements through a combination of a $750.0 million commercial paper program and four committed revolving credit facilities with third-party lenders that provided $985 million of working capital funding. As of September 30, 2011, the amount available to us under our credit facilities, net of outstanding letters of credit, was $702.5 million. These facilities are described in further detail in Note 7 to the consolidated financial statements.

On May 2, 2011, we replaced our five-year $566.7 million unsecured credit facility, due to expire in December 2011, with a five-year $750 million unsecured credit facility with an accordion feature that could increase our borrowing capacity to $1.0 billion.

In December 2010, we replaced AEM’s $450 million 364-day facility with a $200 million, three-year facility. The reduced amount of the new facility is due to the current low cost of gas and AEM’s ability to access an intercompany facility that was increased in fiscal 2011; however, this facility contains an accordion feature that could increase our borrowing capacity to $500 million.

In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement that expired in April 2011. As planned, we did not replace or extend this agreement.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we were able to issue a total of $950 million in debt securities and $350 million in equity securities. At September 30, 2011, $900 million was available for issuance. Of this amount, $550 million is available for the issuance of debt securities and $350 million remains available for the issuance of equity securities under the shelf until March 2013.

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). On May 11, 2011, Moody’s upgraded our senior unsecured debt rating to Baa1 from Baa2, with a ratings outlook of stable, citing steady rate increases, improving credit metrics and a strategic focus on lower risk regulated activities as reasons for the upgrade. On June 2, 2011, Fitch upgraded our senior unsecured debt rating to A- from BBB+, with a ratings outlook of stable, citing a constructive regulatory environment, strategic focus on lower risk regulated activities and the geographic diversity of our regulated operations as key rating factors. As of September 30, 2011, S&P maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB+

Baa1

A-

Commercial paper

A-2

P-2

F-2

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

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

Debt Covenants

We were in compliance with all of our debt covenants as of September 30, 2011. Our debt covenants are described in Note 7 to the consolidated financial statements.

Capitalization

The following table presents our capitalization as of September 30, 2011 and 2010:


	September 30
	2011				2010
	(In thousands, except percentages)

Short-term debt	$	206,396	4.4	%	$	126,100	2.8	%
Long-term debt		2,208,551	47.3	%		2,169,682	48.5	%
Shareholders’ equity		2,255,421	48.3	%		2,178,348	48.7	%

Total capitalization, including short-term debt	$	4,670,368	100.0	%	$	4,474,130	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 51.7 percent and 51.3 percent at September 30, 2011 and 2010. The increase in the debt to capitalization ratio primarily reflects an increase in short-term debt as of September 30, 2011 compared to the prior year. Our ratio of total debt to capitalization is typically greater during the winter heating season as we make additional short-term borrowings to fund natural gas purchases and meet our working capital requirements. We intend to continue to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

Contractual Obligations and Commercial Commitments

The following table provides information about contractual obligations and commercial commitments at September 30, 2011.


	Payments Due by Period
			Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years
					(In thousands)

Contractual Obligations
Long-term debt⁽¹⁾	$	2,212,565	$	2,434	$	250,131	$	500,000	$	1,460,000
Short-term debt⁽¹⁾		206,396		206,396		—		—		—
Interest charges⁽²⁾		1,574,702		136,452		250,841		198,596		988,813
Gas purchase commitments⁽³⁾		460,179		274,985		185,194		—		—
Capital lease obligations⁽⁴⁾		1,194		186		372		372		264
Operating leases⁽⁴⁾		199,567		17,718		33,365		30,376		118,108
Demand fees for contracted storage⁽⁵⁾		19,339		11,421		6,770		983		165
Demand fees for contracted transportation⁽⁶⁾		37,295		13,941		19,929		3,425		—
Financial instrument obligations⁽⁷⁾		93,542		15,453		78,089		—		—
Postretirement benefit plan contributions⁽⁸⁾		194,323		31,519		28,543		35,122		99,139

Total contractual obligations	$	4,999,102	$	710,505	$	853,234	$	768,874	$	2,666,489


⁽¹⁾		See Note 7 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, 2011.


⁽⁴⁾		See Note 14 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, 2011. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled. The table above excludes $1.3 million of current liabilities from risk management activities that are classified as liabilities held for sale in conjunction with the sale of our Iowa, Illinois and Missouri operations.

⁽⁸⁾		Represents expected contributions to our postretirement benefit plans.

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, 2011, AEH was committed to purchase 103.3 Bcf within one year, 46.4 Bcf within one to three years and 0.9 Bcf after three years under indexed contracts. AEH is committed to purchase 4.2 Bcf within one year and 0.3 Bcf within one to three years under fixed price contracts with prices ranging from $3.49 to $6.36 per Mcf.

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 the individual contract. 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 these contract terms as of September 30, 2011 are reflected in the table above.

Risk Management Activities

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 use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated segment associated with deliveries under fixed-priced forward contracts to deliver gas to customers, and we use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our nonregulated segment.

Also, in our nonregulated segment, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges.

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, 2011 (in thousands):


Fair value of contracts at September 30, 2010	$	(49,600	)
Contracts realized/settled		(51,136	)
Fair value of new contracts		2,584