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, 2006
		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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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 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, 2006, was $2,064,662,421.

As of November 8, 2006, the registrant had 81,823,767 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 7, 2007 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		23
	Item 1B.	Unresolved Staff Comments		27
	Item 2.	Properties		27
	Item 3.	Legal Proceedings		30
	Item 4.	Submission of Matters to a Vote of Security Holders		30

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		32
	Item 6.	Selected Financial Data		33
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		62
	Item 8.	Financial Statements and Supplementary Data		64
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		124
	Item 9A.	Controls and Procedures		124
	Item 9B.	Other Information		126

PART III
	Item 10.	Directors and Executive Officers of the Registrant		126
	Item 11.	Executive Compensation		126
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		126
	Item 13.	Certain Relationships and Related Transactions		126
	Item 14.	Principal Accountant Fees and Services		127

PART IV
	Item 15.	Exhibits and Financial Statement Schedules		127
Statement of Computation of Ratio of Earnings to Fixed Charges
Subsidiaries of the Registrant
Consent of Ernst & Young LLP
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications
Annual Certification Pursuant to Section 303A.12

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation

AEH		Atmos Energy Holdings, Inc.

AEM		Atmos Energy Marketing, LLC

AES		Atmos Energy Services, LLC

APB		Accounting Principles Board

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

EITF		Emerging Issues Task Force

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FIN		FASB Interpretation

Fitch		Fitch Ratings, Ltd.

FSP		FASB Staff Position

GRIP		Gas Reliability Infrastructure Program

Heritage		Heritage Propane Partners, L.P.

iFERC		Inside FERC

KPSC		Kentucky Public Service Commission

LGS		Louisiana Gas Service Company and LGS Natural Gas Company, which were acquired July 1, 2001

LPSC		Louisiana Public Service Commission

Mcf		Thousand cubic feet

MDWQ		Maximum daily withdrawal quantity

MMcf		Million cubic feet

Moody’s		Moody’s Investor Services, Inc.

MPSC		Mississippi Public Service Commission

MVG		Mississippi Valley Gas Company, which was acquired December 3, 2002

NYMEX		New York Mercantile Exchange, Inc.

NYSE		New York Stock Exchange

RRC		Railroad Commission of Texas

RSC		Rate Stabilization Clause

S&P		Standard & Poor’s Corporation

SEC		United States Securities and Exchange Commission

SFAS		Statement of Financial Accounting Standards

TXU Gas		TXU Gas Company, which was acquired on October 1, 2004

USP		U.S. Propane, L.P.

VCC		Virginia Corporation Commission

WNA		Weather Normalization Adjustment

PART I

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


ITEM 1.	*Business*

Overview

Atmos Energy Corporation, headquartered in Dallas, Texas, is engaged primarily in the natural gas utility business as well as other natural gas nonutility businesses. We are one of the country’s largest natural-gas-only distributors based on number of customers and one of the largest intrastate pipeline operators in Texas based upon miles of pipe. As of September 30, 2006, we distributed natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our seven regulated utility divisions, which covered service areas in 12 states. 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.

Through our nonutility businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers in 22 states and natural gas transportation and storage services to certain of our utility divisions and to third parties.

We were organized under the laws of Texas in 1983 as Energas Company for the purpose of owning and operating the natural gas distribution business of Pioneer Corporation in Texas. In September 1988, we changed our name to Atmos Energy Corporation. As a result of the merger with United Cities Gas Company in July 1997, we also became incorporated in Virginia.

Operating Segments

Our operations are divided into four segments:


	•	the utility segment, which includes our regulated natural gas distribution and related sales operations,

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

	•	the pipeline and storage segment, which includes our regulated and nonregulated natural gas transmission and storage services and

	•	the other nonutility segment, which includes all of our other nonregulated nonutility operations.

Strategy

Our overall strategy is to:


	•	deliver superior shareholder value,

	•	improve the quality and consistency of earnings growth, while operating our natural gas utility and nonutility businesses exceptionally well and

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

Over the last five years, we have primarily grown through two significant acquisitions, our acquisition in December 2002 of Mississippi Valley Gas Company (MVG) and our acquisition in October 2004 of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas).

We have experienced over 20 consecutive years of increasing dividends and earnings growth after giving effect to our acquisitions. We have achieved this record of growth while operating our utility operations efficiently by managing our operating and maintenance expenses and leveraging our technology, such as our 24-hour call centers, to achieve more efficient operations. In addition, we have focused on regulatory rate

proceedings to increase revenue as our costs increase and mitigated weather-related risks through weather-normalized rates that now apply to most of our service areas. We have also strengthened our nonutility businesses by increasing gross profit margins, actively pursuing opportunities to increase the amount of storage available to us and expanding commercial opportunities in our pipeline and storage segment.

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.

Utility Segment Overview

We operated our utility segment through the following seven regulated natural gas utility divisions during the year ended September 30, 2006:


	•	Atmos Energy Colorado-Kansas Division,

	•	Atmos Energy Kentucky Division,

	•	Atmos Energy Louisiana Division,

	•	Atmos Energy Mid-States Division,

	•	Atmos Energy Mid-Tex Division,

	•	Atmos Energy Mississippi Division and

	•	Atmos Energy West Texas Division.

Effective October 1, 2006, the Kentucky and Mid-States Divisions were combined.

Our natural gas utility distribution business is seasonal and dependent on weather conditions in our service areas. 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.

In addition to weather, our financial results are affected by the cost of natural gas and economic conditions in the areas that we serve. Higher gas costs, which we are generally able to pass through to our customers under purchased gas adjustment clauses, may cause customers to conserve or, in the case of industrial customers, to use alternative energy sources. Higher gas costs may also 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.

The effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which are now approved by the regulators for over 90 percent of residential and commercial meters in our service areas. WNA allows 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.

Prior to October 1, 2006, our largest division, the Mid-Tex Division, did not have WNA. However, its operations benefited from a rate structure that combined a monthly customer charge with a declining block rate schedule to partially mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provided for the recovery of most of our fixed costs for such operations under most weather conditions. However, this rate structure was not as beneficial during periods where weather was significantly warmer than normal.

In May 2006, the Mid-Tex Division filed a Statement of Intent seeking additional annual revenues of $60 million and several rate design changes including WNA. In July 2006, the Railroad Commission of Texas

(RRC) approved an interim and a permanent WNA, effective October 1, 2006 for the Mid-Tex Division. The agreement provided that the interim WNA will be based on the use of 30 years of weather history, while the permanent WNA will allow the parties to contest the appropriate period of weather data to use in calculating normal weather. The permanent WNA will also be modified or adjusted to conform to the rate design that the RRC ultimately approves in the case. Additionally, in May 2006, we agreed to a settlement with the Louisiana Public Service Commission (LPSC) that authorized the implementation of WNA in our Louisiana Division effective December 1, 2006.

As of September 30, 2006 we had, or received regulatory approvals for WNA for our customer meters in the following service areas for the following periods:


Georgia		October — May
Kansas		October — May
Kentucky		November — April
Louisiana⁽¹⁾		December — March
Mid-Tex⁽¹⁾		October — May
Mississippi		November — April
Tennessee		November — April
Amarillo, Texas		October — May
West Texas		October — May
Lubbock, Texas		October — May
Virginia		January — December


⁽¹⁾		Effective beginning with the 2006-2007 winter heating season.

Our natural gas supply comes from a variety of third-party providers and from gas held in storage. We anticipate that the natural gas supply for the upcoming winter heating season will be provided by a variety of suppliers, including independent producers, marketers and pipeline companies, in addition to withdrawals of gas from storage. Additionally, the natural gas supply for our Mid-Tex Division includes peaking and spot purchase agreements. We also contract for storage service in underground storage facilities on many of the interstate pipelines serving us. We estimate the peak-day availability of natural gas supply from long-term contracts, short-term contracts and withdrawals from underground storage to be approximately 4.2 Bcf. The peak-day demand for our utility operations in fiscal 2006 was on December 8, 2005, when sales to customers reached approximately 3.4 Bcf.

Supply arrangements are contracted from our suppliers on a firm basis with various terms at market prices. The firm supply consists of both base load and swing supply quantities. 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 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 2006 were Anadarko Energy Services, BP Energy Company, Chesapeake Energy Marketing, Inc., ConocoPhillips Company, Cross Timbers Energy Services, Inc., Devon Gas Services, L.P., Enbridge Marketing (US) L.P., PPM Energy, Inc., Tenaska Marketing and Atmos Energy Marketing, LLC, our natural gas marketing subsidiary.

The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments.

Also, 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 statutes or regulations. 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.

We receive gas deliveries for all of our utility divisions, except for our Mid-Tex Division, through 37 pipeline transportation companies, both interstate and intrastate, to satisfy our natural gas needs. 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 by our Atmos Pipeline — Texas Division.

The following is a brief description of our seven natural gas utility divisions. Additional information for our natural gas utility divisions is presented under the caption “Operating Statistics”.

Atmos Energy Colorado-Kansas Division. Our Colorado-Kansas Division operates in Colorado, Kansas and the southwestern corner of Missouri and is regulated by each respective state’s public service commission with respect to accounting, rates and charges, operating matters and the issuance of securities. We operate under terms of non-exclusive franchises granted by the various cities. Rates in our Kansas service area are subject to WNA. The principal transporters of the Colorado-Kansas Division’s gas supply requirements are Colorado Interstate Gas Company, Northwest Pipeline, Public Service Company of Colorado and Southern Star Central Pipeline. Additionally, the Colorado-Kansas Division purchases substantial volumes from producers that are connected directly to its distribution system.

Atmos Energy Kentucky Division. Our Kentucky Division operates in Kentucky and is regulated by the Kentucky Public Service Commission (KPSC), which regulates utility services, rates, issuance of securities and other matters. We operate in various incorporated cities pursuant to non-exclusive franchises granted by these cities. The sale of natural gas for use as vehicle fuel in Kentucky is unregulated. In February 2006, the KPSC approved our request to continue the performance-based ratemaking mechanism for an additional five-year period. Under the performance-based mechanism, we and our customers jointly share in any actual gas cost savings achieved when compared to pre-determined benchmarks. Our rates are also subject to WNA. The Kentucky Division’s gas supply is delivered primarily by Midwestern Pipeline, Tennessee Gas Pipeline Company, Texas Gas Transmission LLC and Trunkline Gas Company. As noted below, this division was combined with the Mid-States Division effective October 1, 2006.

Atmos Energy Louisiana Division. Our Louisiana Division operates in Louisiana and serves the metropolitan area of Monroe, the suburban areas of New Orleans and western Louisiana. Our Louisiana Division is regulated by the Louisiana Public Service Commission, which regulates utility services, rates and other matters. We operate most of our service areas pursuant to a non-exclusive franchise granted by the governing authority of each area. 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. Effective beginning with the 2006-2007 winter heating season, rates in our Louisiana service area will be subject to WNA. The principal transporters of the Louisiana Division’s gas supply requirements are Acadian Pipeline, Gulf South, Louisiana Intrastate Gas Company, Texas Gas Transmission LLC and Trans Louisiana Gas Pipeline, Inc., a subsidiary of Atmos Pipeline and Storage, LLC.

Atmos Energy Mid-States Division. Our Mid-States Division operates in Georgia, Illinois, Iowa, Missouri, Tennessee and Virginia. In each of these states, our rates, services and operations as a natural gas distribution company are subject to general regulation by each state’s public service commission. We operate in each community, where necessary, under a franchise granted by the municipality for a fixed term of years. In Tennessee and Georgia, we have WNA and a performance-based rate program, which provides incentives

for us to find ways to lower costs and share the cost savings with our customers. We have WNA in our Virginia service area that covers the entire year. Our Mid-States Division is served by 13 interstate pipelines; however, the majority of the volumes are transported through Columbia Gulf, East Tennessee Pipeline, Southern Natural Gas and Tennessee Gas Pipeline. The Kentucky Division was combined with the Mid-States Division effective October 1, 2006.

Atmos Energy Mid-Tex Division. Our Mid-Tex Division includes the natural gas distribution operations that operate in the north-central, eastern and western parts of Texas. The Mid-Tex Division purchases, distributes and sells natural gas in approximately 550 cities and towns, including the 11-county Dallas/Fort Worth metropolitan area. This division currently operates under a system-wide rate structure. The governing body of each municipality we serve has original jurisdiction over all utility rates, operations and services within its city limits, except with respect to sales of natural gas for vehicle fuel and agricultural use. We operate pursuant to non-exclusive franchises granted by the municipalities we serve, which are subject to renewal from time to time. The 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. Effective beginning with the 2006-2007 winter heating season, rates in our Mid-Tex service area will be subject to WNA.

Atmos Energy Mississippi Division. Our Atmos Energy Mississippi Division operates in Mississippi and is regulated by the Mississippi Public Service Commission (MPSC) with respect to rates, services and operations. We operate under non-exclusive franchises granted by the municipalities we serve. Through fiscal 2005, we operated under a rate structure that allowed us, over a five-year period, to recover a portion of our integration costs associated with the MVG acquisition and operations and maintenance costs in excess of an agreed-upon benchmark. In addition, we were required to file for rate adjustments based on our expenses every six months. Effective October 1, 2005, our rate design was modified to substitute the original agreed-upon benchmark with a sharing mechanism to allow the sharing of cost savings above an allowed return on equity level. Further, beginning October 1, 2005, we moved from a semi-annual filing process to an annual filing process. We also have WNA in Mississippi. This division’s gas supply is delivered primarily by Gulf South Pipeline Company, Tennessee Gas Pipeline Company, Southern Natural Gas Company, Texas Eastern Transmission, Texas Gas Transmission LLC, Trunkline Gas Co. LLC and Enbridge Marketing LP.

Atmos Energy West Texas Division. Our West Texas Division operates in Texas in three primary service areas: the Amarillo service area, the Lubbock service area and the West Texas service area. Similar to our Mid-Tex Division, the governing body of each municipality we serve has original jurisdiction over all utility rates, operations and services within its city limits, except with respect to sales of natural gas for vehicle fuel and agricultural use. We operate pursuant to non-exclusive franchises granted by the municipalities we serve, which are subject to renewal from time to time. The 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. We have WNA in each of our service areas. Our West Texas Division receives transportation service from ONEOK Pipeline. In addition, the West Texas Division purchases a significant portion of its natural gas supply from Pioneer Natural Resources, which is connected directly to our Amarillo, Texas, distribution system.

Natural Gas Marketing Segment Overview

Our natural gas marketing and other nonutility segments, which are organized under Atmos Energy Holdings, Inc. (AEH), have operations in 22 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly-owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing, L.L.C., which was renamed Atmos Energy Marketing, LLC (AEM).

We acquired a 45 percent interest in Woodward Marketing, L.L.C. in July 1997 as a result of the merger of Atmos Energy and United Cities Gas Company, which had acquired that interest in May 1995. In April

2001, we acquired the remaining 55 percent interest that we did not own for 1,423,193 restricted shares of our common stock.

AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers primarily in the southeastern and midwestern states and to our Kentucky, Louisiana and Mid-States divisions. These services primarily consist of 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 management through the use of derivative products. We use proprietary and customer-owned transportation and storage assets to provide the various services our customers request. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues for services we deliver.

We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we participate in natural gas storage transactions in which we seek to capture the pricing differences that occur over time. We purchase physical natural gas and then sell financial contracts at favorable prices to lock in a gross profit margin. Through the use of transportation and storage services and derivatives, we are able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

AEM’s management of natural gas requirements involves the sale of natural gas and the management of storage and transportation supplies under contracts with customers generally having one to two year terms. AEM also sells natural gas to some of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. At September 30, 2006, AEM had a total of 679 industrial, 73 municipal and 289 other customers.

Pipeline and Storage Segment Overview

Our pipeline and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC (APS). The Atmos Pipeline — Texas 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 inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline and lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands. Both of these services are primarily offered on our Atmos Pipeline — Texas system. These operations represent 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.

APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.

In May 2006, APS announced plans to form a joint venture with a local natural gas producer to construct a natural gas gathering system in Eastern Kentucky. Referred to as the Straight Creek Project, the new system is expected to relieve severe gas gathering and transportation constraints that historically have burdened natural gas producers in the area and should improve delivery reliability to natural gas customers. In October 2006, the Federal Energy Regulatory Commission (FERC) issued a declaratory order finding that the Straight Creek Project will be exempt from FERC jurisdiction. The joint venture provides APS the opportunity to apply its expertise to the upstream gathering business.

Other Nonutility Segment Overview

Our other nonutility segment consists primarily of the operations of Atmos Energy Services, LLC (AES), and Atmos Power Systems, Inc. which are wholly-owned by our subsidiary, Atmos Energy Holdings, Inc. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services, which began in April 2004, include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices in exchange for revenues that are equal to the costs incurred to provide those services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and have entered into agreements to lease these plants.

Through January 2004, United Cities Propane Gas, Inc., a wholly-owned subsidiary of Atmos Energy Holdings, Inc., owned an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with other utility companies to own a limited partnership interest in Heritage Propane Partners, L.P. (Heritage), a publicly-traded marketer of propane through a nationwide retail distribution network. During fiscal 2004, we sold our interest in USP and Heritage. As a result of these transactions, we no longer have an interest in the propane business.

Operating Statistics

The following tables present certain operating statistics for our utility, natural gas marketing, pipeline and storage and other nonutility segments for each of the five fiscal years from 2002 through 2006.

Utility Sales and Statistical Data


	Year Ended September 30
	2006		2005⁽¹⁾		2004		2003⁽¹⁾		2002

METERS IN SERVICE, end of year
Residential		2,886,042		2,862,822		1,506,777		1,498,586		1,247,247
Commercial		275,577		274,536		151,381		151,008		122,156
Industrial		2,661		2,715		2,436		3,799		2,118
Agricultural		8,714		9,639		8,397		9,514		10,576
Public authority and other		8,205		8,128		10,145		9,891		7,244

Total meters		3,181,199		3,157,840		1,679,136		1,672,798		1,389,341

HEATING DEGREE DAYS⁽²⁾
Actual (weighted average)		2,527		2,587		3,271		3,473		3,368
Percent of normal		87%		89%		96%		101%		94%
UTILITY SALES VOLUMES — MMcf⁽³⁾
Gas Sales Volumes
Residential		144,780		162,016		92,208		97,953		77,386
Commercial		87,006		92,401		44,226		45,611		35,796
Industrial		26,161		29,434		22,330		23,738		14,499
Agricultural		5,629		3,348		4,642		7,884		10,988
Public authority and other		8,457		9,084		9,813		9,326		5,875

Total gas sales volumes		272,033		296,283		173,219		184,512		144,544
Utility transportation volumes		126,960		122,098		87,746		70,159		69,589

Total utility throughput		398,993		418,381		260,965		254,671		214,133

UTILITY OPERATING REVENUES (000’s)⁽³⁾
Gas Sales Revenues
Residential	$	2,068,736	$	1,791,172	$	923,773	$	873,375	$	535,981
Commercial		1,061,783		869,722		400,704		367,961		221,728
Industrial		276,186		229,649		155,336		151,969		70,164
Agricultural		40,664		27,889		31,851		48,625		37,951
Public authority and other		103,936		86,853		77,178		65,921		31,731

Total utility gas sales revenues		3,551,305		3,005,285		1,588,842		1,507,851		897,555
Transportation revenues		62,215		59,996		31,714		30,461		28,786
Other gas revenues		37,071		37,859		17,172		15,770		11,185

Total utility operating revenues	$	3,650,591	$	3,103,140	$	1,637,728	$	1,554,082	$	937,526

Utility average transportation revenue per Mcf	$	0.49	$	0.49	$	0.36	$	0.43	$	0.41
Utility average cost of gas per Mcf sold	$	10.02	$	7.41	$	6.55	$	5.76	$	3.87

Employees		4,402		4,327		2,742		2,817		2,255

See footnotes following these tables.

Utility Sales and Statistical Data By Division


	Year Ended September 30, 2006
	Colorado-						Mid-		West									Total
	Kansas		Kentucky		Louisiana		States		Texas		Mississippi		Mid-Tex		Other⁽⁴⁾			Utility

METERS IN SERVICE
Residential		213,566		158,408		330,694		277,998		273,520		241,406		1,390,450		—			2,886,042
Commercial		21,440		18,228		23,108		36,686		25,984		27,868		122,263		—			275,577
Industrial		84		240		—		681		808		643		205		—			2,661
Agricultural		312		—		—		—		8,402		—		—		—			8,714
Public authority and other		543		1,637		—		1,034		2,166		2,825		—		—			8,205

Total		235,945		178,513		353,802		316,399		310,880		272,742		1,512,918		—			3,181,199

HEATING DEGREE DAYS⁽²⁾
Actual		5,466		4,349		1,319		3,515		3,561		2,757		1,697		—			2,527
Percent of normal		99%		100%		78%		95%		100%		102%		72%		—			87%
SALES VOLUMES — MMcf⁽³⁾
Gas Sales Volumes
Residential		15,113		9,249		12,131		15,065		15,609		12,601		65,012		—			144,780
Commercial		5,901		4,526		6,944		11,328		6,309		6,440		45,558		—			87,006
Industrial		419		1,830		—		6,945		3,933		8,250		4,784		—			26,161
Agricultural		619		—		—		—		5,010		—		—		—			5,629
Public authority and other		1,390		1,237		—		226		1,962		3,642		—		—			8,457

Total		23,442		16,842		19,075		33,564		32,823		30,933		115,354		—			272,033
Transportation Volumes		9,680		25,871		6,310		20,654		15,135		1,702		47,608		—			126,960

Total Throughput		33,122		42,713		25,385		54,218		47,958		32,635		162,962		—			398,993

OPERATING MARGIN (000’s)⁽³⁾	$	71,000	$	50,271	$	98,502	$	106,742	$	93,693	$	92,515	$	412,334	$	—		$	925,057
OPERATING EXPENSES (000’s)⁽³⁾
Operation and maintenance	$	28,235	$	19,874	$	40,741	$	38,148	$	33,332	$	44,533	$	154,412	$	(1,756	)	$	357,519
Depreciation and amortization	$	13,578	$	11,636	$	21,201	$	22,172	$	13,690	$	10,596	$	74,375	$	(2,755	)	$	164,493
Taxes, other than income	$	6,663	$	4,423	$	8,788	$	10,867	$	21,509	$	14,110	$	111,844	$	—		$	178,204
Impairment of long-lived assets	$	—	$	—	$	—	$	—	$	22,947	$	—	$	—	$	—		$	22,947
OPERATING INCOME (000’s)⁽³⁾	$	22,524	$	14,338	$	27,772	$	35,555	$	2,215	$	23,276	$	71,703	$	4,511		$	201,894
CAPITAL EXPENDITURES (000’s)	$	19,466	$	16,645	$	32,218	$	38,307	$	27,374	$	15,389	$	134,762	$	23,581		$	307,742
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)	$	252,584	$	190,959	$	328,310	$	436,916	$	253,086	$	226,690	$	1,262,516	$	132,240		$	3,083,301
OTHER STATISTICS, at year end
Miles of pipe		6,601		3,937		8,214		8,015		14,831		6,415		27,856		—			75,869
Employees		263		220		412		416		341		437		1,458		855			4,402

See footnotes following these tables.


	Year Ended September 30, 2005
	Colorado-						Mid-		West									Total
	Kansas		Kentucky		Louisiana		States		Texas		Mississippi		Mid-Tex		Other⁽⁴⁾			Utility

METERS IN SERVICE
Residential		209,321		159,216		348,576		276,667		267,278		244,136		1,357,628		—			2,862,822
Commercial		20,914		18,350		23,850		36,519		25,410		28,350		121,143		—			274,536
Industrial		81		239		—		684		816		664		231		—			2,715
Agricultural		279		—		—		—		9,360		—		—		—			9,639
Public authority and other		476		1,650		—		1,066		2,139		2,797		—		—			8,128

Total		231,071		179,455		372,426		314,936		305,003		275,947		1,479,002		—			3,157,840

HEATING DEGREE DAYS⁽²⁾
Actual		5,437		4,241		1,301		3,510		3,536		2,583		1,904		—			2,587
Percent of normal		99%		98%		78%		93%		99%		96%		80%		—			89%
SALES VOLUMES — MMcf⁽³⁾
Gas Sales Volumes
Residential		16,404		10,741		13,134		16,222		19,292		12,985		73,238		—			162,016
Commercial		5,929		4,891		6,811		11,806		7,493		6,711		48,760		—			92,401
Industrial		338		1,858		—		8,205		4,477		9,057		5,499		—			29,434
Agricultural		246		—		—		—		3,102		—		—		—			3,348
Public authority and other		1,355		1,396		—		241		2,296		3,796		—		—			9,084

Total		24,272		18,886		19,945		36,474		36,660		32,549		127,497		—			296,283
Transportation Volumes		8,388		26,066		7,046		20,142		12,390		1,309		46,757		—			122,098

Total Throughput		32,660		44,952		26,991		56,616		49,050		33,858		174,254		—			418,381

OPERATING MARGIN (000’s)⁽³⁾	$	70,542	$	52,302	$	94,350	$	110,012	$	90,316	$	91,610	$	398,234	$	—		$	907,366
OPERATING EXPENSES (000’s)⁽³⁾
Operation and maintenance	$	26,679	$	18,618	$	37,994	$	38,427	$	29,701	$	49,241	$	146,449	$	(515	)	$	346,594
Depreciation and amortization	$	13,693	$	11,739	$	21,911	$	23,615	$	13,249	$	10,830	$	64,460	$	—		$	159,497
Taxes, other than income	$	5,013	$	3,288	$	9,626	$	12,283	$	19,846	$	12,494	$	102,360	$	—		$	164,910
OPERATING INCOME (000’s)⁽³⁾	$	25,157	$	18,657	$	24,819	$	35,687	$	27,520	$	19,045	$	84,965	$	515		$	236,365
CAPITAL EXPENDITURES (000’s)	$	20,690	$	17,525	$	31,198	$	34,176	$	29,066	$	15,925	$	115,024	$	36,970		$	300,574
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)	$	244,250	$	183,931	$	318,869	$	416,825	$	263,285	$	206,511	$	1,167,425	$	125,000		$	2,926,096
OTHER STATISTICS, at year end
Miles of pipe		6,530		3,908		8,151		7,958		15,000		6,356		33,701		—			81,604
Employees		267		236		421		412		346		467		1,398		780			4,327

See footnotes following these tables.

Natural Gas Marketing, Pipeline and Storage and Other Nonutility Operations Sales and Statistical Data


	Year Ended September 30
	2006		2005		2004		2003		2002

CUSTOMERS, end of year Industrial		746		624		638		644		641
Municipal		73		69		80		94		101
Other		467		401		237		202		117

Total		1,286		1,094		955		940		859

NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽³⁾		336,516		273,201		265,090		294,785		273,692
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽³⁾		590,985		563,949		9,395		11,648		12,788
OPERATING REVENUES (000’s)⁽³⁾ Natural gas marketing	$	3,156,524	$	2,106,278	$	1,618,602	$	1,668,493	$	1,031,874
Pipeline and storage		160,567		153,289		19,758		20,298		18,720
Other nonutility		5,898		5,302		3,393		2,853		5,985

Total operating revenues	$	3,322,989	$	2,264,869	$	1,641,753	$	1,691,644	$	1,056,579

Employees, at year end		230		216		122		88		83

Notes to preceding tables:


⁽¹⁾		The operational and statistical information includes the operations of the Mississippi Division since the December 3, 2002 acquisition date and the Mid-Tex and Atmos Pipeline — Texas Divisions since the October 1, 2004 acquisition date.

⁽²⁾		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 30-year average 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.

⁽³⁾		Sales volumes, revenues, operating margins, operating expense and operating income reflect segment operations, including intercompany sales and transportation amounts.

⁽⁴⁾		The Other column represents our utility shared services unit, which provides administrative and other support to our seven regulated utility divisions. Certain costs incurred by this unit are not allocated to our utility divisions.

Ratemaking Activity

Overview

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

address all of the utility’s non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of expense, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility’s other costs, (ii) represents a large component of the utility’s cost of service and (iii) is generally outside the control of the gas utility. There is no gross profit generated through purchased gas adjustments because they provide a dollar-for-dollar offset to increases or decreases in utility gas costs. Although substantially all of our utility sales to our customers fluctuate with the cost of gas that we purchase, utility gross profit (which is defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas due to the purchased gas adjustment mechanism. 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 hedges to lock in gas costs. Under the performance-based ratemaking adjustment, purchased gas costs savings are shared between the utility and its customers.

The following table summarizes some information regarding our ratemaking jurisdictions. This information is for regulatory purposes only and may not be representative of our actual financial position.

Jurisdictional Rate Summary


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

Atmos Pipeline — Texas	Texas		5/24/04	$	417,111		8.258	%		10.00	%
Colorado-Kansas	Colorado		7/1/05		84,711		8.95	%		11.25	%
	Kansas		3/1/04		(2)		(2	)		(2	)
Kentucky	Kentucky		12/21/99		(2)		(2	)		(2	)
Louisiana	Trans LA		10/1/04		81,645		9.14	%		10.50% - 11.50%
	LGS		10/1/04		170,358		9.23	%		10.88% - 11.50%
Mid-States	Georgia		12/20/05		62,380		7.57	%		10.13	%
	Illinois		11/1/00		24,564		9.18	%		11.56	%
	Iowa		3/1/01		5,000		(2	)		11.00	%
	Missouri		10/14/95		(2)		10.58	%		12.15	%
	Tennessee		11/15/95		111,970		(2	)		(2	)
	Virginia		8/1/04		30,672		8.46% - 8.96%			9.50% -10.50%
Mid-Tex	Texas		5/24/04		769,721		8.258	%		10.00	%
Mississippi	Mississippi		1/1/05		196,801		8.23	%		9.80	%
West Texas	Amarillo		9/1/03		36,844		9.88	%		12.00	%
	Lubbock		3/1/04		43,300		9.15	%		11.25	%
	West Texas		5/1/04		87,500		8.77	%		10.50	%

See footnotes on the following page.

Effective

Authorized

Bad

Performance-

Date of Last

Debt/

Debt

Based Rate

Division

Jurisdiction

Rate Action

Equity Ratio

Rider⁽⁵⁾

WNA

Program⁽³⁾

Atmos Pipeline — Texas

Texas

5/24/04

50/50

N/A

Colorado-Kansas

Colorado

7/1/05

52/48

Kansas

3/1/04

(2)

Yes

Kentucky

12/21/99

(2)

Yes

Louisiana

Trans LA

10/1/04

50/50

(4)

LGS

10/1/04

53/47

(4)

Mid-States

Georgia

12/20/05

55/45

Yes

Illinois

11/1/00

67/33

Iowa

3/1/01

57/43

Missouri

10/14/95

(2)

Tennessee

11/15/95

56/44

Yes

Virginia

8/1/04

52/48

Yes

Mid-Tex

Texas

5/24/04

50/50

(4)

Mississippi

1/1/05

47/53

Yes

West Texas

Amarillo

9/1/03

50/50

Yes

Lubbock

3/1/04

50/50

Yes

West Texas

5/1/04

50/50

Yes


⁽¹⁾		The rate base and authorized rate of return presented in this table are the rate base and rate of return from the last base rate case for each jurisdiction. These rate bases and rates of return are not necessarily indicative of current or future rate bases or rates of return.

⁽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⁾		The performance-based rate program provides incentives to natural gas utilities to minimize purchased gas costs by allowing the utility and its customers to share the purchased gas cost savings.

⁽⁴⁾		During 2006, our Louisiana and Mid-Tex Divisions received authorization to implement WNA beginning in the 2006-2007 winter heating season.

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

Recent Ratemaking Activity

Our current rate strategy focuses on seeking rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved margins from customer usage patterns due to weather-related variability, declining use per customer and energy conservation, also known as decoupling. Additionally, we are seeking to stratify rates for low income households and to recover the gas cost portion of our bad debt expense.

Improving rate design is a long-term process. In the interim, we are addressing regulatory lag issues by directing discretionary capital spending to jurisdictions that permit us to recover our investment in a timely manner and filing rate cases on a more frequent basis to minimize the regulatory lag to keep our actual returns more closely aligned with our allowed returns.

Approximately 97 percent of our utility revenues in the fiscal years ended September 30, 2006, 2005 and 2004 were derived from sales at rates set by or subject to approval by local or state authorities. Net annual revenue increases resulting from ratemaking activity totaling $39.0 million, $6.3 million and $16.2 million became effective in fiscal 2006, 2005 and 2004 as summarized below:


	Most Recent			Increase (Decrease) to Revenue
	Effective	Most Recent		for the Year Ended September 30
Division	Date	Rate Action	Jurisdiction	2006			2005		2004
				(In thousands)

Atmos Pipeline — Texas	8/1/06	GRIP⁽¹⁾	Texas	$	5,205		$	1,802	$	—
Colorado-Kansas	4/1/04	Show Cause	Colorado		—			—		(1,900	)
	1/1/06	Ad Valorem Tax	Kansas		1,565			—		—
	3/1/04	Rate Case	Kansas		—			—		2,500
Louisiana	2/1/06	Stable Rate Filing⁽²⁾	LGS		3,326			—		—
	10/1/04	Stable Rate Filing⁽²⁾	LGS		—			225		—
Mid-States	8/1/04	Rate Case	Virginia		—			—		372
	12/20/05	Rate Case	Georgia		409			—		—
Mid-Tex	2/1/06	GRIP⁽¹⁾	Texas		25,313			—		—
Mississippi	(3)	Stable Rate Filing⁽²⁾	Mississippi		—			4,300		10,545
	11/1/05	Rate Restructuring	Mississippi		(600	)		—		—
West Texas	12/1/05	GRIP⁽¹⁾	Lubbock		1,263			—		—
	3/1/04	Rate Case	Lubbock		—			—		1,525
	3/1/06	GRIP⁽¹⁾	West Texas		2,539			—		—
	5/1/04	Rate Case	West Texas		—			—		3,200

				$	39,020		$	6,327	$	16,242


⁽¹⁾		In 2003, the Texas Legislature approved the Gas Reliability Infrastructure Program (GRIP) which allows natural gas utilities the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. Natural gas utilities that enter the program will be required to file a complete rate case at least once every five years.

⁽²⁾		A stable rate filing is a regulatory mechanism designed to allow us to refresh our rates on a periodic basis without filing a formal rate case.

⁽³⁾		The MPSC had formerly required that we file for rate adjustments every six months. Through May 2005, rate filings were made in May and November of each year and the rate adjustments typically became effective in June and December. See further discussion under the recent ratemaking activity for our Atmos Energy Mississippi Division below.

Additionally, the following ratemaking efforts were initiated during fiscal 2006 but had not been completed as of September 30, 2006:


Division	Rate Action	Jurisdiction	Revenue Requested
			(In thousands)

Louisiana	Stable Rate Filing⁽¹⁾	LGS	$	10,753
Mid-States	Rate Case	Missouri		3,396
	Rate Proceeding⁽²⁾	Tennessee		3,400
Mid-Tex	System-wide Case	Texas		60,844

			$	78,393


⁽¹⁾		The Louisiana Division has included the Rate Stabilization Clause increase in rates. The increase is subject to refund, pending final resolution of the Stable Rate Filing.

⁽²⁾		The Tennessee rate proceeding was settled in October 2006. See below for information regarding the settlement.

Our recent ratemaking activity is discussed in greater detail below.

Atmos Pipeline-Texas. In April 2006, Atmos Pipeline — Texas made a filing under Texas’ Gas Reliability Infrastructure Program (GRIP) to include in rate base approximately $21.6 million of pipeline capital expenditures incurred during calendar year 2005, which should result in additional annual revenues of approximately $3.3 million. The RRC approved this filing in July 2006 and these new charges were included in the monthly customer charge beginning in August 2006.

In September 2005, Atmos Pipeline — Texas made a GRIP filing to include in rate base approximately $10.6 million of pipeline capital expenditures incurred during calendar year 2004, which resulted in approximately $1.9 million in additional annual revenue. In December 2004, Atmos Pipeline — Texas made a GRIP filing to include in rate base approximately $12.0 million of pipeline capital expenditures made by TXU Gas during calendar year 2003, which resulted in additional annual revenues of approximately $1.8 million.

Atmos Energy Colorado-Kansas Division. In December 2005, the Colorado-Kansas Division filed its second annual ad valorem tax surcharge for $1.6 million. The surcharge is designed to collect Kansas property taxes in excess of the amount in the Colorado-Kansas Division’s most recent general rate case. We began to bill this surcharge in January 2006.

In July 2004, the Colorado Public Utility Commission ordered us to issue a one-time credit to our Colorado customers of $1.9 million. The agreement was a result of an inquiry by the Colorado Office of Consumer Counsel related to our earnings in Colorado. The staff of the Colorado Public Utility Commission was also a party to the agreement.

In May 2003, the Colorado-Kansas Division filed a rate case with the Kansas Corporation Commission for approximately $7.4 million in additional annual revenues. In January 2004, the Kansas Corporation Commission approved an agreement that allowed a $2.5 million increase in our rates effective March 2004. Additionally, the agreement allowed us to increase our monthly customer charges from $5 to $8, provided that we would not file another full rate application prior to September 2005. WNA became effective in Kansas in October 2003 in accordance with the Kansas Corporation Commission’s ruling in May 2003.

Atmos Energy Kentucky Division. In February 2006, the KPSC approved the Company’s request to continue its Performance Based Ratemaking (PBR) mechanism for an additional five year period. The PBR establishes predetermined gas cost benchmarks and provides incentives to the Company for purchasing gas supply below those benchmark costs.

In February 2005, the Attorney General of the State of Kentucky filed a complaint with the Kentucky Public Service Commission (KPSC) alleging that our rates were producing revenues in excess of reasonable levels. We answered the complaint and filed a Motion to Dismiss with the KPSC. In February 2006, the KPSC issued an Order denying our Motion to Dismiss but stated that the Attorney General had not met his burden of proof concerning his complaint. In March 2006, the KPSC set a procedural schedule for the case. The Attorney General is currently conducting discovery. A hearing should be scheduled for early 2007. We believe that the Attorney General will not be able to demonstrate that our present rates are in excess of reasonable levels.

Atmos Energy Louisiana Division. In September 2005, the Louisiana Public Service Commission (LPSC) consolidated several then-existing dockets. These dockets included a separate proceeding for the renewal of the Rate Stabilization Clause (RSC) for each of the LGS and TransLa Gas service areas; resolution of the outstanding 2003 RSC filing for the LGS service area; and our request for approval of a decoupling mechanism to stabilize margins in both the LGS and TransLa service areas.

On May 25, 2006, the LPSC voted to approve a settlement which included a modified WNA providing for partial decoupling, renewal of the RSC for both the LGS and TransLa service areas with provisions that will reduce regulatory lag and a refund to customers of approximately $0.4 million for the LGS service areas that previously had been deferred. The first RSC filing was in August 2006 for approximately $10.8 million, based on a test year ended December 31, 2005, for the LGS service area. The increase is subject to refund, pending final approval by the LPSC. The first filing for the TransLa service area will be made by

December 31, 2006, for the test period ending September 30, 2006, with an effective rate adjustment of April 1, 2007. WNA for both service areas will be in effect for an initial three-year period beginning with the winter of 2006-2007. In the third quarter of fiscal 2006, $6.2 million in deferred revenue associated with the 2003 RSC rate adjustment was recognized.

On August 29, 2005, Hurricane Katrina struck the Gulf Coast, inflicting significant damage to our eastern Louisiana operations. The hardest hit areas in our service territory were in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes. Although service has been restored for many of our customers, a significant number of customers will not require gas service for some time, if ever, because of sustained damages. We began implementing new rates, subject to refund, in September 2006 that reflected the reduction of approximately 26,500 customers and included a request to recover costs attributable to Hurricane Katrina. We cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to this filing or our ability to fully recover all costs incurred as a result of the storm.

During the second quarter of 2005, the Louisiana Division implemented a rate increase of $3.3 million in its LGS service area. This increase resulted from our RSC filing in 2004 and was subject to refund, pending the final resolution of that filing. As the rate increase was subject to refund, we did not recognize the effects of this increase in our results of operations during fiscal 2005 or the first three quarters of fiscal 2006.

During fiscal 2004, the Louisiana Public Service Commission approved tariff revisions for our LGS service area totaling $0.2 million that became effective in October 2004.

In October 2002, Atmos received written notification from the Executive Secretary of the LPSC asserting that a monthly facilities fee of approximately $0.6 million charged since July 2001 to Atmos by Trans Louisiana Gas Pipeline, Inc., a wholly-owned subsidiary of Atmos, pursuant to a contract between the parties, was excessive. The Executive Secretary asserted that all monthly facilities fees in excess of approximately $0.1 million from July 2001 should be refunded to ratepayers with interest. In October 2003, the LPSC unanimously voted to approve an agreement to allow us to charge a facilities fee of approximately $0.5 million per month (subject to future escalation) beginning November 2003 for a period of 14 years. No retroactive adjustments were required under this agreement.

Atmos Energy Mid-States Division. In April 2006, Atmos filed a rate case in its Missouri service area seeking a rate increase of $3.4 million. The Company is proposing to consolidate the rates for its Missouri properties into three sets of regional rates and consolidate the current purchased gas adjustment (PGA) into one statewide PGA. The Company is also proposing a WNA mechanism. An evidentiary hearing is scheduled to begin on November 27, 2006, with an order expected to be issued in February 2007.

In March 2006, we received notification from the Tennessee Regulatory Authority (TRA) that it disagreed with the way we calculated amounts under its performance-based rate mechanism, which resulted in a one-time $3.3 million income reduction during the second quarter of fiscal 2006. We believe the original calculations were correct and have appealed the TRA’s decision.

During the third quarter of fiscal 2005, Atmos filed a rate case in its Georgia service area seeking a rate increase of $4.0 million. In December 2005, the Georgia Public Service Commission (GPSC) approved a $0.4 million increase. In January 2006, we filed an appeal of the GPSC’s decision in the Superior Court of Fulton County. Oral arguments were held on September 7, 2006 before the Fulton County Superior Court. The court affirmed the commission’s order. We are considering further appeal.

In November 2005, we received a notice from the TRA that it was opening an investigation into allegations by the Consumer Advocate and Protection Division of the Tennessee Attorney General’s Office that we were overcharging customers in parts of Tennessee by approximately $10 million per year. We responded to numerous data requests from the TRA Staff. In April 2006, the TRA Staff filed a Report and Recommendation in which it recommended that the TRA convene a contested case procedure for the purpose of establishing a fair and reasonable return. The TRA convened to consider the Staff’s recommendation on May 15, 2006 and set a procedural schedule. A hearing was held from August 29, 2006 through August 31, 2006. Of the $10 million rate reduction requested by the Consumer Advocate and Protection Division, the TRA approved on October 27, 2006 a $6.1 million reduction to future rates.

In February 2004, the Mid-States Division filed a rate case with the Virginia Corporation Commission (VCC) to request a $1.0 million increase in our base rates, WNA and recovery of the gas cost component of bad debt expense. The VCC granted a rate increase in November 2004 of $0.4 million that was retroactively effective to July 27, 2004. Additionally, the VCC authorized WNA beginning in July 2005 and the ability to recover the gas cost component of bad debt expense.

Atmos Energy Mid-Tex Division. The following is a discussion of our recent ratemaking activity for our Mid-Tex Division.

Rate Case

During fiscal 2006, we received “show cause” resolutions from approximately 80 cities served by our Mid-Tex Division, including the City of Dallas, which require us to demonstrate that existing distribution rates in the Mid-Tex Division are just and reasonable. In May 2006, in response to these resolutions, we filed a Statement of Intent to increase rates on a division-wide basis. By agreement with the cities, the “show cause” resolutions were consolidated and became part of the Mid-Tex Division’s first rate case before the RRC since we acquired the TXU Gas operations in October 2004. In this rate proceeding, we are seeking incremental annual revenues in the Mid-Tex Division of approximately $60 million and several rate design changes, including WNA, revenue stabilization and recovery of the gas cost component of bad debt expense.

In exchange for an agreement to provide the intervening parties in the proceeding additional time to prepare for the hearing, we obtained agreement from the intervenors to implement WNA in the rates for the Mid-Tex Division for the 2006-2007 winter season, which has been approved by the RRC, and to implement WNA in the final rates in this proceeding. The hearing in this proceeding was concluded on November 17, 2006, and a decision is due from the RRC no later than April 2007. During the hearing, the principal issues raised by the cities included the Mid-Tex Division’s rate of return, the reduction of rate base for the accumulated deferred federal income taxes and investment tax credits associated with the TXU Gas operations prior to our acquisition, the methodology used by us to allocate certain shared services expenses to the division, and the inclusion of certain items in operation and maintenance expenses.

In addition, under applicable statutes, the RRC is reviewing the interim rate adjustments that were previously granted in response to the Mid-Tex Division’s prior GRIP filings and our acquisition of the TXU Gas operations for consistency with the public interest. Any increase that the RRC may grant in this case would be effective prospectively from the date of the final order. However, any decrease that may be ordered by the RRC would be effective from May 31, 2006 pursuant to the agreement with the intervenors for consolidation of the show cause resolutions and the Statement of Intent filing. Any disallowance related to the previously granted GRIP interim rate adjustments would be refunded to customers with interest beginning some time after the issuance of a final order in this proceeding.

While the decision of the RRC in this case cannot be predicted with certainty, we believe that we have adequately demonstrated to the RRC that the Mid-Tex Division is entitled to receive an increase in annual revenues and that the remaining rate design changes should be implemented.

GRIP Filings

In March 2006, the Mid-Tex Division made a GRIP filing to include in rate base approximately $62.2 million of distribution capital expenditures incurred during calendar year 2005, which we estimate would result in additional annual revenues of approximately $11.9 million. The RRC approved this filing in August 2006, and the new customer charges were implemented in September 2006 billings to customers.

In September 2005, the Mid-Tex Division made a GRIP filing to include in rate base approximately $29.4 million of distribution capital expenditures incurred during calendar year 2004, which currently provides additional annual revenues of approximately $6.7 million. The RRC approved this filing in January 2006, and these new charges were included in the monthly customer charge beginning in February 2006.

In December 2004, the Mid-Tex Division made a GRIP filing to include in rate base approximately $32.0 million of distribution capital expenditures made by TXU Gas during calendar year 2003, which

currently provides additional annual revenues of approximately $6.7 million. New monthly customer charges were implemented in October 2005.

Other Regulatory Matters

In September 2006, the Mid-Tex Division filed its annual gas cost reconciliation with the RRC. The filing reflects approximately $24 million in refunds of amounts that were overcollected from customers between July 2005 and June 2006. The Mid-Tex Division has requested and received approval to refund these amounts over a six-month period beginning in November 2006.

In September 2004, the Mid-Tex Division filed its 36-Month Gas Contract Review with the RRC. This proceeding involves a review for reasonableness of gas purchases totaling $2.2 billion made by the Mid-Tex Division from November 2000 through October 2003. A hearing on this matter was held before the RRC in June 2005. The parties negotiated a unanimous settlement agreement providing for a refund of $8 million to customers over a three-year period and for reimbursement of parties’ expenses without recovery from customers. The RRC approved the settlement on September 12, 2006. Refunds to customers began in the first quarter of fiscal year 2007.

The Mid-Tex Division is also pursuing an appeal to the Travis County District Court of the Final Order in its last system-wide rate case completed in May 2004 to obtain a return of and on its investment associated with the Poly I replacement pipe that was originally disallowed in its rate case completed in May 2004. The case was argued before the Travis County District Court in July 2006. The Court ruled to uphold the Commission’s final order. Steps are being taken to perfect an appeal to the Court of Appeals in Travis County.

Atmos Energy Mississippi Division. Through the first quarter of fiscal 2005, the MPSC required that we file for rate adjustments every six months. Rate filings were made in May and November of each year and the rate adjustments typically became effective in the following July and January.

During the second quarter of fiscal 2005, we agreed with the MPSC to suspend our May 2005 semi-annual filing to allow sufficient time for us and the MPSC to undertake a comprehensive review in an effort to improve our rate design and the ratemaking process. Effective October 2005, our rate design was modified to substitute the original agreed-upon benchmark with a sharing mechanism to allow the sharing of cost savings above an allowed return on equity level. Further, we moved from a semi-annual filing process to an annual filing process. Additionally, our WNA period begins on November 1 instead of November 15, and ends on April 30 instead of May 15. Also, we now have a fixed monthly customer base charge which makes a portion of our earnings less susceptible to usage. As part of the rate design restructuring, we agreed to reduce our rates by approximately $0.6 million. We made our first annual filing under this new structure in September 2006 requesting no change in rates.

In September 2004, the MPSC originally disallowed certain deferred costs totaling $2.8 million. In connection with the modification of our rate design described above, the MPSC decided to allow these costs, and we included these costs in our rates in October 2005.

In June 2006, the MPSC approved a pilot program whereby Trans Louisiana Gas Pipeline (TLGP) will provide asset management services to the Mississippi Division. The asset management program allows TLGP to market certain off-peak gas supply assets, such as company-owned or leased storage and pipeline capacity, on a recallable basis. In return, TLGP will share net positive benefits of the asset management program with Mississippi ratepayers. The pilot program runs from June 1, 2006 to April 30, 2007 and may be extended by the MPSC upon application by Atmos.

In October 2003, the MPSC issued a final order that denied our May 2003 request for a rate increase of $5.8 million. In January 2004, the MPSC authorized additional annual revenue of $5.9 million on our November 2003 filing, which became effective in December 2003. In September 2004, the MPSC authorized additional annualized revenue of $4.7 million on our May 2004 filing, which became effective in June 2004.

We filed our second semiannual filing for 2004 in November 2004, requesting rate adjustments of $6.0 million in annualized revenue. The MPSC allowed us to include $3.0 million in annualized revenue in

our rates effective January 2005. In February 2005, we entered into an agreement with the Mississippi Public Utilities Staff that provides for an additional $1.3 million in annualized revenue that was retroactive to January 2005, which was approved by the MPSC during the second quarter of fiscal 2005.

Atmos Energy West Texas Division. In September 2005, the West Texas Division made a GRIP filing to include in rate base approximately $22.6 million of distribution capital costs incurred during calendar year 2004, which should result in additional annual revenues of approximately $3.8 million. Of this amount, approximately $1.3 million related to our Lubbock jurisdiction and the remaining $2.5 million related to our West Texas jurisdiction. New charges for the filings were included in the monthly customer charge beginning May 2006. Atmos made its 2005 GRIP filings for the West Texas Division and the Lubbock Division in September 2006 requesting no change in rates.

In January 2006, the Lubbock, Texas City Council passed a resolution requiring Atmos to submit copies of all documentation necessary for the city to review the rates of Atmos’ West Texas Division to ensure they are just and reasonable. The requested information was provided to the city on February 28, 2006. We believe that we will be able to ultimately demonstrate to the City of Lubbock that our rates are just and reasonable.

In May 2006, Atmos began receiving “show cause” ordinances from several of the cities in the West Texas Division. We made a filing in response to the ordinances on October 2, 2006. We believe that we will be able to ultimately demonstrate to the West Texas cities that our rates are just and reasonable.

In October 2003, our West Texas Division filed a rate case in Lubbock requesting a $3.0 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. The City of Lubbock approved a $1.5 million increase effective March 2004, as well as the proposed WNA.

In September 2003, our West Texas Division filed a rate case in its West Texas System to request a $7.7 million increase in annual revenues and WNA for its residential, commercial and public-authority customers. In May 2004, the 66 cities in its West Texas System approved an increase of $3.2 million in our annual utility revenues. The cities also approved a WNA rider for residential, commercial, public-authority and state-institution customers. This rider became effective in October 2004.

Other Regulation

Each of our utility 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. 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. These claims are fully described in Note 13 to the consolidated financial statements.

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.

Competition

Although our utility 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 and agricultural 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. In addition, our Natural Gas Marketing segment competes with other natural gas brokers in obtaining natural gas supplies for our customers.

Employees

At September 30, 2006, we had 4,632 employees, consisting of 4,402 employees in our utility segment and 230 employees in our other segments. See “Operating Statistics — Utility Sales and Statistical Data by Division” for the number of employees by division.

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, that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, 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 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 provisions of the Sarbanes-Oxley Act of 2002, related rules and regulations of the Securities and Exchange Commission as well as corporate governance-related listing standards of the New York Stock Exchange, the Board of Directors of the Company has adopted the Company’s Corporate Governance Guidelines and revised the Company’s Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, the Board of Directors has updated 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 the Company’s website. We will also provide copies of such information 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 factors, many of which are not within our control. Although we have tried to discuss key risk factors below, please be aware that other risks may prove to be important in the future. These factors include the following:

We are subject to regulation by each state in which we operate that affect our operations and financial results.

Our natural gas utility business is subject to various regulated returns on its rate base in each of the 12 states 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 the regulatory environment, assets may be placed in service and historical test periods established before rate cases that could adjust our returns can be filed. 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”. In addition, rate cases involve a risk of rate reduction, and once rates have been approved, they are still subject to challenge for their reasonableness by appropriate

regulatory authorities. Our debt and equity financings are also subject to approval by regulatory bodies in several states which could limit our ability to take advantage of favorable market conditions.

Our business could also be affected by deregulation initiatives, including the development of unbundling initiatives in the natural gas industry. Unbundling is the separation of the provision and pricing of local distribution gas services into discrete components. It typically focuses on the separation of the distribution and gas supply components and the resulting opening of the regulated components of sales services to alternative unregulated suppliers of those services. Although we believe that our enhanced technology and distribution system infrastructures have positively positioned us, we cannot provide assurance that there would be no significant adverse effect on our business should unbundling or further deregulation of the natural gas distribution service business occur.

Our operations are weather sensitive.

Our natural gas utility sales volumes and related revenues are correlated with heating requirements that result from cold winter weather. Although beginning in the 2006-2007 winter heating season, we will have weather-normalized rates for over 90 percent of our residential and commercial meters that should substantially eliminate the adverse effects of warmer-than-normal weather for meters in those service areas, our utility operating results will continue to vary with the temperatures during the winter heating season. In addition, 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.

The concentration of our distribution, pipeline and storage operations in the State of Texas have increased the exposure of our operations and financial results to adverse weather, economic conditions or regulatory decisions in Texas.

As a result of our acquisition of the distribution, pipeline and storage operations of TXU Gas in October 2004, over 50 percent of our natural gas distribution customers and most of our pipeline and storage assets and operations are now located in the State of Texas. This concentration of our business in Texas means that our operations and financial results are subject to greater impact than before from changes in the Texas economy in general as well as the weather in our service areas of the state during the winter heating season. Our financial results in fiscal 2006 were adversely affected by warm weather in Texas. In addition, the impact of any adverse rate or other regulatory decisions by state or local regulatory authorities in Texas will also be greater. The hearing in the Mid-Tex Division’s first rate case since the TXU Gas acquisition has just concluded. In the proceeding, we are seeking additional revenue and several rate design changes. A rate reduction or other significant, adverse decision by the Texas Railroad Commission in the proceeding could materially affect our financial results.

We are subject to environmental regulation 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. Such revised or new regulations could result in increased compliance costs or additional operating restrictions which could adversely affect our business, financial condition and results of operations.

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

Our risk management operations are subject to market risks beyond our control including market liquidity, commodity price volatility 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 or the risk in our natural gas marketing and pipeline and storage segments which could lead to volatility in our earnings. Physical trading 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. 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. The determination of our net open position as of any 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 each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. 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 because the timing of the recognition of profits or losses on the hedges for financial accounting purposes does not always match up with 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. Further, if the local physical markets in which we trade do not move consistently with the NYMEX futures market, we could experience increased volatility in the financial results of our natural gas marketing and pipeline and storage segments.

Our natural gas marketing and pipeline and storage 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 derivatives. 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. 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.

We are also subject to interest rate risk on our commercial paper borrowings and floating rate debt. In the past few years, we have been operating in a relatively low interest-rate environment with both short and long-term interest rates being relatively low compared to past interest rates. However, in the past two years, the Federal Reserve has taken actions that have resulted in increases in short-term interest rates. Future increases in interest rates could adversely affect our future financial results.

The execution of our business plan could be affected by an inability to access financial markets.

We rely upon access to both short-term and long-term capital markets to satisfy our liquidity requirements. Adverse changes in the economy or these markets, the overall health of the industries in which we operate and changes to our credit ratings could limit access to these markets, increase our cost of capital or restrict the execution of our business plan.

Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation (S&P), Moody’s Investors Services, Inc. (Moody’s) and Fitch Ratings, Ltd. (Fitch), the three credit rating agencies that rate our long-term debt securities. There can be no assurance that these rating agencies will maintain investment grade ratings for our long-term debt. If we were to lose our investment-grade rating, the commercial paper markets and the commodity derivatives markets could become unavailable to us. This would increase our borrowing costs for working capital and reduce the borrowing capacity of our gas marketing affiliate. In addition, if our commercial paper ratings were lowered, it would increase the cost of commercial

paper financing and could reduce or eliminate our ability to access the commercial paper markets. If we are unable to issue commercial paper, we intend to borrow under our bank credit facilities to meet our working capital needs. This would increase the cost of our working capital financing.

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 utility 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 influence future results.

Rapid increases in the price of purchased gas, which occurred recently and in some prior years, cause us to experience a significant increase in short-term debt because 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 utility 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 operations are subject to increased competition.

In the residential and commercial customer markets, our regulated utility 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, resulting in reduced 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, and agricultural customers, 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 pipeline and storage operations currently face limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, competition may increase if new intrastate pipelines are constructed near our existing facilities.

The cost of providing pension and postretirement health care benefits is subject to changes in pension fund values and changing demographics and may have a material adverse effect on our financial results.

We provide a cash-balance pension plan for the benefit of eligible full-time employees as well as postretirement health care benefits to eligible full-time employees. Our costs of providing such benefits is subject to changes in the market value of our pension fund assets, changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years, and various actuarial calculations and assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates and other factors. These differences may result in a significant impact on the amount of pension expense or other postretirement benefit costs recorded in future periods.

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 maintain the 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. Our cash flows from operations are generally not sufficient to supply funding for all our capital expenditures including the financing of the costs of this new construction along with capital expenditures necessary to maintain our existing natural gas system. As a result, we must fund at least a portion of these costs through borrowing funds from third party lenders, the cost of which is dependent on the interest rates at the time. 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.

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 financial position and results of operations could be adversely affected.

Natural disasters and terrorist activities and other actions 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 future financial results.


ITEM 1B.	*Unresolved Staff Comments*

Not applicable.


ITEM 2.	*Properties*

Distribution, transmission and related assets

At September 30, 2006, our utility segment owned an aggregate of 75,869 miles of underground distribution and transmission mains throughout our gas distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. At September 30, 2006, our pipeline and storage segment owned 6,127 miles of gas transmission and gathering lines.

Our utility segment also holds franchises granted by the incorporated cities and towns that we serve. At September 30, 2006, we held 1,103 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.

Storage Assets

Our utility and pipeline and storage segments 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:


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

Utility Segment
Kentucky		4,442,696		6,322,283		10,764,979		109,100
Kansas		3,639,000		2,640,000		6,279,000		55,000
Mississippi		1,544,633		2,181,737		3,726,370		48,000
Georgia		450,000		50,000		500,000		30,000

Total Utility Segment		10,076,329		11,194,020		21,270,349		242,100

Pipeline and Storage Segment
Texas		39,128,475		13,128,025		52,256,500		1,235,000
Kentucky		3,492,900		3,295,000		6,787,900		71,000
Louisiana		438,583		300,973		739,556		56,000

Total Pipeline and Storage Segment		43,059,958		16,723,998		59,783,956		1,362,000

Total		53,136,287		27,918,018		81,054,305		1,604,100


⁽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:


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

Utility Segment
Colorado-Kansas Division	Southern Star Central Pipeline		2,719,101		82,397
	Tenaska Marketing Ventures		1,000,000		10,400
	Colorado Interstate Gas Company		422,142		12,985
	Kinder Morgan, Inc.		67,500		1,500
	Centerpoint Energy Gas Transmission		28,500		950
Kentucky Division	Texas Gas Transmission		3,841,150		41,060
	Tennessee Gas Pipeline Company		1,313,538		22,698
Louisiana Division	Gulf South		1,978,020		98,901
	Jefferson Island Storage & Hub		600,000		60,000
	Acadian Natural Gas Company		33,276		2,234
	Tennessee Gas Pipeline Company		18,776		329
	Southern Natural Gas Company		12,945		261
	Trunkline Gas Company		3,105		41
Mid-States Division	Atmos Energy Marketing		1,993,543		16,634
	Southern Natural Gas Company		1,453,265		29,345
	Panhandle Eastern Pipeline		1,035,462		15,721
	Tennessee Gas Pipeline Company		835,674		20,000
	Texas Eastern Transmission Company		753,969		11,303
	Gallagher Drilling Company⁽²⁾		640,000		5,000
	ANR Pipeline Company		629,480		11,200
	Dominion		609,008		8,136
	Transco		568,674		12,710
	Virginia Gas Pipeline Company		380,000		23,000
	East Tennessee		339,900		52,633
	Natural Gas Pipeline Company		312,750		5,580
	Texas Gas Transmission		239,576		7,495
	CMS Trunkline Gas Company		220,455		2,940
	MRT Energy Marketing		137,493		2,395
Mississippi Division	Gulf South		1,237,500		61,875
	Southern Natural Gas Company		1,049,436		21,191
	Texas Gas Transmission		826,390		36,420
	Texas Eastern		518,220		8,637
	Atmos Energy Marketing		400,000		40,000
	Trunkline Gas Company		24,840		331
	Tennessee Gas Pipeline Company		3,394		113
West Texas Division	ONEOK Texas Gas Storage LLP		1,125,000		50,000

Total Utility Segment			27,372,082		776,415

See footnotes on the following page.


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

Natural Gas Marketing Segment
Atmos Energy Marketing, LLC
	Gulf South		5,992,015		85,686
	Egan		1,500,000		90,000
	Atmos Pipeline — Texas		1,000,000		24,000
	Texas Eastern Transmission Company		544,841		5,532
	East Tennessee		250,000		12,500
	National Fuel		223,080		2,028
	Virginia Gas Pipeline Company		170,000		17,000
	Dominion		56,910		929

Total Natural Gas Marketing Segment			9,736,846		237,675

Pipeline and Storage Segment
Trans Louisiana Gas Pipeline, Inc.	Gulf South Pipeline Company		750,000		30,000
	Bridgeline Gas Distribution LLC		300,000		30,000

Total Pipeline and Storage Segment			1,050,000		60,000

Total Contracted Storage Capacity			38,158,928		1,074,090


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

⁽²⁾		We contract for storage service in two underground storage facilities, Wiseman and Ellis, from this company.

Other facilities

Our utility 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 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. Our nonutility operations are headquartered in Houston, Texas, with offices in Houston and other locations, primarily in leased facilities.


ITEM 3.	*Legal Proceedings*

See Note 13 to the consolidated financial statements.


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 2006.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2006, 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		59		9	Chairman, President and Chief Executive Officer
Kim R. Cocklin		55		—	Senior Vice President, Utility Operations
R. Earl Fischer		67		44	Senior Vice President, Utility Operations
Louis P. Gregory		51		6	Senior Vice President and General Counsel
Mark H. Johnson		47		5	Senior Vice President, Nonutility Operations and President, Atmos Energy Marketing, LLC
Wynn D. McGregor		53		18	Senior Vice President, Human Resources
John P. Reddy		53		8	Senior Vice President and Chief Financial Officer

Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997.

Kim R. Cocklin joined the Company in June 2006 as Senior Vice President, Utility Operations to succeed R. Earl Fischer, who retired from the Company on September 30, 2006. Prior to joining the Company, Mr. Cocklin served as Senior Vice President, General Counsel and Chief Compliance Officer of Piedmont Natural Gas Company from February 2003 to May 2006. Prior to joining Piedmont, Mr. Cocklin was with Williams Gas Pipeline from 1995 to January 2003, where he served in various capacities, including serving as Vice President for rates, regulatory and business development for all of the Williams Gas pipelines from 2001 to January 2003.

R. Earl Fischer was named Senior Vice President, Utility Operations in May 2000. Mr. Fischer previously served the Company as President of the Mid-Tex Division from October 2004 to October 2005. Mr. Fischer retired from the Company on September 30, 2006.

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

Mark H. Johnson was named Senior Vice President, Nonutility Operations in April 2006 and President of Atmos Energy Holdings, Inc., and Atmos Energy Marketing, LLC, in April 2005. Mr. Johnson previously served the Company as Vice President, Nonutility Operations from October 2005 to March 2006 and as Executive Vice President of Atmos Energy Marketing from October 2003 to March 2005. Mr. Johnson joined Atmos Energy Marketing’s predecessor, Woodward Marketing, L.L.C., in 1992 as Vice President of Marketing and Operations and was later promoted to Senior Vice President of Marketing for the Midwest and Gulf Coast. Mr. Johnson succeeded JD Woodward III who retired from the Company effective April 1, 2006.

Wynn D. McGregor was named Senior Vice President, Human Resources in October 2005. He previously served the Company as Vice President, Human Resources from January 1994 to September 2005.

John P. Reddy was named Senior Vice President and Chief Financial Officer in September 2000.

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 2006 and 2005 are listed below. The high and low prices listed are the closing NYSE quotes for shares of our common stock:


	2006						2005
					Dividends						Dividends
	High		Low		Paid		High		Low		Paid

Quarter ended:
December 31	$	28.36	$	25.79	$	.315	$	27.43	$	24.85	$	.310
March 31		27.00		26.10		.315		29.09		26.19		.310
June 30		27.91		26.00		.315		28.87		25.94		.310
September 30		29.11		27.96		.315		29.76		28.23		.310

					$	1.26					$	1.24

Dividends are payable at the discretion of our Board of Directors out of legally available funds and are also subject to restriction under the terms of our First Mortgage Bond agreement. See Note 6 to the consolidated financial statements. 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, 2006 was 24,425. 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 2006 that were not registered under the Securities Act of 1933, as amended.

The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2006.


	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,		Outstanding Options,		Plans (Excluding Securities
	Warrants and Rights		Warrants and Rights		Reflected in Column (a))
	(a)		(b)		(c)

Equity compensation plans approved by security holders:
Long-Term Incentive Plan		1,017,152	$	22.57		731,745
Long-Term Stock Plan for the
Mid-States Division		—		—		168,550

Total equity compensation plans approved by security holders		1,017,152		22.57		900,295
Equity compensation plans not approved by security holders		—		—		—

Total		1,017,152	$	22.57		900,295


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.


	Year Ended September 30
	2006⁽¹⁾			2005⁽²⁾		2004⁽³⁾		2003⁽⁴⁾			2002
	(In thousands, except per share data and ratios)

Results of Operations
Operating revenues	$	6,152,363		$	4,961,873	$	2,920,037	$	2,799,916		$	1,650,964
Gross profit		1,216,570			1,117,637		562,191		534,976			431,140
Operating expenses⁽¹⁾		833,954			768,982		368,496		347,136			275,809
Operating income		382,616			348,655		193,695		187,840			155,331
Miscellaneous income (expense)⁽³⁾		881			2,021		9,507		2,191			(1,321	)
Interest charges		146,607			132,658		65,437		63,660			59,174
Income before income taxes and cumulative effect of accounting change		236,890			218,018		137,765		126,371			94,836
Cumulative effect of accounting change, net income tax benefit		—			—		—		(7,773	)		—
Income tax expense		89,153			82,233		51,538		46,910			35,180
Net income	$	147,737		$	135,785	$	86,227	$	71,688		$	59,656
Weighted average diluted shares outstanding		81,390			79,012		54,416		46,496			41,250
Diluted net income per share	$	1.82		$	1.72	$	1.58	$	1.54		$	1.45
Cash flows from operations		311,449			386,944		270,734		49,541			297,395
Cash dividends paid per share	$	1.26		$	1.24	$	1.22	$	1.20		$	1.18
Total utility throughput (MMcf)		393,995			411,134		246,033		247,965			208,541
Total natural gas marketing sales volumes (MMcf)		283,962			238,097		222,572		225,961			204,027
Total pipeline transportation volumes (MMcf)		420,217			383,377		—		—			—
Financial Condition
Net property, plant and equipment⁽⁵⁾	$	3,629,156		$	3,374,367	$	1,722,521	$	1,624,394		$	1,380,070
Working capital⁽⁵⁾		(1,616	)		151,675		283,310		16,248			(139,150	)
Total assets⁽⁵⁾⁽⁶⁾		5,719,547			5,653,527		2,912,627		2,625,495			2,059,631
Short-term debt, inclusive of current maturities of long-term debt		385,602			148,073		5,908		127,940			167,771
Capitalization:
Shareholders’ equity		1,648,098			1,602,422		1,133,459		857,517			573,235
Long-term debt (excluding current maturities)		2,180,362			2,183,104		861,311		862,500			668,959

Total capitalization		3,828,460			3,785,526		1,994,770		1,720,017			1,242,194
Capital expenditures		425,324			333,183		190,285		159,439			132,252
Financial Ratios
Capitalization ratio⁽⁶⁾		39.1%			40.7%		56.7%		46.4%			40.7%
Return on average shareholders’ equity⁽⁷⁾		8.9%			9.0%		9.1%		9.9%			9.9%

See footnotes on the following page.


⁽¹⁾		Financial results for 2006 include a $22.9 million pre-tax loss for the impairment of the West Texas Division’s irrigation assets.

⁽²⁾		Financial results for 2005 include the results of the Mid-Tex Division and Atmos Pipeline — Texas Division from October 1, 2004, the date of acquisition.

⁽³⁾		Financial results for 2004 include a $5.9 million pre-tax gain on the sale of our interest in U.S. Propane, L.P. and Heritage Propane Partners, L.P.

⁽⁴⁾		Financial results for fiscal 2003 include the results of MVG from December 3, 2002, the date of acquisition.

⁽⁵⁾		Beginning in 2004, we reclassified our regulatory cost of removal obligation from accumulated depreciation to a liability. The amounts presented above for property, plant and equipment, working capital and total assets reflect this reclassification for all periods presented. These reclassifications did not impact our financial position, results of operations or cash flows as of and for the years ended September 30, 2003 and 2002.

⁽⁶⁾		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. Beginning in 2004 we reclassified our original issue discount costs from deferred charges and other assets to long-term debt. This reclassification did not materially impact our capitalization or our capitalization ratio as of September 30, 2003 and 2002.

⁽⁷⁾		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.

The following table presents a condensed income statement by segment for the year ended September 30, 2006.


	Year Ended September 30, 2006
			Natural Gas		Pipeline		Other
	Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	3,649,851	$	2,418,856	$	81,857	$	1,799	$	—		$	6,152,363
Intersegment revenues		740		737,668		78,710		4,099		(821,217	)		—

		3,650,591		3,156,524		160,567		5,898		(821,217	)		6,152,363
Purchased gas cost		2,725,534		3,025,897		838		—		(816,476	)		4,935,793

Gross profit		925,057		130,627		159,729		5,898		(4,741	)		1,216,570
Operating expenses		723,163		28,392		81,871		5,506		(4,978	)		833,954

Operating income		201,894		102,235		77,858		392		237			382,616
Miscellaneous income		9,506		2,598		2,554		4,151		(17,928	)		881
Interest charges		126,489		8,510		25,331		3,968		(17,691	)		146,607

Income before income taxes		84,911		96,323		55,081		575		—			236,890
Income tax expense		31,909		37,757		19,457		30		—			89,153

Net income	$	53,002	$	58,566	$	35,624	$	545	$	—		$	147,737

Capital expenditures	$	307,742	$	909	$	116,673	$	—	$	—		$	425,324


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.

Our performance in the future will primarily depend on the results of our utility and nonutility operations. 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: regulatory trends and decisions, including deregulation initiatives and the impact of rate proceedings before various state regulatory commissions; adverse weather conditions, such as warmer than normal weather in our utility service territories or colder than normal weather that could adversely affect our natural gas marketing activities; the concentration of our distribution, pipeline and storage operations in one state; impact of environmental regulations on our business; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; our ability to continue to access the capital markets; the effects of inflation and changes in the availability and prices of natural gas, including the volatility of natural gas prices; increased competition from energy suppliers and alternative forms of energy; increased costs of providing pension and postretirement health care benefits; the capital-intensive nature of our distribution business, the inherent hazards and risks involved in operating our distribution business, and other risks and uncertainties discussed herein, especially 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.

OVERVIEW

In fiscal 2006, we earned $147.7 million in net income or $1.82 per diluted share, compared with net income of $135.8 million, or $1.72 per diluted share in fiscal 2005. The nine percent year-over-year increase in net income was primarily attributable strong financial results in our natural gas marketing segment as it was able to capture higher margins in a volatile natural gas market and favorable unrealized mark-to-market gains. Additionally, pipeline and storage net income increased 16 percent compared with the prior year. These positive results helped overcome the adverse effects on our utility segment of weather (adjusted for WNA) that

was 13 percent warmer than normal, the adverse effect of Hurricane Katrina on our Louisiana Division and a non-recurring, noncash charge to impair certain assets. Our utility operations contributed $53.0 million ($0.65 per diluted share) or 36 percent to fiscal 2006 results. Our nonutility operations, comprised of our natural gas marketing, pipeline and storage and other nonutility segments, contributed $94.7 million ($1.17 per diluted share) or 64 percent to fiscal 2006 results. Key financial and other events for fiscal 2006 include the following:


	•	Our utility segment net income decreased $28.1 million during the year ended September 30, 2006 compared with the year ended September 30, 2005. The decrease primarily resulted from the impact of weather, as adjusted for jurisdictions with weather-normalized rates, that was two percent warmer than the prior-year period and 13 percent warmer than normal, coupled with higher operating expenses. Utility segment results also reflect a $14.6 million net of tax charge associated with the impairment of the West Texas Division’s irrigation assets.

	•	During fiscal 2006, our Louisiana and Mid-Tex divisions received WNA in their rate designs that will go into effect in fiscal 2007. After receiving WNA in these two jurisdictions, we will have weather protection for over 90 percent of our residential and commercial meters for the 2006-2007 winter heating season.

	•	Our natural gas marketing segment net income increased $35.2 million during the year ended September 30, 2006 compared with the year ended September 30, 2005. The increase in natural gas marketing net income primarily reflects an increase in our unrealized margin of $43.2 million and increased realized margins due to our ability to capture higher margins in a volatile natural gas market. These increases were partially offset by a $7.4 million increase in operating expenses and increased interest charges resulting from increased short-term borrowings to fund working capital needs.

	•	Our pipeline and storage segment net income increased $5.0 million during the year ended September 30, 2006 compared with the year ended September 30, 2005. Increased gross profit margin resulting from higher transportation and related services margins coupled with increased throughput on our Atmos Pipeline-Texas system and Atmos Pipeline & Storage, LLC’s ability to capture more favorable arbitrage spreads in its asset management contracts were partially offset by higher operating expenses.

	•	Our capitalization ratio at September 30, 2006 was 60.9 percent compared with 59.3 percent at September 30, 2005 reflecting the impact of increased short-term debt borrowings to fund working capital needs partially offset by current-year net income.

	•	For the year ended September 30, 2006, we generated $311.4 million in operating cash flow compared with $386.9 million for the year ended September 30, 2005, reflecting the adverse impact of high natural gas costs on our working capital.

	•	Capital expenditures increased to $425.3 million from $333.2 million primarily reflecting increased capital spending for various pipeline expansion projects in our Atmos Pipeline — Texas Division.

Our financial performance is discussed in greater detail below in Results of Operations.

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, allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the 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 utility operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our regulated utility operations are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement requires cost-based, rate-regulated entities that meet certain criteria to reflect the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions in their financial statements. We record regulatory assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are recorded 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 because they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. The impact of regulation on our utility operations may be affected by decisions of the regulatory authorities or the issuance of new regulations.

Revenue recognition — Sales of natural gas to our utility customers are billed on a monthly cycle 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 utility 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 regulators and are subject to refund. As permitted by SFAS No. 71, 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 cost through purchased gas adjustment mechanisms. Purchased gas 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’s non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of expense, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility’s other costs, (ii) represents a large component of the utility’s cost of service and (iii) is generally outside the control of the gas utility. There is no gross profit generated through purchased gas adjustments, but they do provide a dollar-for-dollar offset to increases or decreases in utility gas costs. Although substantially all of our utility sales to our customers fluctuate with the cost of gas that we purchase, utility gross profit is generally not affected by fluctuations in the cost of gas due to the purchased gas adjustment mechanism. The effects of these purchased gas adjustment mechanisms are recorded as deferred gas costs on our balance sheet.

Energy trading contracts resulting in the delivery of a commodity where we are the principal in the transaction are recorded as natural gas marketing sales or purchases at the time of physical delivery. Realized gains and losses from the settlement of financial instruments that do not result in physical delivery related to our natural gas marketing energy trading contracts and unrealized gains and losses from changes in the market value of open contracts are included as a component of natural gas marketing revenues.

Allowance for doubtful accounts — 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 different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Derivatives and hedging activities — In our utility segment, we use a combination of storage and financial derivatives to partially insulate us and our natural gas utility customers against gas price volatility

during the winter heating season. The financial derivatives we use in our utility segment are accounted for under the mark-to-market method pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Changes in the valuation of these derivatives primarily result from changes in the valuation of the portfolio of contracts, the maturity and settlement of contracts and newly originated transactions. However, because the costs of financial derivatives used in our utility segment will ultimately be recovered through our rates, current period changes in the assets and liabilities from these risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. The changes in the assets and liabilities from risk management activities are recognized in purchased gas cost in the income statement when the related costs are recovered through our rates.

Our natural gas marketing risk management activities are conducted through our natural gas marketing segment. This segment is exposed to risks associated with changes in the market price of natural gas, which we manage through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date. The use of these contracts is subject to our risk management policies, which are monitored for compliance daily.

We participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers. Additionally, we engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase or sell physical natural gas and then sell or purchase financial contracts at a price sufficient to cover our carrying costs and provide a gross profit margin. Through the use of transportation and storage services and derivatives, we seek to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

Under SFAS 133, natural gas inventory is designated as the hedged item in a fair-value hedge by AEM and Atmos Pipeline and Storage LLC. This inventory is marked to market at the end of each month with changes in fair value recognized as unrealized gains or losses in revenue in the period of change. Effective October 2005, we changed the index used to value our physical natural gas from Inside FERC to Gas Daily to better reflect the prices of our physical commodity. This change had no material impact on our financial position on the date of adoption. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenue and the carrying value of the inventory as an associated purchased gas cost in our consolidated statement of income when we sell the gas and deliver it out of the storage facility.

Derivatives associated with our natural gas inventory are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in the period of change. The difference in the indices used to mark to market our physical inventory (Gas Daily) and the related fair-value hedges (NYMEX) are reported as a component of revenue and can result in volatility in our reported net income. 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 continually manage our positions and seek to optimize value as market conditions and other circumstances change. We elect to exclude the differential between the spot price used to value our physical inventory and the forward price used to value the financial hedges designated against our physical inventory for purposes of assessing the effectiveness of these fair-value hedges.

Similar to our inventory position, we attempt to mitigate substantially all of the commodity price risk associated with our fixed-price contracts with minimum volume requirements through the use of various offsetting derivatives. Prior to April 2004, these derivatives were not designated as hedges under SFAS 133 because they naturally locked in the economic gross profit margin at the time we entered into the contract. The fixed-price forward and offsetting derivative contracts were marked to market each month with changes in fair value recognized as unrealized gains and losses recorded in revenue in our consolidated statement of income. The unrealized gains and losses were realized as a component of revenue in the period in which we fulfilled the requirements of the fixed-price contract and the derivatives settled. To the extent that the

unrealized gains and losses of the fixed-price forward contracts and the offsetting derivatives did not offset exactly, our earnings experienced some volatility. At delivery, the gains and losses on the fixed-price contracts were offset by gains and losses on the derivatives, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

Effective April 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales. As a result, we ceased marking the fixed-price forward contracts to market. We designated the offsetting derivative contracts as cash flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on these open derivative contracts have been 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.

Additionally, we utilize 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. Although the purpose of these instruments is to either reduce basis or other risks or lock in arbitrage opportunities, these derivative instruments have not been designated as hedges. Accordingly, these derivative instruments are recorded at fair value with all changes in fair value included in revenue in our natural gas marketing segment.

During fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the anticipated issuance of $875 million of long-term debt. We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. This realized loss is being recognized as a component of interest expense over the life of the related financing arrangements.

The fair value of our financial derivatives is determined through a combination of prices actively quoted on national exchanges, prices provided by other external sources and prices based on models and other valuation methods. Changes in the valuation of our financial derivatives primarily result from 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 derivatives. We believe the market prices and models used to value these derivatives 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.

Impairment assessments — We perform impairment assessments of our goodwill, intangible assets subject to amortization and long-lived assets. We currently have 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 utility divisions and wholly-owned subsidiaries. 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 periodically evaluate whether events or circumstances have occurred that indicate that our intangible assets subject to amortization and other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of these assets by determining whether the carrying value will be recovered through expected future cash flows. 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. We review the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities annually based upon a June 30 measurement date. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. When establishing our discount rate, we consider high quality corporate bond rates based on Moody’s Aa bond index, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with a high quality corporate bond spot rate curve.

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 cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan cost over a period of approximately ten to twelve years.

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 cost ultimately recognized. A 0.25 percent change in our discount rate would impact our pension and postretirement cost by approximately $1.1 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement cost by approximately $0.8 million.

RESULTS OF OPERATIONS

The following table presents our financial highlights for the three fiscal years ended September 30, 2006:


	For the Year Ended September 30
	2006		2005		2004
	(In thousands, unless otherwise noted)

Operating revenues	$	6,152,363	$	4,961,873	$	2,920,037
Gross profit		1,216,570		1,117,637		562,191
Operating expenses		833,954		768,982		368,496
Operating income		382,616		348,655		193,695
Miscellaneous income		881		2,021		9,507
Interest charges		146,607		132,658		65,437
Income before income taxes		236,890		218,018		137,765
Income tax expense		89,153		82,233		51,538
Net income	$	147,737	$	135,785	$	86,227

Utility sales volumes — MMcf		272,033		296,283		173,219
Utility transportation volumes — MMcf		121,962		114,851		72,814

Total utility throughput — MMcf		393,995		411,134		246,033

Natural gas marketing sales volumes — MMcf		283,962		238,097		222,572

Pipeline transportation volumes — MMcf		420,217		383,377		—

Heating Degree Days ⁽¹⁾
Actual (weighted average)		2,527		2,587		3,271
Percent of normal		87%		89%		96%
Consolidated utility average transportation revenue per Mcf	$	0.50	$	0.51	$	0.42
Consolidated utility average cost of gas per Mcf sold	$	10.02	$	7.41	$	6.55


⁽¹⁾		Adjusted for service areas that have weather normalized operations. 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.

The following table shows our operating income by utility division and by segment for the three fiscal years ended September 30, 2006. The presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	2006					2005					2004
			Heating					Heating						Heating
			Degree Days					Degree Days						Degree Days
	Operating		Percent of			Operating		Percent of			Operating			Percent of
	Income		Normal⁽¹⁾			Income		Normal⁽¹⁾			Income			Normal⁽¹⁾
	(In thousands, except degree day information)

Colorado-Kansas	$	22,524		99	%	$	25,157		99	%	$	20,876			99	%
Kentucky		14,338		100	%		18,657		98	%		22,738			98	%
Louisiana		27,772		78	%		24,819		78	%		40,762			93	%
Mid-States		35,555		95	%		35,687		93	%		38,778			95	%
Mid-Tex		71,703		72	%		84,965		80	%		—			—
Mississippi		23,276		102	%		19,045		96	%		18,709			101	%
West Texas		2,215		100	%		27,520		99	%		22,090			90	%
Other		4,511		—			515		—			(4,063	)		—

Utility segment		201,894		87	%		236,365		89	%		159,890			96	%
Natural gas marketing segment		102,235		—			40,985		—			27,726			—
Pipeline and storage segment		77,858		—			70,286		—			5,293			—
Other nonutility segment		629		—			1,019		—			786			—

Consolidated operating income	$	382,616		87	%	$	348,655		89	%	$	193,695			96	%


⁽¹⁾		Adjusted for service areas that have weather-normalized operations. 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.

Year ended September 30, 2006 compared with year ended September 30, 2005

Utility segment

Our utility segment has historically contributed 65 to 85 percent of our consolidated net income. However, during fiscal 2006, our utility segment contributed approximately 36 percent of our consolidated net income primarily due to the adverse effect of significantly warmer than normal weather, the adverse effect of Hurricane Katrina and a non-recurring, noncash charge to recognize the impairment of our irrigation assets. The primary factors that impact the results of our utility operations are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas sales to residential, commercial and public-authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Accordingly, our second fiscal quarter has historically been our most critical earnings quarter with an average of approximately 64 percent of our consolidated net income having been earned in the second quarter during the three most recently completed fiscal years. Additionally, we typically experience higher levels of accounts receivable, accounts payable, gas stored underground and short-term debt balances during the winter heating season due to the seasonal nature of our revenues and the need to purchase and store gas to support these operations. Utility sales to industrial customers are much less weather sensitive.

Changes in the cost of gas impact revenue but do not directly affect our gross profit from utility operations because the fluctuations in gas prices are passed through to our customers. Accordingly, we believe gross profit margin is a better indicator of our financial performance than revenues. However, higher gas costs may cause customers to conserve or, in the case of industrial customers, to use alternative energy sources. Higher gas costs may also 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.

The effects of weather that is above or below normal are substantially offset through weather normalization adjustments in most of our service areas. WNA allows us to increase the base rate portion of customers’ bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. Accordingly, in our WNA service areas, our gross profit margin should be based substantially on the amount of gross profit that would result from normal weather, despite actual weather conditions that may be either warmer or colder than normal.

During fiscal 2006, we received WNA in our two most weather sensitive jurisdictions: the Louisiana and Mid-Tex divisions. With the addition of WNA in these two jurisdictions, we will have weather protection for over 90 percent of our residential and commercial meters for the 2006-2007 winter heating season. Prior to these decisions, there was limited weather protection in these jurisdictions. The Louisiana Division had previously benefited from a higher base customer charge. However, this rate structure was not as beneficial during periods where weather was significantly warmer than normal. In May 2006, the LPSC approved a settlement that provided for a modified WNA which provides a partial decoupling mechanism to stabilize this jurisdiction’s margins. The approved WNA will cover a period from December to March.

Prior to October 1, 2006, the Mid-Tex Division, which is our largest utility division and contains almost 50 percent of our approximately 3.2 million distribution customers, had benefited from a rate structure that combined a monthly customer charge with a declining block rate schedule to partially mitigate the impact of warmer-than-normal weather on revenue. The combination of the monthly customer charge and the customer billing under the first block of the declining block rate schedule provided for the recovery of a significant portion of our fixed costs for such operations under average weather conditions. However, this rate structure was not as beneficial during periods where weather was significantly warmer than normal.

In July 2006, in connection with the Mid-Tex Division rate proceeding the RRC approved an interim and a permanent WNA effective October 1, 2006 for the Mid-Tex Division. The WNA covers the period from October through May. The interim WNA is based on 30 years of weather history, and the permanent WNA will be modified or adjusted to conform to the rate design that the RRC ultimately approves in the rate proceeding, which proceeding is described in greater detail under Recent Ratemaking Activity.

In the pending rate proceeding before the RRC, we are seeking for our Mid-Tex Division additional annual revenues of approximately $60 million and several rate design changes including revenue stabilization and recovery of the gas cost component of bad debt expense. While the outcome of the Mid-Tex Division’s pending rate proceeding before the RRC cannot be predicted with certainty, we believe that we have adequately demonstrated to the RRC that the Mid-Tex Division is entitled to receive an increase in annual revenues and that the remaining rate design changes should be implemented. However, if the RRC were to deny an increase in the Mid-Tex Division’s rates or not allow new rate design changes the Mid-Tex Division has requested, our business, financial condition and results of operations could be adversely affected in the future.

Operating income

Utility gross profit increased to $925.1 million for the year ended September 30, 2006 from $907.4 million for the year ended September 30, 2005. Total throughput for our utility business was 394.0 Bcf during the current year compared to 411.1 Bcf in the prior year.

The increase in utility gross profit, despite lower throughput, primarily reflects higher franchise fees and state gross receipts taxes, which are paid by utility customers and have no permanent effect on net income. Additionally, margins increased approximately $14.0 million due to rate increases received from our fiscal 2005 and fiscal 2004 GRIP filings and the recognition of $6.2 million that had been previously deferred in Louisiana following the LPSC’s ratification of our agreement in May 2006. These increases were partially offset by approximately $22.9 million due to the impact of significantly warmer than normal weather, particularly in our Mid-Tex and Louisiana divisions. For the year ended September 30, 2006, weather was

13 percent warmer than normal, as adjusted for jurisdictions with weather-normalized operations and two percent warmer than the prior year. In the Mid-Tex and Louisiana Divisions, which did not have weather-normalized rates during the 2005-2006 winter heating season, weather was 28 percent and 22 percent warmer than normal.

Additionally, utility gross profit decreased approximately $2.9 million compared with the prior year in the Louisiana Division due to the impact of Hurricane Katrina. Service has been restored in some areas affected by the storm; however, it is not likely that service will be restored to all of the affected service areas. As more fully described under Recent Ratemaking Activity, we implemented new rates in September 2006 that reflect the impact of Hurricane Katrina.

Operating expenses increased to $723.2 million for the year ended September 30, 2006 from $671.0 million for the year ended September 30, 2005. The increase reflects a $13.3 million increase in taxes, primarily related to franchise fees and state gross receipts taxes, both of which are calculated as a percentage of revenue, and are paid by our customers as a component of their monthly bills. Although these amounts are included as a component of revenue in accordance with our tariffs, timing differences between when these amounts are billed to our customers and when we recognize the associated expense may affect net income favorably or unfavorably on a temporary basis. However, there is no permanent effect on net income.

Operation and maintenance expense, excluding the provision for doubtful accounts, increased $7.8 million primarily due to higher employee costs associated with increased headcount to fill positions that were previously outsourced to a third party, higher medical and dental claims and increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs. Increased line locate, telecommunication and facilities costs also contributed to the overall increase. These increases were partially offset by a reduction in third-party costs for outsourced administrative and meter reading functions that were in-sourced during fiscal 2006. Operation and maintenance expense for the year ended September 30, 2006 was also favorably impacted by the absence of $2.1 million of merger and integration cost amortization associated with the merger of United Cities Gas Company in July 1997, as these costs were fully amortized by December 2004.

The provision for doubtful accounts increased $3.1 million to $20.6 million for the year ended September 30, 2006, compared with $17.5 million in the prior year. The increase was primarily attributable to increased collection risk associated with higher natural gas prices. In the utility segment, the average cost of natural gas for the year ended September 30, 2006 was $10.02 per Mcf, compared with $7.41 per Mcf for the year ended September 30, 2005.

Additionally, during the first quarter of fiscal 2006, the MPSC, in connection with the modification of our rate design described in Recent Ratemaking Activity, decided to allow the recovery of $2.8 million in deferred costs, which it had originally disallowed in its September 2004 decision. This charge was originally recorded in fiscal 2004. This ruling decreased our depreciation expense during the year ended September 30, 2006. This decrease was offset by increased depreciation expense associated with the placement of various capital projects into service during the fiscal year.

Operating expenses were also impacted by $22.9 million noncash charge to impair our West Texas Division’s irrigation assets. During the fiscal 2006 fourth quarter, we determined that, as a result of declining irrigation sales primarily associated with our agricultural customers’ shift from gas-powered pumps to electric pumps, the West Texas Division’s irrigation assets would not be able to generate sufficient future cash flows from operations to recover the net investment in these assets. Therefore, the entire net book value was written off. We will continue to operate these assets until we determine a plan for these assets as we are obligated to provide natural gas services to certain customers served by these assets.

As a result of the aforementioned factors, our utility segment operating income for the year ended September 30, 2006 decreased to $201.9 million from $236.4 million for the year ended September 30, 2005.

Miscellaneous income

Miscellaneous income for the year ended September 30, 2006 was $9.5 million compared to miscellaneous income of $6.8 million for the year ended September 30, 2005. This increase was primarily attributable to increased interest income on intercompany borrowings to our natural gas marketing segment to fund its working capital needs. This increase was partially offset by a $3.3 million charge recorded during the fiscal 2006 second quarter associated with an adverse ruling in Tennessee related to the calculation of a performance-based rate mechanism associated with gas purchases.

Interest charges

Interest charges allocated to the utility segment for the year ended September 30, 2006 increased to $126.5 million from $112.4 million for the year ended September 30, 2005. The increase was attributable to higher average outstanding short-term debt balances to fund natural gas purchases at significantly higher prices coupled with an approximate 200 basis point increase in the interest rate on our $300 million unsecured floating rate Senior Notes due 2007 due to an increase in the three-month LIBOR rate. These increases were partially offset by $4.8 million of interest savings arising from the early payoff of $72.5 million of our First Mortgage Bonds in June 2005.

Natural gas marketing segment

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. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the 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 derivative products. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues for services we deliver.

To optimize the storage and transportation capacity we own or control, we participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Additionally, we engage in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial contracts at favorable prices to lock in gross profit margins. Through the use of transportation and storage services and derivative contracts, we seek to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

Operating income

Gross profit margin for our natural gas marketing segment consists primarily of marketing activities, which represent the utilization of proprietary and customer-owned transportation and storage assets to provide the various services our customers request, and storage activities, which are derived from the optimization of our managed proprietary and third party storage and transportation assets.

Our natural gas marketing segment’s gross profit margin was comprised of the following for the year ended September 30, 2006 and 2005:


	Year Ended September 30
	2006			2005
	(In thousands, except physical position)

Storage Activities
Realized margin	$	26,225		$	28,008
Unrealized margin		(1,293	)		(14,007	)

Total Storage Activities		24,932			14,001
Marketing Activities
Realized margin		87,236			59,971
Unrealized margin		18,459			(11,999	)

Total Marketing Activities		105,695			47,972

Gross profit	$	130,627		$	61,973

Net physical position (Bcf)		14.5			6.9

Our natural gas marketing segment’s gross profit margin was $130.6 million for the year ended September 30, 2006 compared to gross profit of $62.0 million for the year ended September 30, 2005. Gross profit margin from our natural gas marketing segment for the year ended September 30, 2006 included an unrealized gain of $17.2 million compared with an unrealized loss of $26.0 million in the prior year. Natural gas marketing sales volumes were 336.5 Bcf during the year ended September 30, 2006 compared with 273.2 Bcf for the prior year. Excluding intersegment sales volumes, natural gas marketing sales volumes were 284.0 Bcf during the current year compared with 238.1 Bcf in the prior year. The increase in consolidated natural gas marketing sales volumes was primarily due to focusing our marketing efforts on higher margin opportunities partially offset by warmer-than-normal weather across our market areas.

Our storage activities generated $24.9 million in gross profit margin for the year ended September 30, 2006 compared to $14.0 million for the year ended September 30, 2005. Lower realized margins in our storage operations were primarily due to the realization of less favorable arbitrage spreads compared with the prior year coupled with increased storage fees. These decreases were partially offset by a decrease in the unrealized loss associated with these operations due to a favorable movement during the year ended September 30, 2006 in the forward natural gas prices used to value the financial hedges designated against our physical inventory and our fixed-price forward contracts. These decreases were also favorably impacted by positive basis ineffectiveness resulting from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the derivative instruments designated as a fair value hedge. These results were magnified by a 7.6 Bcf increase in our net physical position at September 30, 2006 compared to the prior year. We continually seek opportunities to increase the amount of our storage capacity. To the extent we obtain and utilize new capacity and experience price volatility, the amount of our unrealized storage contribution could increase in future periods.

Our marketing activities generated $105.7 million in gross profit margin for the year ended September 30, 2006 compared with $48.0 million for the year ended September 30, 2005. This increase reflects increased realized margins coupled with a favorable unrealized margin variance compared with the prior year. The increase in our realized marketing operations was primarily attributable to successfully capturing increased margins in certain market areas that experienced higher market volatility. The favorable unrealized margin variance was primarily due to favorable movement during the year ended September 30, 2006 in the forward natural gas prices associated with financial derivatives used in these activities and positive basis ineffectiveness on those financial derivatives.

year ended September 30, 2006 from $21.0 million for the year ended September 30, 2005. The increase in operating expense primarily was attributable to an increase in personnel costs due to increased headcount and an increase in regulatory compliance costs.

The improved gross profit margin partially offset by higher operating expenses resulted in an increase in our natural gas marketing segment operating income to $102.2 million for the year ended September 30, 2006 compared with operating income of $41.0 million for the year ended September 30, 2005.

Interest charges

Interest charges allocated to the natural gas marketing segment for the year ended September 30, 2006 increased to $8.5 million from $3.4 million for the year ended September 30, 2005. The increase was attributable to higher average outstanding debt balances to fund natural gas purchases at significantly higher prices.

Pipeline and storage segment

Our pipeline and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC (APS), which were previously included in our other nonutility segment. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and 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 inventory on hand. These operations represent 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. This pipeline system provides access to nine basins located in Texas, which are estimated to contain a substantial portion of the nation’s remaining onshore natural gas reserves. APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We also use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods.

Similar to our utility segment, our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas transportation requirements are affected by the winter heating season requirements of our customers. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. 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.

Operating income

Gross profit margin for our pipeline and storage segment primarily consists of transportation margins earned from our Mid-Tex Division and from third parties, other ancillary pipeline services and asset management fees earned by APS. Our pipeline and storage segment’s gross profit margin was comprised of the following components for the year ended September 30, 2006 and 2005:


	Year Ended September 30
	2006		2005
	(In thousands)

Mid-Tex transportation	$	69,925	$	70,089
Third party transportation		58,490		55,376
Asset management fees		10,333		8,559
Storage and park and lend services		11,297		7,451
Unrealized gains (losses)		3,350		(4,730	)
Other		6,334		9,733

Gross profit	$	159,729	$	146,478

Pipeline and storage gross profit increased to $159.7 million for the year ended September 30, 2006 from $146.5 million for the year ended September 30, 2005. Total pipeline transportation volumes were 591.0 Bcf during the year ended September 30, 2006 compared with 563.9 Bcf for the prior year. Excluding intersegment transportation volumes, total pipeline transportation volumes were 420.2 Bcf during the current year compared with 383.4 Bcf in the prior year.

The increase in gross profit was primarily attributable to increased third-party throughput and ancillary services, coupled with increased margins on APS’ asset management contracts. Increased third-party throughput on Atmos Pipeline — Texas was primarily attributable to increases in the electric-generation market due to the warmer than normal temperatures during the summer of 2006, increased demand for through-system transportation services due to a widening of pricing differentials between the pipeline’s hubs and the impact of Atmos Pipeline — Texas’ North Side Loop and other compression projects that were placed into service in June 2006. Storage and parking and lending services on Atmos Pipeline — Texas also increased during fiscal 2006 as a result of the widening of pricing differentials between the pipeline’s hubs, which increased the attractiveness of storing gas on the pipeline and our ability to obtain improved margins for these services. The increases on Atmos Pipeline — Texas’ system were partially offset by a decrease in margins earned from intercompany transportation services to our Mid-Tex Division due to the significantly warmer than normal weather experienced during fiscal 2006. Additionally, these increases were partially offset by the absence of inventory sales of $3.0 million realized in the prior year.

Increases in APS’ margins due to its ability to capture more favorable arbitrage spreads on its asset management contracts also contributed to this segment’s improved gross profit margin. These improved margins reflect an unrealized component as APS hedges its risk associated with these contracts. During fiscal 2006, favorable movements in the forward natural gas prices used to value the financial hedges designated against the physical inventory underlying these contracts resulted in an unrealized gain compared with an unrealized loss in the prior year.

Operating expenses increased to $81.9 million for the year ended September 30, 2006 from $76.2 million for the year ended September 30, 2005 due to higher employee benefit costs associated with the increase in headcount, increased pension and postretirement costs resulting from changes in the assumptions used to determine our fiscal 2006 costs, higher facilities costs and higher pipeline integrity costs.

As a result of the aforementioned factors, our pipeline and storage segment operating income for the year ended September 30, 2006 increased to $77.9 million from $70.3 million for the year ended September 30, 2005.

Other nonutility segment

Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC, and Atmos Power Systems, Inc. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services, which began April 2004, include aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our utility service areas at competitive prices. The revenues of AES represent charges to our utility divisions equal to the costs incurred to provide those services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and have entered into agreements to lease these plants.

Operating income for this segment primarily reflects the leasing income associated with two sales-type lease transactions completed in 2001 and 2002 and was essentially unchanged for the year ended September 30, 2006 compared with the prior year.

Year ended September 30, 2005 compared with year ended September 30, 2004

Utility segment

Operating income

Utility gross profit increased to $907.4 million for the year ended September 30, 2005 from $503.1 million for the year ended September 30, 2004. Total throughput for our utility business was 411.1 Bcf during the current year compared to 246.0 Bcf in the prior year.

The increase in utility gross profit margin primarily reflects the impact of the acquisition of the Mid-Tex Division resulting in an increase in utility gross profit margin and total throughput of $398.2 million and 174.3 Bcf. The $6.1 million increase in the gross profit generated from our other utility operations primarily reflects rate increases in our Mississippi and West Texas divisions that were absent in the prior year coupled with the recognition of a $1.9 million refund to our customers in our Colorado service area in the prior year. Offsetting these increases was a $3.9 million reduction in gross profit in our Louisiana Division due to the impact of Hurricane Katrina. Gross profit margins, particularly in Louisiana, were also adversely impacted by weather (as adjusted for jurisdictions with weather-normalized operations) that was five percent warmer than normal and one percent warmer than the prior year period. Additionally, gross profit margin was adversely impacted by the lack of cold weather in patterns sufficient to encourage customers to increase their heat load consumption and lower irrigation throughput in our West Texas and Colorado-Kansas Divisions.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $671.0 million for the year ended September 30, 2005 from $343.2 million for the year ended September 30, 2004 primarily as a result of the addition of the Mid-Tex Division. Excluding the impact of the Mid-Tex Division, operating expenses for our other utility operations increased $14.5 million primarily due to $2.3 million associated with the effects of Hurricane Katrina, a $7.7 million increase in taxes, other than income, a $2.4 million increase in operation and maintenance expense, including the provision for doubtful accounts, and a $2.1 million increase in depreciation and amortization. Included in taxes other than income taxes are franchise and state gross receipts taxes which are paid by our customers as a component of their monthly bills. Although these amounts are offset in revenues through customer billings, timing differences between when the expense is incurred and is recovered may impact our net income on a temporary basis. However, there is no permanent effect on net income.

As a result of the aforementioned factors, our utility segment operating income for the year ended September 30, 2005 increased to $236.4 million from $159.9 million for the year ended September 30, 2004.

Miscellaneous income

Miscellaneous income increased to $6.8 million for the year ended September 30, 2005 from $5.8 million for the year ended September 30, 2004. The increase was attributable to an increase in interest income earned

on higher cash balances during the current year compared with the prior year partially offset by the recognition of a $0.8 million gain on the sale of a building during the year ended September 30, 2004.

Interest charges

Interest charges allocated to the utility segment for the year ended September 30, 2005 increased to $112.4 million from $65.4 million for the year ended September 30, 2004. The increase was attributable to the interest expense associated with the issuance of long-term debt to finance the acquisition of the Mid-Tex Division in October 2004. On June 30, 2005, we repaid $72.5 million in principal on five series of our First Mortgage Bonds prior to their scheduled maturities. The early repayment of these bonds resulted in savings of $1.3 million in interest expense in fiscal 2005.

Natural gas marketing segment

Operating income

Our natural gas marketing segment’s gross profit margin was comprised of the following for the years ended September 30, 2005 and 2004:


	Year Ended September 30
	2005			2004
	(In thousands, except physical position)

Storage Activities
Realized margin	$	28,008		$	(1,900	)
Unrealized margin		(14,007	)		357

Total Storage Activities		14,001			(1,543	)
Marketing Activities
Realized margin		59,971			51,347
Unrealized margin		(11,999	)		(3,173	)

Total Marketing Activities		47,972			48,174

Gross profit	$	61,973		$	46,631

Net physical position (Bcf)		6.9			5.4

Our natural gas marketing segment’s gross profit margin was $62.0 million for the year ended September 30, 2005 compared to gross profit of $46.6 million for the year ended September 30, 2004. Gross profit margin from our natural gas marketing segment for the year ended September 30, 2005 included an unrealized loss of $26.0 million compared with an unrealized loss of $2.8 million in the prior year. Natural gas marketing sales volumes were 273.2 Bcf during the year ended September 30, 2005 compared with 265.1 Bcf for the prior year. Excluding intersegment sales volumes, natural gas marketing sales volumes were 238.1 Bcf during the current year compared with 222.6 Bcf in the prior year. The increase in consolidated natural gas marketing sales volumes primarily was attributable to successfully executed marketing strategies into new market areas.

The contribution to gross profit from our storage activities was a gain of $14.0 million for the year ended September 30, 2005 compared to a loss of $1.5 million for the year ended September 30, 2004. The $15.5 million improvement primarily was attributable to a $29.9 million increase in the realized storage contribution for the year ended September 30, 2005 compared to the prior year due to more favorable arbitrage spread opportunities during the current year, partially offset by increased storage fees associated with 9.0 Bcf of newly contracted storage capacity during the third quarter of fiscal 2005. Annual demand charges for this new storage approximate $7.6 million. We may further increase the amount of our storage capacity in the future; therefore, the impact of price volatility on our unrealized storage contribution could become more significant in future periods.

A $14.4 million decrease in the unrealized storage contribution resulted from an unfavorable movement during the year ended September 30, 2005 in the forward indices used to value the storage financial instruments combined with greater physical natural gas storage quantities at September 30, 2005 compared to the prior year also.

Our marketing activities contributed $48.0 million to our gross profit for the year ended September 30, 2005 compared to $48.2 million for the year ended September 30, 2004. The decrease in the marketing contribution primarily was attributable to $12.0 million of unrealized marked-to-market losses associated with basis swaps that were put in place to capture margins in certain volatile market areas. The increase in unrealized marked-to-market losses was partially offset by an increase in our realized marketing margins due to focusing our marketing efforts on higher margin customers and successfully entering into new market areas.

The increase in gross profit margin, combined with higher operating expenses, resulted in an increase in our natural gas marketing segment operating income to $41.0 million for the year ended September 30, 2005 compared with operating income of $27.7 million for the year ended September 30, 2004.

Pipeline and storage segment

Operating income

Pipeline and storage gross profit increased to $146.5 million for the year ended September 30, 2005 from $10.4 million for the year ended September 30, 2004. Total pipeline transportation volumes were 563.9 Bcf during the year ended September 30, 2005 compared with 9.4 Bcf for the prior year. Excluding intersegment transportation volumes, total pipeline transportation volumes were 383.4 Bcf during the current year.

The increase in pipeline and storage gross profit margin primarily reflects the impact of the acquisition of the Atmos Pipeline — Texas Division resulting in an increase in pipeline and storage gross profit margin and total transportation volumes of $138.1 million and 375.6 Bcf. Also contributing to Atmos Pipeline — Texas Division’s results were higher transportation and related services margin due to significant basis differentials at its three major Texas hubs. The $2.0 million decrease in the gross profit generated by APS primarily reflects a decrease in asset management fees received during fiscal 2005.

Operating expenses increased to $76.2 million for the year ended September 30, 2005 from $5.1 million for the year ended September 30, 2004 due to the addition of $72.2 million in operating expenses associated with the Atmos Pipeline — Texas Division. As the Atmos Pipeline — Texas Division is a regulated entity, franchise and state gross receipts taxes are paid by our customers; thus, these amounts are offset in revenues through customer billings and have no permanent effect on net income. Included in operating expense was $8.9 million associated with taxes other than income taxes, of which $8.3 million was associated with our Atmos Pipeline — Texas Division.

As a result of the aforementioned factors, our pipeline and storage segment operating income for the year ended September 30, 2005 increased to $70.3 million from $5.3 million for the year ended September 30, 2004.

Interest charges

Interest charges allocated to this segment for the year ended September 30, 2005 increased to $24.6 million from $1.1 million for the year ended September 30, 2004. The increase was attributable to the interest expense associated with the issuance of long-term debt to finance the acquisition of the Atmos Pipeline — Texas Division in October 2004.

Other nonutility segment

Operating income for our other nonutility segment primarily reflects the leasing income associated with two sales-type lease transactions completed in fiscal 2001 and 2002. The increase in operating income during the year ended September 30, 2005 reflects the absence of a one-time charge of $0.4 million associated with the wind-down of a noncore business during fiscal 2004.

Miscellaneous income for the year ended September 30, 2005 was $2.6 million compared with $8.3 million for the year ended September 30, 2004. The $5.7 million decrease was attributable primarily to the recognition of a $5.9 million pretax gain on the sale of all remaining limited partnership interests in Heritage Propane Partners, L.P. during fiscal 2004.

LIQUIDITY AND CAPITAL RESOURCES

Our working capital and liquidity for capital expenditure and other cash needs are provided from internally generated funds, borrowings under our credit facilities and commercial paper program and funds raised from the public debt and equity capital markets. We believe that these sources of funds will provide the necessary working capital and liquidity for capital expenditures and other cash needs for fiscal 2007. These facilities are described in greater detail below and in Note 6 to the consolidated financial statements.

Capitalization

The following presents our capitalization as of September 30, 2006 and 2005:


	September 30
	2006				2005
	(In thousands, except percentages)

Short-term debt	$	382,416	9.1	%	$	144,809	3.7	%
Long-term debt		2,183,548	51.8	%		2,186,368	55.6	%
Shareholders’ equity		1,648,098	39.1	%		1,602,422	40.7	%

Total capitalization, including short-term debt	$	4,214,062	100.0	%	$	3,933,599	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 60.9 percent and 59.3 percent at September 30, 2006 and 2005. The increase in the debt to capitalization ratio was primarily attributable to an increase in our short-term debt borrowings to fund our working capital needs partially offset by current-year net income. 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. Within three to five years, we intend to reduce our capitalization ratio to a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.

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 services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating activities

Year-over-year changes in our operating cash flows are primarily attributable to working capital changes within our utility segment resulting from the impact of weather, the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the year ended September 30, 2006, we generated operating cash flow of $311.4 million compared with $386.9 million in fiscal 2005 and $270.7 million in fiscal 2004. The significant factors impacting our operating cash flow for the last three fiscal years are summarized below.

Year ended September 30, 2006

Fiscal 2006 operating cash flows reflect the adverse impact of significantly higher natural gas prices. Year-over-year, unfavorable timing of payments for accounts payable and other accrued liabilities reduced operating cash flow by $523.0 million. Partially offsetting these outflows were higher customer collections ($245.1 million) and reduced payments for natural gas inventories ($102.1 million). Additionally, favorable movements in the market indices used to value our natural gas marketing segment risk management assets and liabilities reduced the amount that we were required to deposit in a margin account and therefore favorably affected operating cash flow by $126.3 million.

Year ended September 30, 2005

Fiscal 2005 operating cash flows reflect the effects of a $49.6 million increase in net income and effective working capital management partially offset by higher natural gas prices. Working capital management efforts, which affected the timing of payments for accounts payable and other accrued liabilities, favorably affected operating cash flow by $354.1 million. However, these efforts were partially offset by reduced cash flow generated from accounts receivable changes by $168.9 million, primarily attributable to higher natural gas prices, and an increase in our natural gas inventories attributable to a 13 percent year-over-year increase in natural gas prices coupled with increased natural gas inventory levels, which reduced operating cash flow by $81.8 million. Operating cash flow was also adversely impacted by unfavorable movements in the indices used to value our natural gas marketing segment risk management assets and liabilities, which resulted in a net liability for the segment. Accordingly, under the terms of the associated derivative contracts, we were required to deposit $81.0 million into a margin account.

Year ended September 30, 2004

Fiscal 2004 operating cash flows were favorably impacted by several items. Improved customer collections during fiscal 2004, compared with the prior year, resulted in a $62.2 million increase in operating cash flow. Further, cash used for natural gas inventories decreased by $33.8 million compared with the prior year. The decrease was attributable to lower injections of natural gas into storage, partially offset by higher prices. The reduction in the lag between the time period when we purchase our natural gas and the period in which we can include this cost in our gas rates improved operating cash flow by $65.7 million. Changes in cash held on deposit in margin accounts resulted in an increase in operating cash flow of $25.6 million. This account represents deposits recorded to collateralize certain of our financial derivatives purchased in support of our natural gas marketing activities. The favorable change was attributable to the fact that the fair value of financial instruments held by AEM represented a net asset position at September 30, 2004, which eliminated the need to place cash in margin accounts. Finally, other working capital and other changes improved operating cash flow by $33.9 million. These changes primarily related to various increases in deferred credits and other liabilities, other current liabilities and income taxes payable partially offset by lower deferred income tax expense as compared with the prior year.

Cash flows from investing activities

During the last three years, a substantial portion of our cash resources was used to fund acquisitions and growth projects, our ongoing construction program and improvements to information systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, to expand our natural gas distribution services into new markets, to enhance the integrity of our pipelines and, more recently, to expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a return on our investment timely. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas utility 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.

For the year ended September 30, 2006, we incurred $425.3 million for capital expenditures compared with $333.2 million for the year ended September 30, 2005 and $190.3 million for the year ended

September 30, 2004. The increase in capital expenditures in fiscal 2006 primarily reflects increased spending associated with our Dallas/Fort Worth Metroplex North Side Loop project and other pipeline expansion projects in our Atmos Pipeline — Texas Division, which were completed during the fiscal 2006 third quarter. Increased capital spending in our Mid-Tex Division for various projects also contributed to the increase in our capital expenditures.

Our cash used for investing activities for the year ended September 30, 2005 reflects the $1.9 billion cash paid for the TXU Gas acquisition including related transaction costs and expenses. Cash flow from investing activities for the year ended September 30, 2004 reflects the receipt of $27.9 million from the sale of our limited and general partnership interests in USP and Heritage Propane Partners, L.P. and from the sale of a building.

Cash flows from financing activities

For the year ended September 30, 2006, our financing activities provided $155.3 million in cash compared with $1.7 billion and $80.4 million provided for the years ended September 30, 2005 and 2004. Our significant financing activities for the years ended September 30, 2006, 2005 and 2004 are summarized as follows:


	•	In October 2004, we sold 16.1 million shares of common stock, including the underwriters’ exercise of their overallotment option of 2.1 million shares, under a shelf registration statement declared effective in September 2004, generating net proceeds of $382 million. Additionally, we issued $1.39 billion of senior unsecured debt under our shelf registration statement with an initial weighted average effective interest rate on these notes of 4.76 percent. The net proceeds from these issuances, combined with the net proceeds from our July 2004 common stock offering were used to finance the acquisition of our Mid-Tex and Atmos Pipeline — Texas divisions and settle Treasury lock agreements, into which we entered to fix the Treasury yield component of the interest cost of financing associated with $875 million of the $1.39 billion long-term debt we issued in October 2004 to fund the acquisition.

	•	During the years ended September 30, 2006 and 2005, we increased our borrowings under our short-term facilities by $237.6 million and $144.8 million whereas during the year ended September 30, 2004, we repaid a net $118.6 million under our short-term facilities. Net borrowings under our short-term facilities during fiscal 2006 and 2005 reflect the impact of seasonal natural gas purchases and the effect of higher natural gas prices than in prior years.

	•	We repaid $3.3 million of long-term debt during the year ended September 30, 2006 compared with $103.4 million during the year ended September 30, 2005 and $9.7 million during the year ended September 30, 2004. Fiscal 2005 payments reflected the repayment of $72.5 million of our First Mortgage Bonds. In connection with this repayment we paid a $25.0 million make-whole premium in accordance with the terms of the agreements and accrued interest of approximately $1.0 million. In accordance with regulatory requirements, the premium has been deferred and will be recognized over the remaining original lives of the First Mortgage Bonds that were repaid. The early repayment of these bonds resulted in interest savings of $4.8 million and $1.3 million in fiscal 2006 and 2005.

	•	During the year ended September 30, 2006, we paid $102.3 million in cash dividends compared with dividend payments of $99.0 million and $66.7 million for the years ended September 30, 2005 and 2004. The increase in dividends paid over the prior year reflects an increase in the dividend rate from $1.24 per share during the year ended September 30, 2005 to $1.26 per share during the year ended September 30, 2006 combined with new share issuances under our various plans.

During the year ended September 30, 2006 we issued 0.9 million shares of common stock which generated net proceeds of $23.3 million. In addition, we granted 0.3 million shares of common stock under

our 1998 Long-Term Incentive Plan to directors, officers and other participants in the plan. The following table shows the number of shares issued for the years ended September 30, 2006, 2005 and 2004:


	For the Year Ended September 30
	2006		2005		2004

Shares issued:
Direct stock purchase plan		387,833		450,212		556,856
Retirement savings plan		442,635		441,350		320,313
1998 Long-term incentive plan		366,905		745,788		498,230
Long-term stock plan for Mid-States Division		300		—		6,000
Outside directors stock-for-fee plan		2,442		2,341		3,133
October 2004 Offering		—		16,100,000		—
July 2004 Offering		—		—		9,939,393

Total shares issued		1,200,115		17,739,691		11,323,925

Shelf Registration

In December 2001, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $600.0 million in new common stock and/or debt. The registration statement was declared effective by the SEC in January 2002. In July 2004, we sold 9.9 million shares of our common stock, including the underwriters’ exercise of their overallotment option, which exhausted the remaining availability under this registration statement.

In August 2004, we filed a registration statement with the SEC to issue, from time to time, up to $2.2 billion in new common stock and/or debt, which became effective in September 2004. In October 2004, we sold 16.1 million common shares, including the underwriters’ exercise of their overallotment option of 2.1 million shares, under this registration statement, generating net proceeds of $382.5 million before other offering costs. Additionally, we issued $1.39 billion of senior unsecured debt under the registration statement. After issuing the debt and equity in October 2004, we had approximately $401.5 million of availability remaining under this registration statement. However, we are no longer allowed to issue securities under that registration statement by applicable state regulatory commissions since we are in the process of securing their approval to issue a total of $900 million in securities under a new shelf registration statement, including the remaining $401.5 million of capacity carried over from the currently effective registration statement. We intend to file this new registration statement with the SEC in the near future.

Credit Facilities

As of September 30, 2006, we maintained three short-term committed credit facilities totaling $918 million. We also maintain one uncommitted credit facility totaling $25 million and, through AEM, a second uncommitted credit facility that can provide up to $580 million. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the banks. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder winter months. Our working capital needs can vary significantly due to changes in the price of natural gas charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather. Our cash needs for working capital have increased substantially as a result of the significant increase in the price of natural gas.

In October 2005, our $600 million 364-day committed credit facility expired and was replaced with a $600 million three-year revolving credit facility. In addition, in November 2005, we entered into a new $300 million 364-day revolving credit facility with substantially the same terms as our $600 million credit facility.

In November 2006, we renewed our $300 million 364-day revolving credit facility and were in the process of replacing our three-year $600 million facility with a five-year $600 million revolving credit facility. Both facilities are being renewed with substantially the same terms as their predecessor facilities.

In April 2006, our $18 million committed unsecured credit facility was renewed for one year with no material changes to its terms and pricing. At September 30, 2006, $3.1 million was outstanding under this facility.

As of September 30, 2006, the amount available to us under these credit facilities, net of outstanding letters of credit, was $609.0 million. We believe these credit facilities, combined with our operating cash flows will be sufficient to fund our increased working capital needs. These facilities are described in further detail in Note 6 to the consolidated financial statements.

In November 2005, AEM amended its uncommitted demand working capital credit facility to increase the amount of credit available from $250 million to a maximum of $580 million. In March 2006, AEM amended and extended this uncommitted demand working capital credit facility to March 2007. At September 30, 2006, there were no borrowings outstanding under this facility.

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 utility and nonutility 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 Services, Inc. (Moody’s) and Fitch Ratings, Ltd. (Fitch). Our current debt ratings are all considered investment grade and are as follows:


	S&P	Moody’s	Fitch

Long-term debt	BBB	Baa3	BBB+
Commercial paper	A-2	P-3	F-2

Currently, with respect to our unsecured senior long-term debt, S&P, Moody’s and Fitch maintain their stable outlook. None of our ratings is currently under review.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB−, Moody’s is Baa3 and Fitch is BBB−. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent 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, 2006. If we do not comply with our debt covenants, we may be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our two public debt indentures relating to our senior notes and debentures, as well as both our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. In addition, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate. Additionally, this agreement

contains a provision that would limit the amount of credit available if Atmos were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.

Except as described above, we have no triggering events in our debt instruments that are tied to changes in specified credit ratings or stock price, nor have we entered into any transactions that would require us to issue equity based on our credit rating or other triggering events.

Additional information concerning our debt covenants and how we complied with those covenants is included in Note 6 to the consolidated financial statements.

Contractual Obligations and Commercial Commitments

The following tables provide information about contractual obligations and commercial commitments at September 30, 2006.


	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⁾	$	2,186,878	$	3,186	$	305,865	$	762,762	$	1,115,065
Short-term debt⁽¹⁾		382,416		382,416		—		—		—
Interest charges⁽²⁾		1,028,096		121,511		207,939		164,964		533,682
Gas purchase commitments⁽³⁾		708,217		560,461		110,793		17,035		19,928
Capital lease obligations⁽⁴⁾		2,777		433		673		477		1,194
Operating leases⁽⁴⁾		176,806		15,959		30,157		26,912		103,778
Demand fees for contracted storage⁽⁵⁾		17,989		8,832		7,257		1,900		—
Demand fees for contracted transportation⁽⁶⁾		27,818		4,269		5,944		5,788		11,817
Derivative obligations⁽⁷⁾		30,945		30,669		276		—		—
Postretirement benefit plan contributions⁽⁸⁾		145,198		11,408		21,584		26,141		86,065

Total contractual obligations	$	4,707,140	$	1,139,144	$	690,488	$	1,005,979	$	1,871,529


⁽¹⁾		See Note 6 to the consolidated financial statements.

⁽²⁾		Interest charges were calculated using the stated rate for each debt issuance, or in the case of floating rate debt, the rate that was in effect as of September 30, 2006.

⁽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, 2006.

⁽⁴⁾		See Note 14 to the consolidated financial statements.

⁽⁵⁾		Represents third party contractual demand fees for contracted storage in our natural gas marketing and other utility segments. Contractual demand fees for contracted storage for our utility 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 derivative contracts that were valued as of September 30, 2006. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the derivative contracts are settled.

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

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, 2006, AEM was committed to purchase 61.7 Bcf within one year, 51.2 Bcf between one to three years and 0.8 Bcf after three years under indexed

contracts. AEM was committed to purchase 2.4 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $3.40 to $12.00 per Mcf.

With the exception of our Mid-Tex Division, our utility 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, 2006 are reflected in the table above.

In May 2006, we announced plans to form a joint venture with a local natural gas producer to construct a natural gas gathering system in Eastern Kentucky that will originate in Floyd County, Kentucky, and extend north approximately 60 miles to interconnect with the Tennessee Gas Pipeline in Carter County, Kentucky. Tennessee Gas Pipeline’s interstate system delivers natural gas to the northeastern United States, including New York City and Boston. Referred to as the Straight Creek Project, the new system is expected to relieve severe gas gathering and transportation constraints that historically have burdened natural gas producers in the area and should improve delivery reliability to natural gas customers. More than a dozen other producers have signed memoranda of understanding to commit gas volumes to the new system and to enter into agreements on commercially reasonable terms.

As currently designed, the project is expected to cost between $75 million to $80 million. In October 2006, FERC issued a declaratory order finding that the Straight Creek Project will be exempt from FERC jurisdiction. Upon receiving all required regulatory approvals, construction is expected to begin in the first half of fiscal 2007, with operations expected to begin in fiscal 2008. Final terms of the joint venture are still being negotiated; however, we anticipate that we will have the ability to consolidate the joint venture.

Risk Management Activities

We conduct risk management activities through our utility, natural gas marketing and pipeline and storage segments. In our utility segment, we use a combination of 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 and storage 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 derivatives, 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 derivatives being treated as mark to market instruments through earnings.

In our natural gas marketing segment, hedge ineffectiveness resulting from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments (referred to as basis ineffectiveness) for both fair value and cash flow hedges was an unrealized gain of approximately $35.5 million for the year ended September 30, 2006 and an unrealized loss of approximately $5.4 million and $1.1 million for the years ended September 30, 2005 and 2004. Actual hedge ineffectiveness resulting from the timing of settlement of physical contracts and the settlement of the derivative instruments (referred to as timing ineffectiveness) resulted in an unrealized gain of approximately $4.4 million and $0.5 million for the years ended September 30, 2006 and 2004 and an unrealized loss of approximately $2.2 million for the year ended September 30, 2005.

In our pipeline and storage segment, timing ineffectiveness resulted in an unrealized loss of approximately $4.7 million and less than $0.1 million for the years ended September 30, 2006 and 2004 and an unrealized gain of approximately $5.2 million for the year ended September 30, 2005.

Finally, during fiscal 2004, we entered into four Treasury lock agreements to fix the Treasury yield component of the interest cost of financing associated with the anticipated issuance of $875 million of long-

term debt. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. Approximately $11.6 million of the $43.8 million obligation is being recognized as a component of interest expense over a five year period from the date of settlement, and the remaining amount, approximately $32.2 million, is being recognized as a component of interest expense over a ten year period from the date of settlement. Our risk management activities and related accounting treatment are described in further detail in Note 5 to the consolidated financial statements.

We record our derivatives 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 derivative. Substantially all of our derivative financial instruments are valued using external market quotes and indices. The following table shows the components of the change in fair value of our utility and natural gas marketing derivative contract activities for the year ended September 30, 2006 (in thousands):


				Natural Gas
	Utility			Marketing

Fair value of contracts at September 30, 2005	$	93,310		$	(61,898	)
Contracts realized/settled		25,461			11,106
Fair value of new contracts		(18,651	)		—
Other changes in value		(127,329	)		65,795

Fair value of contracts at September 30, 2006	$	(27,209	)	$	15,003

The fair value of our utility and natural gas marketing derivative contracts at September 30, 2006, is segregated below by time period and fair value source.


	Fair Value of Contracts at September 30, 2006
	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	$	(17,421	)	$	7,122		$	—	$	—	$	(10,299	)
Prices provided by other external sources		(440	)		(936	)		—		—		(1,376	)
Prices based on models and other valuation methods		(255	)		(276	)		—		—		(531	)

Total Fair Value	$	(18,116	)	$	5,910		$	—	$	—	$	(12,206	)

Storage and Hedging Outlook

AEM participates in transactions in which it seeks to find and profit from pricing differences that occur over time. AEM purchases physical natural gas and then sells financial contracts at favorable prices to lock in a gross profit margin. AEM is able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

Natural gas inventory is marked to market at the end of each month with changes in fair value recognized as unrealized gains and losses in the period of change. Effective October 1, 2005, we changed the index used to value our physical natural gas from Inside FERC to Gas Daily to better reflect the prices of our physical commodity. This change had no material impact to the Company on the date of adoption. Derivatives associated with our natural gas inventory, which are designated as fair value hedges, 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 changes in the difference between the indices used to mark to market our physical inventory (Gas Daily) and the related fair-value hedge (NYMEX) are reported as a component of revenue and can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges; therefore, the economic gross profit AEM captured in the original transaction remains essentially unchanged.

AEM continually manages its positions to enhance the future economic profit it captured in the original transaction. Therefore, AEM may change its scheduled injection and withdrawal plans from one time period to another based on market conditions or adjust the amount of storage capacity it holds on a discretionary basis in an effort to achieve this objective. AEM monitors the impacts of these profit optimization efforts by estimating the gross profit that it captured and expects to collect through the purchase and sale of physical natural gas and the associated financial derivatives, which we refer to as the economic gross profit. The economic gross profit, combined with the effect of unrealized gains or losses recognized in the financial statements in prior periods, provides a measure of the gross profit that could occur in future periods if AEM’s optimization efforts are fully successful. The following table presents AEM’s economic gross profit and its potential gross profit for the last three fiscal years.


					Associated Net
			Economic		Unrealized			Potential
	Net Physical		Gross Profit		(Loss)			Gross Profit
Period Ending	Position (Bcf)		(In millions)		(In millions)			(In millions)

September 30, 2006		14.5	$	60.0	$	(16.0	)	$	76.0
September 30, 2005		6.9	$	13.1	$	(14.8	)	$	27.9
September 30, 2004		5.4	$	12.3	$	(0.8	)	$	13.1

As of September 30, 2006, based upon AEM’s derivatives position and inventory withdrawal schedule, the economic gross profit was $60.0 million. In addition, $16.0 million of net unrealized losses were recorded in the financial statements as of September 30, 2006. Therefore, the potential gross profit was $76.0 million. This potential gross profit amount will not result in an equal increase in future net income as AEM will incur additional storage and other operational expenses to realize this amount.

The economic gross profit is based upon planned injection and withdrawal schedules, and the realization of the economic gross profit is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to enhance the future profitability of its storage position, it may change its scheduled injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot assure that the economic gross profit or the potential gross profit calculated as of September 30, 2006 will be fully realized in the future or in what time period. 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.

Pension and Postretirement Benefits Obligations

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2006, our total net periodic pension and other benefits costs was $50.0 million, compared with $36.4 million and $26.1 million for the years ended September 30, 2005 and 2004. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense.

The increase in total net periodic pension and other benefits cost during fiscal 2006 compared with the prior year primarily reflects changes in assumptions we made during our annual pension plan valuation completed June 30, 2005. The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. In the period leading up to our June 30, 2005 measurement date, these interest rates were declining, which resulted in a 125 basis point reduction in our discount rate to 5.0 percent. This reduction increased the present value of our plan liabilities and associated expenses. Additionally, we reduced the expected return on our pension plan assets by 25 basis points to 8.5 percent, which also increased our pension and postretirement benefit cost.

The increase in total net periodic pension and other benefits cost during fiscal 2005 compared with fiscal 2004 primarily reflects an increase in our service cost associated with the increase in the number of employees

covered by our plans due to the TXU Gas acquisition. Although we did not assume the existing employee benefit liabilities or plans of TXU Gas, for purposes of determining our annual pension cost we agreed to give the transitioned employees credit for years of TXU Gas service under our pension plan. With respect to our postretirement medical plan, we received a credit of $18.9 million against the purchase price to permit us to provide partial past service credits for retiree medical benefits under our retiree medical plan. The $18.9 million credit approximated the actuarially determined present value of the accumulated benefits related to the past service of the transferred employees on the acquisition date.

In addition to the increased number of employees covered by the plans, we changed the assumptions used to determine our fiscal 2005 benefit costs, which resulted in an increase in our net periodic pension and postretirement costs. We increased the discount rate by 25 basis points and we reduced our expected return on our pension plan assets by 25 basis points. These assumption changes decreased the service cost and interest cost and reduced the expected return components of our pension and postretirement benefits costs.

Pension and Postretirement Plan Funding

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

During fiscal 2006, we voluntarily contributed $2.9 million to the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. The current year contribution achieved a desired level of funding by satisfying the minimum funding requirements while maximizing the tax deductible contribution for this plan for plan year 2005. During fiscal 2005, we voluntarily contributed $3.0 million to the Master Trust to maintain the level of funding we desire relative to our accumulated benefit obligation. We made the contribution because declining high yield corporate bond yields in the period leading up to our June 30, 2005 measurement date resulted in an increase in the present value of our plan liabilities.

We contributed $10.9 million, $10.0 million and $13.8 million to our postretirement benefits plans for the years ended September 30, 2006, 2005 and 2004. The contributions represent the portion of the postretirement costs we are responsible for under the terms of our plan and minimum funding required by our regulators.

Outlook for Fiscal 2007

High grade corporate bond yields increased in the period leading up to our June 30, 2006 measurement date. Therefore, we increased the discount rate for determining our fiscal 2007 pension and benefit costs by 130 basis points to 6.3 percent. However, we reduced the expected return on our pension plan assets by 25 basis points to 8.25 percent. The effect of these assumption changes, coupled with the effects of updating our annual valuation should not significantly affect our fiscal 2007 net pension and postretirement costs compared to fiscal 2006.

We are not required to make a minimum funding contribution to our pension plans during fiscal 2007; nor, at this time, do we intend to make voluntary contributions during 2007. However, we anticipate contributing approximately $11 million to our postretirement medical plans during fiscal 2007.

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

RECENT ACCOUNTING DEVELOPMENTS

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the consolidated financial statements.


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

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

We conduct risk management activities through both our utility and natural gas marketing segments. In our utility segment, we use a combination of storage, fixed physical contracts and fixed financial contracts to protect us and our customers against unusually large winter period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial derivatives including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Our risk management activities and related accounting treatment are described in further detail in Note 5 to the condensed consolidated financial statements. Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper, the issuance of floating rate debt in October 2004 and our other short-term borrowings.

Commodity Price Risk

Utility segment

We purchase natural gas for our utility operations. Substantially all of the cost of gas purchased for utility operations is recovered from our customers through purchased gas adjustment mechanisms. However, our utility operations have commodity price risk exposure to fluctuations in spot natural gas prices related to purchases for sales to our non-regulated energy services customers at fixed prices.

For our utility segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on these projected non-regulated gas sales, a hypothetical 10 percent increase in fixed prices based upon the September 30, 2006 three month market strip, would increase our purchased gas cost by approximately $2.3 million in fiscal 2007.

Natural gas marketing and pipeline and storage segments

Our natural gas marketing segment is also exposed to risks associated with changes in the market price of natural gas. For our natural gas marketing segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to our net open position (including existing storage and related financial contracts) at the end of each period. Based on AEH’s net open position (including existing storage and related financial contracts) at September 30, 2006 of 0.2 Bcf, a $0.50 change in the forward NYMEX price would have had less than a $0.1 million impact on our consolidated net income.

Changes in the difference between the indices used to mark to market our physical inventory (Gas Daily) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income; but, over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges. Based upon our net physical position at September 30, 2006 and assuming our hedges would still qualify as highly effective, a $0.50 change in the difference between the Gas Daily and NYMEX indices would impact our reported net income by approximately $5.0 million.

Additionally, these changes could cause us to recognize a risk management liability, which would require us to place cash into an escrow account to collateralize this liability position. This, in turn, would reduce the amount of cash we would have on hand to fund our working capital needs. Because we recognized risk management liabilities as of September 30, 2006, we placed $35.6 million in escrow to collateralize these liabilities.

Interest Rate Risk

Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings increased by an average of one percent, our interest expense would have increased by approximately $3.6 million during 2006.

We also assess market risk for our fixed and floating rate long-term obligations. We estimate market risk for our long-term obligations as the potential increase in fair value resulting from a hypothetical one percent decrease in interest rates associated with these debt instruments. Fair value is estimated using a discounted cash flow analysis. Assuming this one percent hypothetical decrease, the fair value of our long-term obligations would have increased by approximately $143.3 million.

As of September 30, 2006, we were not engaged in other activities that would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates or market commodity prices.


ITEM 8.	*Financial Statements and Supplementary Data*

Index to financial statements and financial statement schedule:


	Page

Report of independent registered public accounting firm on consolidated financial statements		65
Financial statements and supplementary data:
Consolidated balance sheets at September 30, 2006 and 2005		66
Consolidated statements of income for the years ended September 30, 2006, 2005 and 2004		67
Consolidated statements of shareholders’ equity for the years ended September 30, 2006, 2005 and 2004		68
Consolidated statements of cash flows for the years ended September 30, 2006, 2005 and 2004		69
Notes to consolidated financial statements		70
Selected Quarterly Financial Data (Unaudited)		123
Financial statement schedule for the years ended September 30, 2006, 2005 and 2004
Schedule II. Valuation and Qualifying Accounts		131

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
CONSOLIDATED FINANCIAL STATEMENTS

The Board of Directors

Atmos Energy Corporation

We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation as of September 30, 2006 and 2005, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2006. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Atmos Energy Corporation at September 30, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the financial statements taken as a whole, presents fairly, in all material respects, the financial information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 20, 2006 expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Dallas, Texas

November 20, 2006

ATMOS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	September 30
	2006			2005
	(In thousands,
	except share data)

ASSETS
Property, plant and equipment	$	5,026,478		$	4,631,684
Construction in progress		74,830			133,926

		5,101,308			4,765,610
Less accumulated depreciation and amortization		1,472,152			1,391,243

Net property, plant and equipment		3,629,156			3,374,367
Current assets
Cash and cash equivalents		75,815			40,116
Cash held on deposit in margin account		35,647			80,956
Accounts receivable, less allowance for doubtful accounts of $13,686 in 2006 and $15,613 in 2005		374,629			454,313
Gas stored underground		461,502			450,807
Other current assets		169,952			238,238

Total current assets		1,117,545			1,264,430
Goodwill and intangible assets		738,521			737,787
Deferred charges and other assets		234,325			276,943

	$	5,719,547		$	5,653,527


CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding:
2006 — 81,739,516 shares, 2005 — 80,539,401 shares	$	409		$	403
Additional paid-in capital		1,467,240			1,426,523
Accumulated other comprehensive loss		(43,850	)		(3,341	)
Retained earnings		224,299			178,837

Shareholders’ equity		1,648,098			1,602,422
Long-term debt		2,180,362			2,183,104

Total capitalization		3,828,460			3,785,526
Commitments and contingencies
Current liabilities
Accounts payable and accrued liabilities		345,108			461,314
Other current liabilities		388,451			503,368
Short-term debt		382,416			144,809
Current maturities of long-term debt		3,186			3,264

Total current liabilities		1,119,161			1,112,755
Deferred income taxes		306,172			292,207
Regulatory cost of removal obligation		261,376			263,424
Deferred credits and other liabilities		204,378			199,615

	$	5,719,547		$	5,653,527

See accompanying notes to consolidated financial statements

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

Year Ended September 30

2006

2005

2004

(In thousands, except per share data)

Operating revenues

Utility segment

3,650,591