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, 2010
		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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer 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, 2010, was $2,598,503,183.

As of November 5, 2010, the registrant had 90,421,614 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 9, 2011 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		28
	Item 2.	Properties		28
	Item 3.	Legal Proceedings		29
	Item 4.	Submission of Matters to a Vote of Security Holders		29

Part II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		31
	Item 6.	Selected Financial Data		34
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		64
	Item 8.	Financial Statements and Supplementary Data		66
	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		136
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		136
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		136
	Item 14.	Principal Accountant Fees and Services		136

Part IV
	Item 15.	Exhibits and Financial Statement Schedules		137
EX-4.1
EX-10.6.A
EX-10.6.B
EX-10.7.A
EX-10.7.B
EX-10.10.B
EX-10.10.C
EX-10.12
EX-10.13
EX-10.14.E
EX-10.14.F
EX-10.15
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
TXU Gas		TXU Gas Company, which was acquired on October 1, 2004
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. 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 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 and earnings. 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 four 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.

	•	The natural gas marketing segment, which includes a variety of nonregulated natural gas management services.


	•	The pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage 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 Colorado-Kansas Division and

	•	Atmos Energy Mississippi 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. 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, 2010 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 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 2010 were Anadarko Energy Services, BP Energy Company, 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, Texla Energy Management, Inc. and Atmos Energy Marketing, LLC, our natural gas marketing subsidiary.

The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments. We estimate our peak-day availability of natural gas supply to be approximately 4.2 Bcf. The peak-day demand for our natural gas distribution operations in fiscal 2010 was on January 8, 2010, when sales to customers reached approximately 4.0 Bcf.

Currently, all of our natural gas distribution divisions, except for our Mid-Tex Division, utilize 39 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 solely 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.

The following briefly describes 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, 2010, we held 1,115 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 2008, we reached a settlement with cities representing approximately 80 percent of this division’s customers (Settled Cities) that has allowed us, beginning in 2008, to update rates for customers in these cities through an annual rate review mechanism. 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.

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.

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 natural gas marketing 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 2008 and its Amarillo and Lubbock service areas during 2009 to update rates for customers in these service areas through an annual rate review mechanism.

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.

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.

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 on
Division	Jurisdiction	Rate/GRIP Action		(thousands)⁽¹⁾	Return⁽¹⁾	Equity⁽¹⁾

Atmos Pipeline — Texas	Texas		05/24/2004	$417,111	8.258%	10.00%
Atmos Pipeline — Texas — GRIP	Texas		04/20/2010	799,841	8.258%	10.00%
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	88,583⁽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	184,697	(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		04/01/2010	96,400	8.22%	10.00% - 10.80%
	LGS		07/01/2010	251,591	8.54%	10.40%
Mid-Tex — Settled Cities	Texas		10/01/2010	(2)	8.19%	9.60%
Mid-Tex — Dallas & Environs	Texas		01/26/2010	1,279,647⁽⁴⁾	8.60%	10.40%
Mid-Tex — Dallas & Environs — GRIP	Texas		09/01/2010	1,283,357⁽⁴⁾	8.60%	10.40%
Mississippi	Mississippi		12/15/2009	227,055	8.27%	10.04%
West Texas	Amarillo		08/01/2010	55,537	8.19%	9.60%
	Lubbock		09/01/2010	57,074	8.19%	9.60%
	West Texas		08/15/2010	135,565	8.19%	9.60%

Authorized Debt/

Bad Debt

Performance-Based

Customer

Division

Jurisdiction

Equity Ratio

Rider⁽⁵⁾

WNA

Rate Program⁽⁶⁾

Meters

Atmos Pipeline — Texas

Texas

50/50

N/A

Colorado-Kansas

Colorado

50/50

Yes

⁽⁷⁾

110,646

Kansas

(2)

Yes

128,640

Kentucky/Mid-States

Georgia

52/48

Yes

64,946

Illinois

67/33

22,868

Iowa

57/43

4,300

Kentucky

(2)

Yes

176,634

Missouri

49/51

56,843

Tennessee

52/48

Yes

132,261

Virginia

51/49

Yes

23,163

Louisiana

Trans LA

52/48

Yes

76,653

LGS

52/48

Yes

277,551

Mid-Tex — Settled Cities

Texas

52/48

Yes

1,236,538

Mid-Tex — Dallas & Environs

Texas

51/49

Yes

309,134

Mississippi

52/48

Yes

266,233

West Texas

Amarillo

52/48

Yes

70,578

Lubbock

52/48

Yes

73,810

West Texas

52/48

Yes

155,242


⁽¹⁾		The rate base, authorized rate of return and authorized return on equity presented in this table are those from the last 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 $28.4 million included in the October 2010 Pipeline Replacement Program (PRP) surcharge. The $28.4 million of the Georgia rate base amount was awarded in the latest PRP annual filing with an effective date of October 1, 2010, an authorized rate of return of 8.56 percent and an authorized return on equity of 10.70 percent.

⁽⁴⁾		The Mid-Tex Rate Base amounts for the Dallas & Environs areas represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.

⁽⁵⁾		The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.

⁽⁶⁾		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.

⁽⁷⁾		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


	Fiscal Year Ended September 30
	2010			2009			2008			2007			2006

METERS IN SERVICE, end of year
Residential		2,910,672			2,901,577			2,911,475			2,893,543			2,886,042
Commercial		262,778			265,843			268,845			272,081			275,577
Industrial		2,090			2,193			2,241			2,339			2,661
Public authority and other		10,500			9,231			9,218			19,164			16,919

Total meters		3,186,040			3,178,844			3,191,779			3,187,127			3,181,199

INVENTORY STORAGE BALANCE — Bcf		54.3			57.0			58.3			58.0			59.9

HEATING DEGREE DAYS⁽¹⁾
Actual (weighted average)		2,780			2,713			2,820			2,879			2,527
Percent of normal		102	%		100	%		100	%		100	%		87	%
SALES VOLUMES — MMcf⁽²⁾
Gas Sales Volumes
Residential		190,424			159,762			163,229			166,612			144,780
Commercial		103,028			91,379			93,953			95,514			87,006
Industrial		19,047			18,563			21,734			22,914			26,161
Public authority and other		10,129			12,413			13,760			12,287			14,086

Total gas sales volumes		322,628			282,117			292,676			297,327			272,033
Transportation volumes		135,865			130,691			141,083			135,109			126,960

Total throughput		458,493			412,808			433,759			432,436			398,993

OPERATING REVENUES (000’s)⁽²⁾
Gas Sales Revenues
Residential	$	1,826,752		$	1,830,140		$	2,131,447		$	1,982,801		$	2,068,736
Commercial		808,981			838,184			1,077,056			970,949			1,061,783
Industrial		112,366			135,633			212,531			195,060			276,186
Public authority and other		70,580			89,183			137,821			114,298			144,600

Total gas sales revenues		2,818,679			2,893,140			3,558,855			3,263,108			3,551,305
Transportation revenues		62,254			59,914			60,504			59,813			62,215
Other gas revenues		31,560			31,711			35,771			35,844			37,071

Total operating revenues	$	2,912,493		$	2,984,765		$	3,655,130		$	3,358,765		$	3,650,591

Average transportation revenue per Mcf	$	0.46		$	0.46		$	0.43		$	0.44		$	0.49
Average cost of gas per Mcf sold	$	5.77		$	6.95		$	9.05		$	8.09		$	10.02
Employees		4,714			4,691			4,558			4,472			4,402

See footnotes following these tables.

Natural Gas Distribution Sales and Statistical Data by Division


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

METERS IN SERVICE
Residential		1,429,287			424,048			331,784			271,418			216,831			237,304			—			2,910,672
Commercial		116,240			52,938			22,420			24,919			20,741			25,520			—			262,778
Industrial		145			862			—			484			86			513			—			2,090
Public authority and other		—			2,733			—			2,809			2,062			2,896			—			10,500

Total		1,545,672			480,581			354,204			299,630			239,720			266,233			—			3,186,040

HEATING DEGREE DAYS⁽¹⁾
Actual		2,100			3,924			1,532			3,537			5,909			2,734			—			2,780
Percent of normal		103	%		100	%		96	%		99	%		106	%		102	%		—			102	%
SALES VOLUMES — MMcf⁽²⁾
Gas Sales Volumes
Residential		92,489			27,917			15,810			19,772			18,661			15,775			—			190,424
Commercial		55,916			16,841			7,821			7,892			7,349			7,209			—			103,028
Industrial		3,227			5,931			—			4,317			148			5,424			—			19,047
Public authority and other		—			1,444			—			3,482			2,100			3,103			—			10,129

Total		151,632			52,133			23,631			35,463			28,258			31,511			—			322,628
Transportation volumes		45,822			43,782			5,626			22,429			12,655			5,551			—			135,865

Total throughput		197,454			95,915			29,257			57,892			40,913			37,062			—			458,493

OPERATING MARGIN (000’s)⁽²⁾	$	475,852		$	169,516		$	123,344		$	105,476		$	81,056		$	94,203		$	—		$	1,049,447
OPERATING EXPENSES (000’s)⁽²⁾
Operation and maintenance	$	145,166		$	63,665		$	43,604		$	36,696		$	31,233		$	41,542		$	976		$	362,882
Depreciation and amortization	$	89,411		$	33,267		$	22,986		$	15,881		$	16,352		$	12,621		$	—		$	190,518
Taxes, other than income	$	106,620		$	14,718		$	10,995		$	19,390		$	8,271		$	13,599		$	—		$	173,593
OPERATING INCOME (000’s)⁽²⁾	$	134,655		$	57,866		$	45,759		$	33,509		$	25,200		$	26,441		$	(976	)	$	322,454
CAPITAL EXPENDITURES (000’s)	$	196,109		$	62,808		$	47,193		$	39,387		$	29,792		$	28,538		$	33,988		$	437,815
PROPERTY, PLANT AND
EQUIPMENT, NET (000’s)	$	1,761,087		$	750,225		$	413,189		$	319,053		$	300,380		$	284,195		$	130,983		$	3,959,112
OTHER STATISTICS, at year end
Miles of pipe		29,156			12,196			8,381			7,666			7,175			6,546			—			71,120
Employees		1,650			587			439			344			284			371			1,039			4,714

See footnotes following these tables.


	Fiscal Year Ended September 30, 2009
				Kentucky/						West			Colorado-
	Mid-Tex			Mid-States			Louisiana			Texas			Kansas			Mississippi			Other⁽³⁾			Total

METERS IN SERVICE
Residential		1,417,869			423,829			333,224			270,757			218,609			237,289			—			2,901,577
Commercial		116,480			53,386			22,769			24,986			22,080			26,142			—			265,843
Industrial		148			909			—			508			96			532			—			2,193
Public authority and other		—			2,555			—			2,839			1,015			2,822			—			9,231

Total		1,534,497			480,679			355,993			299,090			241,800			266,785			—			3,178,844

HEATING DEGREE DAYS⁽¹⁾
Actual		2,036			3,853			1,574			3,553			5,520			2,746			—			2,713
Percent of normal		100	%		98	%		101	%		99	%		100	%		103	%		—			100	%
SALES VOLUMES — MMcf⁽²⁾
Gas Sales Volumes
Residential		73,678			26,589			12,371			16,341			17,280			13,503			—			159,762
Commercial		48,363			16,049			6,771			6,780			6,848			6,568			—			91,379
Industrial		2,918			6,217			—			3,528			196			5,704			—			18,563
Public authority and other		—			1,434			—			6,014			2,064			2,901			—			12,413

Total		124,959			50,289			19,142			32,663			26,388			28,676			—			282,117
Transportation volumes		44,991			41,693			5,151			23,417			10,471			4,968			—			130,691

Total throughput		169,950			91,982			24,293			56,080			36,859			33,644			—			412,808

OPERATING MARGIN (000’s)⁽²⁾	$	483,155		$	163,602		$	118,021		$	89,982		$	78,188		$	91,680		$	—		$	1,024,628
OPERATING EXPENSES (000’s)⁽²⁾
Operation and maintenance	$	150,978		$	68,823		$	41,956		$	35,126		$	32,935		$	43,642		$	(4,031	)	$	369,429
Depreciation and amortization	$	94,040		$	32,755		$	22,492		$	15,242		$	15,334		$	12,411		$	—		$	192,274
Taxes, other than income	$	108,412		$	13,261		$	9,629		$	15,863		$	8,222		$	13,925		$	—		$	169,312
Asset impairments	$	2,100		$	785		$	510		$	413		$	376		$	415		$	—		$	4,599
OPERATING INCOME (000’s)⁽²⁾	$	127,625		$	47,978		$	43,434		$	23,338		$	21,321		$	21,287		$	4,031		$	289,014
CAPITAL EXPENDITURES (000’s)	$	173,201		$	57,943		$	42,626		$	33,960		$	24,726		$	22,173		$	24,871		$	379,500
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)	$	1,615,900		$	722,530		$	390,957		$	299,242		$	284,398		$	266,053		$	124,391		$	3,703,471
OTHER STATISTICS, at year end
Miles of pipe		28,996			12,158			8,321			7,702			7,162			6,540			—			70,879
Employees		1,585			605			446			352			290			389			1,024			4,691

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 arrangements, lending and sales of excess gas. 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
	2010		2009		2008		2007		2006

CUSTOMERS, end of year
Industrial		65		68		62		65		67
Other		176		168		189		196		178

Total		241		236		251		261		245

PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾		634,885		706,132		782,876		699,006		581,272
OPERATING REVENUES (000’s)⁽¹⁾	$	203,013	$	209,658	$	195,917	$	163,229	$	141,133
Employees, at year end		62		62		60		54		85


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

Natural Gas Marketing Segment Overview

Our natural gas marketing activities are conducted through Atmos Energy Marketing (AEM), which is wholly-owned by Atmos Energy Holdings, Inc. (AEH). AEH is a wholly-owned subsidiary of AEC and operates primarily in the Midwest and Southeast areas of the United States.

AEM’s primary business is to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. In addition, AEM utilizes proprietary and customer-owned transportation and storage assets to provide various 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. AEM serves most of its customers under contracts generally having one to two year terms and sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms ranging from 30 days to two years. As a result, AEM’s 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.

AEM also seeks to maximize, through asset optimization activities, the economic value associated with the storage and transportation capacity we own or control in our natural gas distribution and natural gas marketing segments. We attempt to meet this objective 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 AEM has access and selling financial instruments at advantageous prices to lock in a gross profit margin.

Natural Gas Marketing Sales and Statistical Data


	Fiscal Year Ended September 30
	2010		2009		2008		2007		2006

CUSTOMERS, end of year
Industrial		652		631		624		677		679
Municipal		61		63		55		68		73
Other		339		321		312		281		289

Total		1,052		1,015		991		1,026		1,041

INVENTORY STORAGE BALANCE — Bcf		15.8		17.0		11.0		19.3		15.3
NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽¹⁾		420,203		441,081		457,952		423,895		336,516
OPERATING REVENUES (000’s)⁽¹⁾	$	2,151,264	$	2,336,847	$	4,287,862	$	3,151,330	$	3,156,524


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

Pipeline, Storage and Other Segment Overview

Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. APS is engaged in nonregulated transmission, storage and natural gas gathering services. Its primary asset is a proprietary 21 mile pipeline located in New Orleans, Louisiana. It also owns or controls additional pipeline and storage capacity including interests in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for pipeline capacity to meet customer demand during peak periods.

APS’ primary business is to provide storage and transportation services to our Louisiana and Kentucky/Mid-States regulated natural gas distribution divisions, to our natural gas marketing segment and, on a more limited basis, to third parties. APS earns transportation fees and storage demand charges to aggregate and provide gas supply, provide access to storage capacity and transport gas for these customers.

APS also engages in various asset optimization activities. APS’ primary asset optimization activity involves the administration of two asset management plans with regulated affiliates of the Company. These arrangements provide APS the opportunity to maximize the economic value associated with the transportation and storage capacity assigned to these plans. APS attempts to meet this objective through a variety of activities including engaging in natural gas storage transactions and utilizing excess asset capacity to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. These plans require APS to share a portion of the economic value created by these activities with the regulated customers served by these affiliates. These arrangements have been approved by applicable state regulatory commissions and are subject to annual regulatory review intended to ensure proper allocation of economic value between our regulated customers and APS.

APS also seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. We attempt to meet this objective 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 APS has access and, in transactions involving storage capacity, selling financial instruments at advantageous prices to lock in a gross profit margin.

Pipeline, Storage and Other Sales and Statistical Data


	Fiscal Year Ended September 30
	2010		2009		2008		2007		2006

OPERATING REVENUES (000’s)⁽¹⁾	$	35,318	$	41,924	$	31,709	$	33,400	$	25,574
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾		7,375		6,395		5,492		7,710		9,712
INVENTORY STORAGE BALANCE — Bcf		2.1		2.9		1.4		2.0		2.6


⁽¹⁾		Transportation volumes and operating revenues 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 current rate strategy is to focus 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 two-thirds of our gross margin. We also have accelerated recovery of only capital for approximately 20 percent of our gross margin. Combined, we have rate structures with accelerated recovery of all or a portion of our expenditures for over 80 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 70 percent of our gross margin. These mechanisms work in tandem to provide 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’ 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, 2010, 2009 and 2008 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 $56.8 million, $54.4 million and $40.6 million, became effective in fiscal 2010, 2009 and 2008 as summarized below:


	Annual Increase to Operating
	Income For the Fiscal Year Ended September 30
Rate Action	2010		2009		2008
	(In thousands)

Rate case filings	$	23,663	$	2,959	$	27,838
GRIP filings		16,751		11,443		8,101
Annual rate filing mechanisms		13,757		38,764		3,275
Other rate activity		2,630		1,237		1,424

	$	56,801	$	54,403	$	40,638

Additionally, the following ratemaking efforts were initiated during fiscal 2010 but had not been completed as of September 30, 2010:


			Operating Income
Division	Rate Action	Jurisdiction	Requested
			(In thousands)

Atmos Pipeline — Texas	Rate Case	Texas Railroad Commission	$	38,922
Kentucky/Mid-States	PRP Surcharge⁽¹⁾	Georgia		764
Mississippi	Stable Rate Filing	Mississippi		—
Mid-Tex⁽²⁾	Rate Review Mechanism	Settled Cities		56,827

			$	96,513


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

⁽²⁾		The Company filed a Rate Review Mechanism (RRM) with the Mid-Tex Settled Cities requesting an operating income increase of $56.8 million. A settlement was reached, effective October 1, 2010, which resolves all issues in the annual RRM filing and increases operating income by $23.1 million. Additionally, the settlement allows the Mid-Tex Division to expand its existing program to replace steel service lines which will replace approximately 100,000 steel service lines by September 30, 2012 at a total projected capital cost of $80-$120 million, utilizing an authorized return on equity of 9.0 percent, with the equity portion of the return based on the actual capital structure up to a maximum of 50 percent.

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 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)

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

2008 Rate Case Filings:
Kentucky/Mid-States	Virginia	$	869		09/30/2008
Kentucky/Mid-States	Georgia		3,351		09/22/2008
Mid-Tex⁽²⁾	Texas		5,430		06/24/2008
Colorado-Kansas	Kansas		2,100		05/12/2008
Mid-Tex⁽³⁾	Texas		8,000		04/01/2008
Kentucky/Mid-States	Tennessee		8,088		11/04/2007

Total 2008 Rate Case Filings		$	27,838


⁽¹⁾		In its final order, the Railroad Commission of Texas (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.

⁽²⁾		Increase relates only to the City of Dallas and the unincorporated areas of the Mid-Tex Division.

⁽³⁾		Increase relates only to the Settled Cities area of the Mid-Tex Division.

GRIP Filings

As discussed above in “Natural Gas Distribution Segment Overview,” GRIP allows natural gas utility companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. The following table summarizes our GRIP filings with effective dates during the fiscal years ended September 30, 2010, 2009 and 2008:


				Additional
		Incremental Net		Annual
		Utility Plant		Operating		Effective
Division	Calendar Year	Investment		Income		Date
		(In thousands)		(In thousands)

2010 GRIP:
Mid-Tex⁽¹⁾	2009	$	16,957	$	2,983	09/01/2010
West Texas	2009		19,158		363	06/14/2010
Atmos Pipeline — Texas	2009		95,504		13,405	04/20/2010

Total 2010 GRIP		$	131,619	$	16,751

2009 GRIP:
Mid-Tex⁽²⁾	2008	$	105,777	$	2,732	09/09/2009
Atmos Pipeline — Texas	2008		51,308		6,342	04/28/2009
Mid-Tex⁽¹⁾	2007		57,385		1,837	01/26/2009
West Texas⁽³⁾	2007/08		27,425		532	Various

Total 2009 GRIP		$	241,895	$	11,443

2008 GRIP:
Atmos Pipeline — Texas	2007	$	46,648	$	6,970	04/15/2008
West Texas	2006		7,022		1,131	12/17/2007

Total 2008 GRIP		$	53,670	$	8,101


⁽¹⁾		Increase relates to the City of Dallas and Environs areas of the Mid-Tex Division.

⁽²⁾		Increase relates only to the City of Dallas area of the Mid-Tex Division.

⁽³⁾		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 rate stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms:

Additional

Annual

Operating

Effective

Division

Jurisdiction

Test Year Ended

Income

Date

(In thousands)

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

2008 Filings:

Louisiana

LGS

12/31/2007

1,709

07/01/2008

Louisiana

TransLa

09/30/2007

1,566

04/01/2008

Total 2008 Filings

3,275

In August 2010, we reached an agreement to extend the rate review mechanism 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 rate review mechanism process.

The West Texas rate review mechanism was entered into in August 2008 as a result of a settlement with the West Texas Coalition of Cities. The Lubbock and Amarillo rate review mechanisms 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 year’s filing.

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2010, 2009 and 2008:


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

2010 Other Rate Activity:
Kentucky/Mid-States	Missouri	ISRS⁽¹⁾	$	563		03/02/2010
Colorado-Kansas	Kansas	Ad Valorem⁽²⁾		392		01/05/2010
Colorado-Kansas	Kansas	GSRS⁽³⁾		766		12/12/2009
Kentucky/Mid-States	Georgia	PRP Surcharge⁽⁴⁾		909		10/01/2009

Total 2010 Other Rate Activity			$	2,630

2009 Other Rate Activity:
Colorado-Kansas	Kansas	Tax Surcharge⁽⁵⁾	$	631		02/01/2009
Kentucky/Mid-States	Missouri	ISRS⁽¹⁾		408		11/04/2008
Kentucky/Mid-States	Georgia	PRP Surcharge⁽⁴⁾		198		10/01/2008

Total 2009 Other Rate Activity			$	1,237

2008 Other Rate Activity:
West Texas	Triangle	Special Contract	$	748		06/01/2008
Colorado-Kansas	Kansas	Tax Surcharge⁽⁵⁾		1,434		01/01/2008
Colorado-Kansas	Colorado	Agreement⁽⁶⁾		(1,100	)	11/20/2007
Kentucky/Mid-States	Georgia	PRP Surcharge⁽⁴⁾		342		10/01/2007

Total 2008 Other Rate Activity			$	1,424


⁽¹⁾		Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

⁽²⁾		The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in the Company’s base rates.

⁽³⁾		Gas System Reliability Surcharge (GSRS) relates to safety related investments made since the previous rate case.

⁽⁴⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽⁵⁾		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.

⁽⁶⁾		In November 2007, the Colorado Public Utilities Commission approved an earnings agreement entered into jointly between the Colorado-Kansas Division, the Commission Staff and the Office of Consumer Counsel. The agreement called for a one-time refund to customers of $1.1 million made in January 2008.

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.

We have been replacing certain steel service lines in our Mid-Tex Division since our acquisition of the natural gas distribution system in 2004. We currently have an existing RRM that should allow us to recover the replacement costs through the end of fiscal 2012. On September 10, 2010, the Texas Railroad Commission (RRC) published for comment a proposed regulation dealing with distribution facility replacement. The proposed regulation would require each gas distribution system operator to develop a risk-based program for the removal or replacement of distribution facilities, including steel service lines. A number of Texas operators, industry groups and facility component manufacturers filed comments. The RRC is presently reviewing the comments with action related to this proposal anticipated later this year or early next year. We are committed to replacing the steel service lines on an accelerated schedule to ensure the safety and reliability of our distribution system, and as part of this commitment, we support the objectives of proposed rulemaking by the RRC for steel service-line replacements statewide. Due to the preliminary status of the rulemaking process, we cannot accurately anticipate the impact the proposed regulation would have on the Company, if adopted, or the expected cost of the replacement program.

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. However, higher gas prices, coupled with the electric utilities’ marketing efforts, have increased competition for residential and commercial customers.

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 two 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, 2010, we had 4,913 employees, consisting of 4,776 employees in our regulated operations and 137 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 2010, Robert W. Best, certified to the New York Stock Exchange that he was not aware of any violation 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.

Historically, we have accessed the commercial paper markets to finance our short-term working capital needs. The disruptions in the credit markets during the fall of 2008 temporarily limited our access to the commercial paper markets and increased our borrowing costs. Consequently, for a short period, we were forced to borrow directly under our primary credit facility that backstops our commercial paper program to provide much of our working capital. This credit facility provides up to $567 million in committed financing through its expiration in December 2011. Our borrowings under this facility, along with our commercial paper, have been used primarily to purchase natural gas supplies for the upcoming winter heating season. The amount of our working capital requirements in the near-term will depend primarily on the market price of natural gas. Higher natural gas prices may adversely impact our accounts receivable collections and may require us to increase borrowings under our credit facilities to fund our operations. We have historically supplemented our commercial paper program with a short-term committed credit facility. No borrowings are currently

outstanding under our current $200 million short-term facility, which was scheduled to mature in October 2010. In October 2010, this facility was replaced with a $200 million 180-day facility which expires in April 2011, on substantially the same terms.

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 natural gas marketing segment because the commodity financial instruments markets could become unavailable to us. Our natural gas marketing 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 natural gas marketing 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, 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.

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 legislation should not impact the Company until 2014, the future cost of compliance with the provisions of the Health Care Reform Act 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 natural gas marketing and pipeline, storage and other segments.

Our natural gas marketing and pipeline, storage and other segments manage margins and limit 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 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 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 77,000 miles of pipeline and distribution lines. The steel service line replacement program currently underway in our Mid-Tex Division typifies the preventive maintenance and continual renewal that we perform on our natural gas distribution system in all 12 states in which we 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. Accordingly, the costs of complying with such increased regulations may have at least a short-term adverse impact on our operating costs and financial results.

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

FERC has regulatory authority 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. In addition, 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 natural gas marketing 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.

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 two fiscal years 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 two 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, 2010, our natural gas distribution segment owned an aggregate of 71,120 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 5,924 miles of gas transmission and gathering lines and our pipeline, storage and other segment owned 113 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, 2010:


							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
Pipeline, Storage and Other 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, 2010:


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

Natural Gas Distribution Segment
	Colorado-Kansas Division		4,237,243		108,232
	Kentucky/Mid-States Division		16,993,683		343,746
	Louisiana Division		2,608,255		159,620
	Mississippi Division		3,875,429		165,402
	West Texas Division		2,125,000		76,000

Total			29,839,610		853,000
Natural Gas Marketing Segment	Atmos Energy Marketing, LLC		8,026,869		250,937
Pipeline, Storage and Other Segment	Trans Louisiana Gas Pipeline, Inc.		1,674,000		67,507

Total Contracted Storage Capacity			39,540,479		1,171,444


⁽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.

Other facilities

Our natural gas distribution segment owns and operates one propane peak shaving plant with a total capacity of approximately 180,000 gallons that can produce an equivalent of approximately 3,300 Mcf daily.

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 12 to the consolidated financial statements.


ITEM 4.	*Submission of Matters to a Vote of Security Holders.*

No matters were submitted to a vote of security holders during the fourth quarter of fiscal 2010.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2010, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.


			Years of
Name	Age		Service		Office Currently Held

Robert W. Best		63		13	Chairman and Chief Executive Officer
Kim R. Cocklin		59		4	President and Chief Operating Officer
Louis P. Gregory		55		10	Senior Vice President and General Counsel
Michael E. Haefner		50		2	Senior Vice President, Human Resources
Fred E. Meisenheimer		66		10	Senior Vice President, Chief Financial Officer and Treasurer

Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997. From October 1, 2008 through September 30, 2010, Mr. Best continued to serve the Company as Chairman of the Board and Chief Executive Officer. On October 1, 2010, Mr. Best was named Executive Chairman of the Board.

Kim R. Cocklin was named President and Chief Executive Officer effective October 1, 2010. Mr. Cocklin joined the Company in June 2006 and served as President and Chief Operating Officer of the Company from October 1, 2008 through September 30, 2010, after having served as Senior Vice President, Regulated Operations from October 2006 through September 2008. Mr. Cocklin was Senior Vice President, General Counsel and Chief Compliance Officer of Piedmont Natural Gas Company from February 2003 through May 2006. Mr. Cocklin was also appointed to the Board of Directors on November 10, 2009.

Louis P. Gregory was named Senior Vice President and General Counsel in September 2000.

Michael E. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources. Prior to joining the Company, Mr. Haefner was a self-employed consultant and founder and president of Perform for Life, LLC from May 2007 to May 2008. Mr. Haefner previously served for 10 years as the Senior Vice President, Human Resources, of Sabre Holding Corporation, the parent company of Sabre Airline Solutions, Sabre Travel Network and Travelocity.

Fred E. Meisenheimer was named Senior Vice President and Chief Financial Officer in February 2009 and Treasurer in November 2009. Mr. Meisenheimer previously served the Company as Vice President and Controller from July 2000 through May 2009 and also served as interim Chief Financial Officer in January 2009.

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 2010 and 2009 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:


	2010						2009
					Dividends						Dividends
	High		Low		paid		High		Low		Paid

Quarter ended:
December 31	$	30.06	$	27.39	$	.335	$	27.88	$	21.17	$	.330
March 31		29.52		26.52		.335		25.95		20.20		.330
June 30		29.98		26.41		.335		26.37		22.81		.330
September 30		29.81		26.82		.335		28.80		24.65		.330

					$	1.34					$	1.32

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, 2010 was 19,772. 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 2010 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, 2005 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
	9/30/05		9/30/06		9/30/07		9/30/08		9/30/09		9/30/10

Atmos Energy Corporation		100.00		105.89		109.44		107.92		120.52		131.27
S&P 500		100.00		110.79		129.01		100.66		93.70		103.22
Peer Group		100.00		99.04		115.40		102.25		103.34		126.98

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, 2010.

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

434,962

22.46

848,730

Total equity compensation plans approved by security holders

434,962

22.46

848,730

Equity compensation plans not approved by security holders

—

Total

434,962

22.46

848,730


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
	2010			2009⁽¹⁾			2008			2007⁽¹⁾			2006 ⁽¹⁾
	(In thousands, except per share data and ratios)

Results of Operations
Operating revenues	$	4,789,690		$	4,969,080		$	7,221,305		$	5,898,431		$	6,152,363
Gross profit		1,364,941			1,346,702			1,321,326			1,250,082			1,216,570
Operating expenses⁽¹⁾		875,505			899,300			893,431			851,446			833,954
Operating income		489,436			447,402			427,895			398,636			382,616
Miscellaneous income (expense)		(339	)		(3,303	)		2,731			9,184			881
Interest charges		154,471			152,830			137,922			145,236			146,607
Income before income taxes		334,626			291,269			292,704			262,584			236,890
Income tax expense		128,787			100,291			112,373			94,092			89,153
Net income	$	205,839		$	190,978		$	180,331		$	168,492		$	147,737
Weighted average diluted shares outstanding		92,422			91,620			89,941			87,486			81,173
Diluted net income per share	$	2.20		$	2.07		$	1.99		$	1.91		$	1.81
Cash flows from operations	$	726,476		$	919,233		$	370,933		$	547,095		$	311,449
Cash dividends paid per share	$	1.34		$	1.32		$	1.30		$	1.28		$	1.26
Total natural gas distribution throughput (MMcf)⁽²⁾		454,175			408,885			429,354			427,869			393,995
Total regulated transmission and storage transportation volumes (MMcf)⁽²⁾		428,599			528,689			595,542			505,493			410,505
Total natural gas marketing sales volumes (MMcf)⁽²⁾		353,853			370,569			389,392			370,668			283,962
Financial Condition
Net property, plant and equipment	$	4,793,075		$	4,439,103		$	4,136,859		$	3,836,836		$	3,629,156
Working capital		(290,887	)		91,519			78,017			149,217			(1,616	)
Total assets		6,763,791			6,367,083			6,386,699			5,895,197			5,719,547
Short-term debt, inclusive of current maturities of long-term debt		486,231			72,681			351,327			154,430			385,602
Capitalization:
Shareholders’ equity		2,178,348			2,176,761			2,052,492			1,965,754			1,648,098
Long-term debt (excluding current maturities)		1,809,551			2,169,400			2,119,792			2,126,315			2,180,362

Total capitalization		3,987,899			4,346,161			4,172,284			4,092,069			3,828,460
Capital expenditures		542,636			509,494			472,273			392,435			425,324
Financial Ratios
Capitalization ratio⁽³⁾		48.7	%		49.3	%		45.4	%		46.3	%		39.1	%
Return on average shareholders’ equity⁽⁴⁾		9.1	%		8.9	%		8.8	%		8.8	%		8.9	%


⁽¹⁾		Financial results for 2009, 2007 and 2006 include a $5.4 million, $6.3 million and a $22.9 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.


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, especially those discussed in Item 1A above, 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 quarterly. 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 pipeline, storage and other segments are recognized in the period in which actual volumes are transported and storage services are provided.

Operating revenues for our natural gas marketing 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 natural gas marketing 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 both our natural gas marketing segment and pipeline, storage and other segment. 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 natural gas marketing and pipeline, storage and other segments, we have designated the natural gas inventory held by these operating segments 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 natural gas marketing 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 natural gas marketing 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 a cash flow hedge of an anticipated transaction at the time the agreements are executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income (loss). The realized gain or loss recognized upon settlement of each Treasury lock agreement was 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.

Impairment assessments — We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. As of September 30, 2010, 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 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. Prior to fiscal 2009, we reviewed the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities annually based upon a June 30 measurement date. Effective October 1, 2008, we changed our measurement date to September 30. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement 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 return on plan assets and the 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 $0.9 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 61 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 the current year, colder-than-normal weather and recent improvements in rate designs in our natural gas distribution segment partially offset the decline in demand for natural gas, which contributed to a 19 percent year-over-year decrease in consolidated throughput in our regulated transmission and storage segment and a 5 percent year-over-year decrease in consolidated sales volumes in our natural gas marketing segment.

During the year, we continued to successfully access the capital markets and received updated debt ratings from three rating agencies. In December 2009 we renewed a $450 million 364-day committed credit facility for our nonregulated operations. In March 2010, Moody’s upgraded our rating outlook from stable to positive and affirmed the existing credit rating on our senior long-term debt and commercial paper while S&P affirmed our rating outlook as stable and our senior long-term debt credit rating. In June 2010, Fitch upgraded our rating outlook from stable to positive and affirmed the existing credit rating on our senior unsecured debt and commercial paper. In October 2010, we replaced our $200 million 364-day revolving credit agreement prior to its expiration with a $200 million 180-day revolving credit agreement. The new credit facilities should help ensure we have sufficient liquidity to fund our working capital needs, while our credit ratings should help us continue to obtain financing at a reasonable cost in the future.

On July 1, 2010, we entered into an accelerated share repurchase program with Goldman Sachs & Co. as part of our ongoing efforts to improve shareholder value. The shares that will be repurchased under this program should offset the dilutive impact of stock grants made under our various employee and director incentive compensation plans. The impact of the shares repurchased under the program during fiscal 2010 increased diluted earnings per share by approximately $0.01.

Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2010, 2009 and 2008.


	For the Fiscal Year Ended September 30
	2010			2009			2008
	(In thousands, except per share data)

Operating revenues	$	4,789,690		$	4,969,080		$	7,221,305
Gross profit		1,364,941			1,346,702			1,321,326
Operating expenses		875,505			899,300			893,431
Operating income		489,436			447,402			427,895
Miscellaneous income (expense)		(339	)		(3,303	)		2,731
Interest charges		154,471			152,830			137,922
Income before income taxes		334,626			291,269			292,704
Income tax expense		128,787			100,291			112,373
Net income	$	205,839		$	190,978		$	180,331
Earnings per diluted share	$	2.20		$	2.07		$	1.99

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 81 percent, 83 percent and 74 percent to our consolidated net income for fiscal years 2010, 2009, and 2008. 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
	2010		2009		2008
	(In thousands)

Natural gas distribution segment	$	125,949	$	116,807	$	92,648
Regulated transmission and storage segment		41,486		41,056		41,425
Natural gas marketing segment		27,729		20,194		29,989
Pipeline, storage and other segment		10,675		12,921		16,269

Net income	$	205,839	$	190,978	$	180,331

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
	2010		2009		2008
	(In thousands, except per share data)

Regulated operations	$	167,435	$	157,863	$	134,073
Nonregulated operations		38,404		33,115		46,258

Consolidated net income	$	205,839	$	190,978	$	180,331

Diluted EPS from regulated operations	$	1.79	$	1.71	$	1.48
Diluted EPS from nonregulated operations		0.41		0.36		0.51

Consolidated diluted EPS	$	2.20	$	2.07	$	1.99

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 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 margins totaled $4.3 million which reduced earnings per share by $0.05 per diluted share compared to the prior year, when net unrealized losses totaled $21.6 million, which reduced earnings per share by $0.23 per diluted share.

Net income in both periods was impacted by nonrecurring items. The current year period includes the positive impact of a state sales tax refund of $4.6 million, or $0.05 per diluted share. Net income in the prior-year period included the net positive impact of several one-time items totaling $17.1 million, or $0.19 per diluted share related to the following pre-tax amounts:


	•	$11.3 million related to a favorable one-time tax benefit.

	•	$7.6 million related to the favorable impact of an update to the estimate for unbilled accounts.

	•	$7.0 million favorable impact of the reversal of estimated uncollectible gas costs.

	•	$5.4 million unfavorable impact of a non-cash impairment charge related to available-for-sale securities in our Supplemental Executive Retirement Plan.

Net income during fiscal 2009 increased six percent over fiscal 2008, driven largely from an 18 percent increase in net income from regulated operations during fiscal 2009. The increase primarily reflects a $32.3 million increase in gross profit resulting from the net favorable impact of various ratemaking activities in our natural gas distribution segment, partially offset by higher depreciation expense, pipeline maintenance costs and interest expense. Net income in our nonregulated operations decreased $13.1 million primarily due to the impact of unrealized margins. Pre-tax unrealized margins totaled $35.9 million which reduced earnings per share by $0.23 per diluted share. The overall increase in consolidated net income was also favorably affected by non-recurring items totaling $17.1 million, or $0.19 per diluted share, related to the items noted above.

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. Prior to January 1, 2009, timing differences existed between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. These timing differences had a significant temporary effect on operating income in periods with volatile gas prices, particularly in our Mid-Tex Division. Beginning January 1, 2009, changes in our franchise fee agreements in our Mid-Tex Division became effective which have significantly reduced the impact of this timing difference. However, this timing difference is still present for gross receipts taxes.

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 65 percent of our residential and commercial margins.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the fiscal years ended September 30, 2010, 2009 and 2008 are presented below.


	For the Fiscal Year Ended September 30
	2010		2009		2008		2010 vs. 2009			2009 vs. 2008
			(In thousands, unless otherwise noted)

Gross profit	$	1,049,447	$	1,024,628	$	1,006,066	$	24,819		$	18,562
Operating expenses		726,993		735,614		744,901		(8,621	)		(9,287	)

Operating income		322,454		289,014		261,165		33,440			27,849
Miscellaneous income		1,384		5,766		9,689		(4,382	)		(3,923	)
Interest charges		118,430		124,055		117,933		(5,625	)		6,122

Income before income taxes		205,408		170,725		152,921		34,683			17,804
Income tax expense		79,459		53,918		60,273		25,541			(6,355	)

Net income	$	125,949	$	116,807	$	92,648	$	9,142		$	24,159

Consolidated natural gas distribution sales volumes — MMcf		322,628		282,117		292,676		40,511			(10,559	)
Consolidated natural gas distribution
transportation volumes — MMcf		131,547		126,768		136,678		4,779			(9,910	)

Total consolidated natural gas distribution throughput — MMcf		454,175		408,885		429,354		45,290			(20,469	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.47	$	0.47	$	0.44	$	—		$	0.03
Consolidated natural gas distribution average cost of gas per Mcf sold	$	5.77	$	6.95	$	9.05	$	(1.18	)	$	(2.10	)

The following table shows our operating income by natural gas distribution division for the fiscal years ended September 30, 2010, 2009 and 2008. 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
	2010			2009		2008		2010 vs. 2009			2009 vs. 2008
	(In thousands)

Mid-Tex	$	134,655		$	127,625	$	115,009	$	7,030		$	12,616
Kentucky/Mid-States		57,866			47,978		48,731		9,888			(753	)
Louisiana		45,759			43,434		39,090		2,325			4,344
West Texas		33,509			23,338		13,843		10,171			9,495
Colorado-Kansas		25,200			21,321		20,615		3,879			706
Mississippi		26,441			21,287		19,970		5,154			1,317
Other		(976	)		4,031		3,907		(5,007	)		124

Total	$	322,454		$	289,014	$	261,165	$	33,440		$	27,849

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

The $24.8 million increase in natural gas distribution gross profit primarily reflects rate adjustments and increased throughput as follows:


	•	$33.7 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana, Kentucky, Tennessee, Virginia and Mississippi service areas.


	•	$11.2 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 $8.6 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.

	•	$4.4 million decrease in contract labor expenses.

	•	$4.4 million decrease in travel, legal and other administrative costs.

These decreases were partially offset by:


	•	$7.4 million increase in employee-related expenses.

	•	$4.3 million increase in taxes, other than income.

Miscellaneous income decreased $4.4 million due to lower interest income. Interest charges decreased $5.6 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.

Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008

The $18.6 million increase in natural gas distribution gross profit primarily reflects an increase in rates. The major components of the increase are as follows:


	•	$13.6 million net increase in rates in the Mid-Tex Division as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all incorporated cities in the division other than the City of Dallas and environs (the Settled Cities) and adjustments for customers in the City of Dallas.

	•	$16.0 million increase in other rate adjustments primarily in Georgia, Kansas, Louisiana and West Texas.

	•	$7.6 million increase attributable to a non-recurring update to our estimate for gas delivered to customers but not yet billed to reflect changes in base rates in several of our jurisdictions recorded in the fiscal first quarter.

	•	$7.0 million uncollectible gas cost accrual recorded in a prior year that was reversed in the current year period.

These increases were partially offset by:


	•	$17.9 million decrease as a result of a five percent decrease in consolidated distribution throughput primarily associated with lower residential, commercial and industrial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.

	•	$10.8 million decrease due to lower revenue related taxes, partially offset by the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income discussed below.


	•	$10.6 million decrease due to lower legal, fuel and other administrative costs.

	•	$9.2 million decrease in allowance for doubtful accounts due to the impact of recent rate design changes in certain jurisdictions that allow us to recover the gas cost portion of uncollectible accounts as well as a 23 percent year-over-year decline in the average cost of gas.

	•	$9.2 million decrease in taxes other than income primarily associated with lower franchise fees and state gross receipt taxes.

These decreases were partially offset by:


	•	$15.1 million increase in depreciation and amortization, due primarily to additional assets placed in service during the current year.

	•	$4.6 million increase due to a noncash charge to impair certain available-for-sale investments as we believed the fair value of these investments would not recover within a reasonable period of time.

As discussed above, the results for fiscal 2009 include a $10.5 million tax benefit in the natural gas distribution segment. In addition, results for fiscal 2008 included a $1.2 million gain on the sale of irrigation assets in our West Texas Division.

Interest charges increased $6.1 million primarily due to the effect of the Company’s March 2009 issuance of $450 million 8.50% senior notes to repay $400 million 4.00% senior notes in April 2009. In addition, we experienced higher average short-term debt balances, interest rates and commitment fees during the current year compared to the prior year.

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 service areas. 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 sole 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, 2010, 2009, and 2008 are presented below.


	For the Fiscal Year Ended September 30
	2010		2009		2008		2010 vs. 2009			2009 vs. 2008
	(In thousands, unless otherwise noted)

Mid-Tex Division transportation	$	102,891	$	89,348	$	86,665	$	13,543		$	2,683
Third-party transportation		73,648		95,314		85,256		(21,666	)		10,058
Storage and park and lend services		10,657		11,858		9,746		(1,201	)		2,112
Other		15,817		13,138		14,250		2,679			(1,112	)

Gross profit		203,013		209,658		195,917		(6,645	)		13,741
Operating expenses		105,975		116,495		106,172		(10,520	)		10,323

Operating income		97,038		93,163		89,745		3,875			3,418
Miscellaneous income		135		1,433		1,354		(1,298	)		79
Interest charges		31,174		30,982		27,049		192			3,933

Income before income taxes		65,999		63,614		64,050		2,385			(436	)
Income tax expense		24,513		22,558		22,625		1,955			(67	)

Net income	$	41,486	$	41,056	$	41,425	$	430		$	(369	)

Gross pipeline transportation volumes — MMcf		634,885		706,132		782,876		(71,247	)		(76,744	)

Consolidated pipeline transportation volumes — MMcf		428,599		528,689		595,542		(100,090	)		(66,853	)

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.

Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008

The $13.7 million increase in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$13.0 million increase from higher demand-based fees.

	•	$5.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions.

	•	$5.4 million increase due to our GRIP filings.

These increases were primarily offset by an $8.4 million decrease associated with a decrease in transportation volumes to our Mid-Tex Division due to warmer weather and a decrease in electrical generation, Barnett Shale and HUB deliveries.

Operating expenses increased $10.3 million primarily due to higher levels of pipeline maintenance activities.

Results for the current-year period also include a $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.

Natural Gas Marketing Segment

AEM’s primary business is to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. In addition, AEM utilizes proprietary and customer-owned transportation and storage assets to provide various 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, AEM’s 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.

AEM seeks to enhance its gross profit margin from delivering gas by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity we own or control in our natural gas distribution and natural gas marketing segments. We attempt to meet this objective 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 AEM has access and selling financial instruments at advantageous prices to lock in a gross profit margin.

AEM continually manages its net physical position to attempt to increase the future economic profit that was created when the original transaction was executed. Therefore, AEM may subsequently change its originally scheduled storage injection and withdrawal plans from one time period to another based on market conditions and recognize any associated gains or losses at that time. If AEM elects to accelerate the withdrawal of physical gas, it will execute new financial instruments to hedge the original financial instruments. If AEM elects to defer the withdrawal of gas, it will reset its positions by settling the original financial instruments and executing new financial instruments to correspond to the revised withdrawal schedule.

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.

AEM 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.

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 natural gas marketing operations. 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 natural gas marketing 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.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the fiscal years ended September 30, 2010, 2009 and 2008 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers 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 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 dependent upon the levels of our net physical position at the end of the reporting period.


	For the Fiscal Year Ended September 30
	2010			2009			2008			2010 vs. 2009			2009 vs. 2008
				(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	59,523		$	75,341		$	73,627		$	(15,818	)	$	1,714
Asset optimization		37,214			37,670			(6,135	)		(456	)		43,805

		96,737			113,011			67,492			(16,274	)		45,519
Unrealized margins		(10,786	)		(28,399	)		25,529			17,613			(53,928	)

Gross profit		85,951			84,612			93,021			1,339			(8,409	)
Operating expenses		31,699			38,208			36,629			(6,509	)		1,579

Operating income		54,252			46,404			56,392			7,848			(9,988	)
Miscellaneous income		2,280			537			2,022			1,743			(1,485	)
Interest charges		9,280			12,911			9,036			(3,631	)		3,875

Income before income taxes		47,252			34,030			49,378			13,222			(15,348	)
Income tax expense		19,523			13,836			19,389			5,687			(5,553	)

Net income	$	27,729		$	20,194		$	29,989		$	7,535		$	(9,795	)

Gross natural gas marketing sales volumes — MMcf		420,203			441,081			457,952			(20,878	)		(16,871	)

Consolidated natural gas marketing sales volumes — MMcf		353,853			370,569			389,392			(16,716	)		(18,823	)

Net physical position (Bcf)		13.7			13.8			8.0			(0.1	)		5.8

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

AEM’s delivered gas business contributed 62 percent of total realized margins during the fiscal year ended September 30, 2010 with asset optimization activities contributing the remaining 38 percent. The $16.3 million decrease in realized gross profit reflected the following:


	•	$15.8 million decrease in realized delivered gas margins due to lower per-unit margins as a result of narrowing basis spreads, combined with lower delivered sales volumes. Per-unit margins were $0.14/Mcf in the current-year period compared with $0.17/Mcf in the prior-year period, while delivered sales volumes were 5 percent lower in the current year when compared with the prior year.

	•	$0.5 million decrease in asset optimization margins primarily due to higher storage demand fees partially offset by higher realized storage and trading gains during the fiscal year.

The decrease in realized gross profit was more than offset by a $17.6 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 $6.5 million primarily due to a decrease in employee and other administrative costs.

Miscellaneous income increased $1.7 million due to proceeds received from a class-action legal settlement in the current year. Interest charges decreased $3.6 million primarily due to a decrease in intercompany borrowings.

Asset Optimization Activities

AEM 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 AEM’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 AEM’s economic value and its potential gross profit (loss) at September 30, 2010 and 2009.


	September 30
	2010			2009
	(In millions, unless otherwise noted)

Economic value	$	(7.8	)	$	28.6
Associated unrealized losses		12.6			11.0

Subtotal		4.8			39.6
Related fees⁽¹⁾		(9.6	)		(14.7	)

Potential gross profit (loss)	$	(4.8	)	$	24.9

Net physical position (Bcf)		13.7			13.8


⁽¹⁾		Related fees represent AEM’s contractual costs to acquire the storage capacity utilized in its 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 AEM has entered into as of September 30, 2010 and 2009.

During the fiscal year ended September 30, 2010, AEM’s economic value decreased from $28.6 million, or $2.07/Mcf at September 30, 2009 to a negative economic value of $7.8 million, or $0.57/Mcf.

Early in the first quarter of fiscal 2010, AEM withdrew gas and realized previously captured spread values. As current cash prices declined during the first fiscal quarter, AEM injected gas and rolled positions into the second fiscal quarter to increase economic value. These positions were settled in the second fiscal quarter and the associated economic value was realized. However, during the year, weak market fundamentals have caused cash prices to remain low and have contracted spot-to-forward spread values, which has limited opportunities to capture economic value. Therefore, during the fiscal third and fourth quarters, AEM elected to forego capturing these narrower spread values and maintained a short-term trading position. We anticipate spot-to-forward spread values will expand in the near term and we expect to be able to roll positions and capture greater economic value than what we can capture as of September 30, 2010. However, the short-dated nature of AEM’s trading positions combined with current short-term forward prices that are lower than the cost of gas that was injected into storage in prior periods resulted in negative economic value as of September 30, 2010.

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 AEM 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 or loss calculated as of September 30, 2010 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, 2009 compared with fiscal year ended September 30, 2008

AEM’s delivered gas business contributed 67 percent to total realized margins during fiscal 2009 with asset optimization activities contributing the remaining 33 percent. In the prior year, delivered gas activities represented substantially all of AEM’s realized gross profit margin. The $45.5 million increase in realized gross profit reflected:


	•	A $43.8 million increase in asset optimization margins. AEM realized substantially all of its realized asset optimization margin in the fiscal 2009 first quarter when it realized substantially all of the economic value that it had captured as of September 30, 2008 from withdrawing gas and settling the associated financial instruments. Since that time, as a result of falling current cash prices, AEM has been deferring storage withdrawals and has been a net injector of gas into storage to increase the economic value it could realize in future periods from its asset optimization activities. In the prior year, AEM deferred storage withdrawals primarily into fiscal 2009 and recognized losses on the settlement of the associated financial instruments.

	•	A $1.7 million increase in realized delivered gas margins. AEM experienced a six percent increase in per-unit margins as a result of improved basis spreads in certain market areas where we were able to better optimize transportation assets and successful contract renewals. These margins improvements more than offset a four percent decrease in gross sales volumes primarily attributable to lower industrial demand as a result of the current economic climate.

The increase in realized gross profit was more than offset by a $53.9 million decrease in unrealized margins attributable to the following:


	•	The realization of unrealized gains recorded during fiscal 2008.

	•	A modest widening of the physical/financial spreads, partially offset by favorable unrealized basis gains in certain markets.

	•	A 5.8 Bcf increase in AEM’s net physical position.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income taxes, and asset impairments increased $1.6 million primarily due the following factors:


	•	$4.0 million increase in legal and other administrative costs.

	•	$2.4 million decrease related to tax matters incurred in the prior year that did not recur in the current year.

Pipeline, Storage and Other Segment

Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS is engaged in nonregulated transmission, storage and natural gas-gathering services. Its primary asset is a proprietary 21 mile pipeline located in New Orleans, Louisiana that is principally used to aggregate gas supply for our regulated natural gas distribution division in Louisiana, our natural gas marketing segment, and, on a more limited basis, for third parties. APS also owns or has an interest in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for additional pipeline capacity to meet customer demand during peak periods.

In addition, APS engages in asset optimization activities whereby it seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. Certain of these arrangements

are with regulated affiliates of the Company which have been approved by applicable state regulatory commissions. Generally, these asset management plans require APS to share with our regulated customers a portion of the profits earned from these arrangements. APS also seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls by engaging in natural gas storage transactions in which it seeks to find and profit from the pricing differences that occur over time.

Results for this segment are primarily impacted by seasonal weather patterns and, similar to our natural gas marketing segment, volatility in the natural gas markets. Additionally, this segment’s results include an unrealized component as APS hedges its risk associated with its asset optimization activities.

Review of Financial and Operating Results

Financial and operational highlights for our pipeline, storage and other segment for the fiscal years ended September 30, 2010, 2009 and 2008 are presented below.


	For the Fiscal Year Ended September 30
	2010		2009			2008		2010 vs. 2009			2009 vs. 2008
	(In thousands)

Storage and transportation services	$	13,206	$	12,784		$	14,247	$	422		$	(1,463	)
Asset optimization		10,286		21,474			5,178		(11,188	)		16,296
Other		1,652		2,728			4,183		(1,076	)		(1,455	)
Unrealized margins		2,996		(7,490	)		4,705		10,486			(12,195	)

Gross profit		28,140		29,496			28,313		(1,356	)		1,183
Operating expenses		12,448		11,019			8,064		1,429			2,955

Operating income		15,692		18,477			20,249		(2,785	)		(1,772	)
Miscellaneous income		3,083		6,253			8,428		(3,170	)		(2,175	)
Interest charges		2,808		1,830			2,322		978			(492	)

Income before income taxes		15,967		22,900			26,355		(6,933	)		(3,455	)
Income tax expense		5,292		9,979			10,086		(4,687	)		(107	)

Net income	$	10,675	$	12,921		$	16,269	$	(2,246	)	$	(3,348	)

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

Gross profit from our pipeline, storage and other segment decreased $1.4 million primarily due to the following:


	•	$4.9 million decrease from lower margins earned on storage optimization activities.

	•	$3.9 million decrease in basis gains earned from utilizing leased capacity.

	•	$2.4 million decrease from lower margins earned on asset management plans.

	•	$10.5 million increase in unrealized margins associated with our asset optimization activities.

Operating expenses increased $1.4 million primarily due to increased operating costs associated with APS’ gas gathering activities and administrative costs.

Miscellaneous income decreased $3.2 million primarily due to lower intercompany interest income earned by this segment.

Fiscal year ended September 30, 2009 compared with fiscal year ended September 30, 2008

Gross profit from our pipeline, storage and other segment increased $1.2 million primarily due to the following:


	•	$16.3 million increase in asset optimization margins as a result of larger realized gains from the settlement of financial positions associated with storage and trading activities, basis gains earned from utilizing controlled pipeline capacity and higher margins earned under asset management plans.

	•	$12.2 million decrease in unrealized margins associated with our asset optimization activities due to a widening of the spreads between current cash prices and forward natural gas prices.

Operating expenses increased $3.0 million primarily due to increased employee costs and higher depreciation expense which was largely attributable to additional assets placed in service during the year.

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. In fiscal 2011, we anticipate consolidating our short-term facilities used for our regulated operations into a single line of credit. In October 2010, we replaced our $200 million 364-day revolving credit agreement with a $200 million 180-day revolving credit agreement. Additionally, we intend to replace AEM’s $450 million 364-day facility with a $200 million, three-year facility when it expires in December 2010.

Our $350 million unsecured 7.375% Senior Notes will mature in May 2011. We intend to refinance this debt on a long-term basis through the issuance of 30-year unsecured senior notes in June 2011. Additionally, we plan to issue $250 million of 30-year unsecured senior notes in November 2011 to fund our capital expenditure program. On September 30, 2010, we entered into five Treasury lock agreements to fix the Treasury yield component of the interest cost of financing the anticipated issuances of senior notes. We designated all of the Treasury lock agreements as cash flow hedges of an anticipated transaction. Any realized gain or loss incurred when these agreements are settled will be recognized as a component of interest expense over the life of the related long-term debt.

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 2011.

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, 2010, 2009 and 2008 are presented below.


	For the Fiscal Year Ended September 30
	2010			2009			2008			2010 vs. 2009			2009 vs. 2008
	(In thousands)

Total cash provided by (used in)
Operating activities	$	726,476		$	919,233		$	370,933		$	(192,757	)	$	548,300
Investing activities		(542,702	)		(517,201	)		(483,009	)		(25,501	)		(34,192	)
Financing activities		(163,025	)		(337,546	)		98,068			174,521			(435,614	)

Change in cash and cash equivalents		20,749			64,486			(14,008	)		(43,737	)		78,494
Cash and cash equivalents at beginning of period		111,203			46,717			60,725			64,486			(14,008	)

Cash and cash equivalents at end of period	$	131,952		$	111,203		$	46,717		$	20,749		$	64,486

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, 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 the prior year, 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.

Fiscal Year ended September 30, 2009 compared with fiscal year ended September 30, 2008

Operating cash flows were $548.3 million higher in fiscal 2009 compared to fiscal 2008, primarily due to the following:


	•	$368.9 million increase attributable to the favorable impact on our working capital due to the decline in natural gas prices in the current year compared to the prior year.

	•	$56.8 million increase due to lower cash margin requirements related to our natural gas marketing financial instruments.

	•	These increases were partially offset by a $21.0 million decrease due to a contribution made to our pension plans in the current year.

Cash flows from investing activities

In recent fiscal years, a substantial portion of our cash resources has been used to fund acquisitions and growth projects, our ongoing construction program and improvements to information technology systems. Our ongoing construction program enables us to provide 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.

Since early 2010, we have been discussing the financial and operational details of an accelerated steel service line replacement program with representatives of 440 municipalities served by our Mid-Tex Division. Two coalitions of cities, representing the majority of the cities our Mid-Tex Division serves, have agreed to a program of installing 100,000 replacements during the next two years, with approved recovery of the associated return, depreciation and taxes. Under the terms of the agreement, the accelerated replacement program will commence in fiscal 2011 at a total projected capital cost of $80 — $120 million, with completion expected 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 increase significantly during the next two fiscal years.

For the fiscal year ended September 30, 2010, we incurred $542.6 million for capital expenditures compared with $509.5 million for the fiscal year ended September 30, 2009 and $472.3 million for the fiscal year ended September 30, 2008.

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.

The increase in capital expenditures in fiscal 2009 compared to fiscal 2008 primarily reflects $32.6 million related to spending for a regulated transmission pipeline project completed in the fourth quarter of 2009.

Cash flows from financing activities

For the fiscal year ended September 30, 2010, our financing activities used $163.0 million in cash, while financing activities for the fiscal year ended September 30, 2009 used $337.5 million in cash compared with cash of $98.1 million provided for the fiscal year ended September 30, 2008. Our significant financing activities for the fiscal years ended September 30, 2010, 2009 and 2008 are summarized as follows:

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 our accelerated share repurchase program.

	•	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 in fiscal 2010 shares have begun to be 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.

2008

During the fiscal year ended September 30, 2008, we:


	•	Borrowed a net $200.2 million under our short-term facilities due to the impact of seasonal natural gas purchases and the effect of higher natural gas prices.

	•	Repaid $10.3 million long-term debt in accordance with their normal maturity schedules.

	•	Received $25.5 million in net proceeds related to the issuance of 1.0 million shares of common stock.

	•	Paid $117.3 million in dividends, which reflected a payout ratio of 65 percent of net income.

The following table shows the number of shares issued for the fiscal years ended September 30, 2010, 2009 and 2008:


	For the Fiscal Year Ended September 30
	2010		2009		2008

Shares issued:
Direct stock purchase plan		103,529		407,262		388,485
Retirement savings plan		79,722		640,639		558,014
1998 Long-term incentive plan		421,706		686,046		538,450
Outside directors stock-for-fee plan		3,382		3,079		3,197

Total shares issued		608,339		1,737,026		1,488,146

The year-over-year decrease in the number of shares issued primarily reflects the fact that in fiscal 2010, shares have begun to be purchased in the open market rather than by being issued by us to the Direct Stock Purchase Plan and the Retirement Savings Plan. In addition, we awarded fewer shares under our 1998 Long-Term Incentive Plan due to the Company achieving a lower level of performance relative to the target performance established under the Plan during fiscal 2009 compared to fiscal 2008. 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 the current year.

During the fiscal year, we repurchased 2,958,580 common shares as part of the accelerated share repurchase agreement that is described in further detail below. Additionally, we repurchased 37,365 shares attributable to equity awards during the year. The repurchased share activity is 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. We will receive the balance of the shares at the conclusion of the term of the repurchase agreement. The specific number of shares we will ultimately repurchase in the transaction will be based generally on the average of the daily volume-weighted average share price of our common stock over the duration of the agreement. The agreement is scheduled to end in

March 2011, although the termination date may be accelerated at the option of Goldman Sachs & Co. As a result of this transaction, beginning in our fourth fiscal quarter, 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. The number of shares used to calculate our earnings per share in fiscal 2011 will continue to be reduced by the shares we received in July 2010; however, the total impact to diluted earnings per share for fiscal 2011 will be dependent upon the average share price of our common stock over the remainder of the agreement.

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, 2010, we financed our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. As of September 30, 2010, the amount available to us under our credit facilities, net of outstanding letters of credit was $834.8 million. These facilities are described in further detail in Note 6 to the consolidated financial statements.

In October 2010, our $200 million 364-day facility expired and our five-year $566.7 million facility will expire in December 2011. We replaced the $200 million 364-day facility before its expiration with a $200 million 180-day credit facility that will expire in April 2011. We do not plan to replace this facility upon expiration. We expect to begin discussions in fiscal 2011 to replace the expiring five-year $566.7 million facility with a larger multi-year credit facility. We believe our existing five-year facility will provide adequate short-term borrowing capacity until we can successfully execute a new multi-year credit facility.

Additionally, on December 9, 2010, AEM’s existing $450 million committed revolving credit facility will expire. In October 2010, we received regulatory approval to increase AEH’s intercompany demand credit facility with AEC from $200 million to $350 million, effective December 1, 2010 through December 31, 2011. As a result of this increase, we are in discussions with our third-party lenders to replace AEM’s $450 million committed revolving credit facility with a $200 million three-year committed revolving credit facility with an accordion feature that could increase AEM’s borrowing capacity to $500 million. As a result of consolidating and reducing the amounts available under our facilities, we expect to reduce our short-term financing costs.

Shelf Registration

On March 31, 2010, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $1.3 billion in common stock and/or debt securities available for issuance. We had already received approvals from all requisite state regulatory commissions to issue a total of $1.3 billion in common stock and/or debt securities under the new shelf registration statement, including the carryforward of the $450 million of securities remaining available for issuance under our shelf registration statement filed with the SEC on March 23, 2009. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we will be able to issue a total of $950 million in debt securities and $350 million in equity securities.

Credit Ratings

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

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). In March 2010, Moody’s upgraded our rating outlook from stable to positive and affirmed the credit rating on our senior long-term debt at Baa2 and on our commercial paper at P-2. Moody’s stated that the key driver for the upgrade was successful rate case outcomes over the past year. In March 2010, S&P affirmed our senior long-term debt credit rating of BBB+ and our rating outlook as stable. In June 2010, Fitch reaffirmed our senior long-term debt rating of BBB+ and commercial paper ratings of F-2 and upgraded our rating outlook from stable to positive. Fitch cited our effective management of the regulatory process as well as our consistent financial and operational performance as the primary reasons for the upgrade. Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB+

Baa2

BBB+

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 for 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, 2010. Our debt covenants are described in Note 6 to the consolidated financial statements.

Capitalization

The following table presents our capitalization as of September 30, 2010 and 2009:


	September 30
	2010				2009
	(In thousands, except percentages)

Short-term debt	$	126,100	2.8	%	$	72,550	1.6	%
Long-term debt		2,169,682	48.5	%		2,169,531	49.1	%
Shareholders’ equity		2,178,348	48.7	%		2,176,761	49.3	%

Total capitalization, including short-term debt	$	4,474,130	100.0	%	$	4,418,842	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 51.3 percent and 50.7 percent at September 30, 2010 and 2009. The increase in the debt to capitalization ratio primarily reflects an increase in short-term debt as of September 30, 2010 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 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, 2010.


	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⁾	$	2,172,696	$	360,131	$	252,565	$	500,000	$	1,060,000
Short-term debt⁽¹⁾		126,100		126,100		—		—		—
Interest charges⁽²⁾		1,040,151		130,826		219,726		179,347		510,252
Gas purchase commitments⁽³⁾		346,186		264,525		79,758		1,903		—
Capital lease obligations⁽⁴⁾		1,380		186		372		372		450
Operating leases⁽⁴⁾		217,184		18,240		33,407		31,207		134,330
Demand fees for contracted storage⁽⁵⁾		26,305		13,332		10,243		2,730		—
Demand fees for contracted transportation⁽⁶⁾		32,422		8,678		15,744		7,759		241
Financial instrument obligations⁽⁷⁾		58,597		49,673		8,924		—		—
Postretirement benefit plan contributions⁽⁸⁾		154,511		13,006		24,584		29,882		87,039
Uncertain tax positions (including interest)⁽⁹⁾		6,731		—		6,731		—		—

Total contractual obligations	$	4,182,263	$	984,697	$	652,054	$	753,200	$	1,792,312


⁽¹⁾		See Note 6 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, 2010.

⁽⁴⁾		See Note 13 to the consolidated financial statements.

⁽⁵⁾		Represents third party contractual demand fees for contracted storage in our natural gas marketing and pipeline, storage and other segments. 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 natural gas marketing segment.

⁽⁷⁾		Represents liabilities for natural gas commodity financial instruments that were valued as of September 30, 2010. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled.

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

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

AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At September 30, 2010, AEM was committed to purchase 69.5 Bcf within one year, 28.4 Bcf within one to three years and 3.2 Bcf after three years under indexed contracts. AEM is committed to purchase 3.1 Bcf within one year and 0.3 Bcf within one to three years under fixed price contracts with prices ranging from $3.55 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 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, 2010 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, natural gas marketing and pipeline, storage and other 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 natural gas marketing and pipeline, storage and other 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 natural gas marketing 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 natural gas marketing and pipeline, storage and other segments.

Also, in our natural gas marketing 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, 2010 (in thousands):


Fair value of contracts at September 30, 2009	$	(14,166	)
Contracts realized/settled		(34,575	)
Fair value of new contracts		(6,764	)
Other changes in value		5,905

Fair value of contracts at September 30, 2010	$	(49,600	)

The fair value of our natural gas distribution segment’s financial instruments at September 30, 2010, is presented below by time period and fair value source:


	Fair Value of Contracts at September 30, 2010
	Maturity in Years
	Less								Greater		Total Fair
Source of Fair Value	Than 1			1-3			4-5		Than 5		Value
	(In thousands)

Prices actively quoted	$	(46,723	)	$	(2,877	)	$	—	$	—	$	(49,600	)
Prices based on models and other valuation methods		—			—			—		—		—

Total Fair Value	$	(46,723	)	$	(2,877	)	$	—	$	—	$	(49,600	)