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10-K 1 d30531e10vk.htm FORM 10-K e10vk

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, 2005

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:


Title of Each Class		Name of Each Exchange 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 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. o

Indicate by check whether the recipient is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o

Indicate by check whether the recipient is a shell company (as defined in Exchange Act Rule 12b-2). 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, 2005, was $2,085,825,303.

As of November 11, 2005, the registrant had 80,613,517 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 8, 2006 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 2.	Properties		22
Item 3.	Legal Proceedings		25
Item 4.	Submission of Matters to a Vote of Security Holders		25
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		27
Item 6.	Selected Financial Data		28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk		59
Item 8.	Financial Statements and Supplementary Data		61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		122
Item 9A.	Controls and Procedures		122
Item 9B.	Other Information		124
PART III
Item 10.	Directors and Executive Officers of the Registrant		124
Item 11.	Executive Compensation		124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		124
Item 13.	Certain Relationships and Related Transactions		124
Item 14.	Principal Accountant Fees and Services		125
PART IV
Item 15.	Exhibits and Financial Statement Schedules		125
Form of Non-Qualified Stock Option Agreement
Form of Award Agreement
Form of Award Agreement
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

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
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		The 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
S&P		Standard & Poor’s
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		The 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, (AEC), 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, 2005 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.

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 grown through several acquisitions, including our acquisition in April 2001 of the remaining 55 percent interest in Woodward Marketing, L.L.C. that we did not already own, our acquisition in July 2001 of the assets of Louisiana Gas Service Company, our acquisition in December 2002 of Mississippi Valley Gas Company (MVG) and our acquisition on October 1, 2004 of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas).

The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas.

The purchase price for the TXU Gas acquisition was approximately $1.9 billion (after closing adjustments and before transaction costs and expenses), which we paid in cash. We acquired approximately $112 million of working capital and did not assume any indebtedness of TXU Gas in connection with the acquisition. TXU Gas retained certain assets, provided for the repayment of all of its indebtedness and redeemed all of its preferred stock prior to closing and retained and agreed to pay certain other liabilities under the terms of the acquisition agreement.

We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of approximately 9.9 million shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. In October 2004, we repaid the commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004 which generated net proceeds of approximately $1.39 billion and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of approximately $382.5 million before other offering costs.

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, leveraging our technology, such as our 24-hour call centers, to achieve more efficient operations, focusing on regulatory rate proceedings to increase revenue as our costs increase and mitigating weather-related risks through weather-normalized rates in many of our service areas. Additionally, we have strengthened our nonutility business by increasing gross profit margins, actively pursuing opportunities to increase the amount of storage available to us and expanding commercial opportunities on our intrastate Texas pipeline.

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 operate our utility segment through the following seven regulated natural gas utility divisions:


	•	Atmos Energy Colorado-Kansas Division,

	•	Atmos Energy Kentucky Division,

	•	Atmos Energy Louisiana Division,

	•	Atmos Energy Mid-States Division,

	•	Atmos Energy Mid-Tex Division (acquired October 2004),

	•	Atmos Energy Mississippi Division (formerly known as the Mississippi Valley Gas Company Division) and

	•	Atmos Energy West Texas Division.

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. The seasonal nature of our sales to residential and commercial customers is partially offset by our sales in the spring and summer months to our agricultural customers in Texas, Colorado and Kansas who use natural gas to operate irrigation equipment.

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 partially offset through weather normalization adjustments, or WNA, as approved by the regulators in certain of 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. As of September 30, 2005 we had WNA in the following service areas for the following periods, which covered approximately 1.0 million of our meters in service:


Tennessee		November — April
Georgia		October — May
Mississippi⁽¹⁾		November — May
Kentucky		November — April
Kansas		October — May
Amarillo, Texas		October — May
West Texas		October — May
Lubbock, Texas		October — May
Virginia⁽²⁾		January — December


⁽¹⁾	Beginning in October 2005, the WNA period for Mississippi will be November — April.

⁽²⁾	Effective beginning in July 2005.

Our Mid-Tex Division does not have WNA. However, their operations benefit from a rate structure that combines 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 provides for the recovery of most of our fixed costs for such operations under most weather conditions. However, this rate structure is not as beneficial during periods where weather is significantly warmer than normal.

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 2005 was on December 23, 2004, when sales to customers reached approximately 3.5 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 2005 were Anadarko Energy Services, BP Energy Company, Chevron Corporation, ConocoPhillips Company, Cross Timbers Energy Services, Inc., Devon Gas Services, L.P., Enbridge Marketing (US) L.P., Oneok Energy Services Company, L.P., Tenaska Marketing and Atmos Energy Marketing, LLC, our natural gas marketing subsidiary.

The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into 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, 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, which was formed from the natural gas transmission and storage operations that we acquired in the TXU Gas acquisition.

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, 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. We will operate under a performance-based rate program through March 2006. Under the performance-based program, 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.

Atmos Energy Louisiana Division. Our Louisiana Division operates in Louisiana and includes the operations of the Louisiana Gas Service Company assets acquired in July 2001, which serves the metropolitan area of Monroe and the suburban areas of New Orleans, and our previously existing Trans La Division, which serves western Louisiana. Our Louisiana Division is regulated by the Louisiana Public Service Commission (LPSC), 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. 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. Beginning in July 2005, we have WNA in Virginia that will cover 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.

Atmos Energy Mid-Tex Division. Our Mid-Tex Division, which represents the distribution assets and operations that we acquired from TXU Gas on October 1, 2004, includes 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 to approximately 1.5 million residential and business customers in approximately 550 cities and towns, including the 11-county Dallas/ Fort Worth metropolitan area. Under a May 2004 rate filing, this division operates under a system-wide rate structure along with the pipeline operations we acquired in the acquisition. 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 Railroad Commission of Texas (RRC) has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality. This division does not have WNA. However, our operations benefit from a declining block rate structure that partially mitigates the impact of warmer-than-normal weather on revenue. This rate structure is not as beneficial during periods where weather is significantly warmer than normal. The majority of this division’s residential and business customers use natural gas for heating, and their needs are directly affected by the mildness or severity of the heating season.

At closing of the acquisition, TXU Gas and some of its affiliates entered into transitional services agreements with us to provide call center, meter reading, customer billing, collections, information reporting, software, accounting, treasury, administrative and other services to the Mid-Tex Division. Some of these services were outsourced by TXU Gas to Capgemini Energy L.P. However, on November 4, 2004, we entered into an agreement with Capgemini Energy L.P. whereby we took over the operations of the Waco, Texas call center on April 1, 2005 and purchased from Capgemini Energy L.P. all of the related call center assets on October 1, 2005. The remaining transitional services agreements expired on September 30, 2005 and were not renewed as we have in-sourced all of these functions, effective October 1, 2005.

Atmos Energy Mississippi Division. Our Atmos Energy Mississippi Division (formerly known as Mississippi Valley Gas Company Division), which was acquired in December 2002, 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. Since the acquisition, we have been operating under a rate structure that allows us, over a five-year period, to recover a portion of our integration costs associated with the 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, we will move from a semi-annual filing process to an annual filing process. We also have WNA in Mississippi. This division’s gas supply is delivered 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. During 2004, the West Texas Division received approval from the City of Lubbock, Texas and the 66 cities in our West Texas system, for WNA in these service areas, which is effective October through May of each year, beginning with the 2004-2005 winter heating season. We also have WNA in our Amarillo service area. 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 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 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 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, 2005, AEM had a total of 558 industrial, 69 municipal and 210 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. The natural gas transmission and storage operations that we acquired in the TXU Gas acquisition, which are operated in the Atmos Pipeline — Texas Division, represent one of the largest intrastate pipeline operations in Texas. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and for third parties. These operations include interconnected natural gas transmission lines, five underground storage reservoirs (including a salt dome facility) and 24 compressor stations and related properties, all within Texas. These operations may create additional gas marketing and other opportunities for our non-regulated subsidiaries.

The gas distribution and transmission lines we acquired have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. In addition to being heavily concentrated in the established natural gas-producing areas of central, northern and eastern Texas, the intrastate pipeline system we acquired also extends 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 estimated to contain a substantial portion of the nation’s remaining onshore natural gas reserves. This pipeline system provides access to all of these basins. We believe that we are well situated to receive large volumes into this pipeline system at the major hubs, such as Katy, Waha and Carthage as well as from storage facilities where we maintain high delivery capabilities.

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.

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 on April 1, 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 construct gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

Through January 20, 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 2001 through 2005.


	*Utility Sales and Statistical Data*


			Year Ended September 30

			2005⁽¹⁾		2004		2003⁽¹⁾		2002		2001⁽¹⁾

METERS IN SERVICE, end of year
	Residential			2,862,822		1,506,777		1,498,586		1,247,247		1,243,625
	Commercial			274,536		151,381		151,008		122,156		122,274
	Industrial			2,715		2,436		3,799		2,118		1,838
	Agricultural			9,639		8,397		9,514		10,576		11,182
	Public authority and other			8,128		10,145		9,891		7,244		7,404

		Total meters		3,157,840		1,679,136		1,672,798		1,389,341		1,386,323

HEATING DEGREE DAYS⁽²⁾
	Actual (weighted average)			2,587		3,271		3,473		3,368		4,124
	Percent of normal			89%		96%		101%		94%		115%

UTILITY SALES VOLUMES — MMcf⁽³⁾
Gas Sales Volumes
	Residential			162,016		92,208		97,953		77,386		79,000
	Commercial			92,401		44,226		45,611		35,796		36,922
	Industrial			29,434		22,330		23,738		14,499		19,243
	Agricultural			3,348		4,642		7,884		10,988		7,070
	Public authority and other			9,084		9,813		9,326		5,875		6,892

		Total gas sales volumes		296,283		173,219		184,512		144,544		149,127
Utility transportation volumes				122,098		87,746		70,159		69,589		69,492

Total utility throughput				418,381		260,965		254,671		214,133		218,619

UTILITY OPERATING REVENUES (000’s)⁽³⁾
Gas Sales Revenues
	Residential		$	1,791,172	$	923,773	$	873,375	$	535,981	$	788,902
	Commercial			869,722		400,704		367,961		221,728		342,945
	Industrial			229,649		155,336		151,969		70,164		120,770
	Agricultural			27,889		31,851		48,625		37,951		28,753
	Public authority and other			86,853		77,178		65,921		31,731		58,539

		Total utility gas sales revenues		3,005,285		1,588,842		1,507,851		897,555		1,339,909
Transportation revenues				59,996		31,714		30,461		28,786		28,750
Other gas revenues				37,859		17,172		15,770		11,185		11,489

		Total utility operating revenues	$	3,103,140	$	1,637,728	$	1,554,082	$	937,526	$	1,380,148

Utility average transportation revenue per Mcf			$	0.49	$	0.36	$	0.43	$	0.41	$	0.41
Utility average cost of gas per Mcf sold			$	7.41	$	6.55	$	5.76	$	3.87	$	6.82

Employees⁽⁵⁾				4,327		2,742		2,817		2,255		2,299

See footnotes following these tables.


	*Utility Sales and Statistical Data By Division*


			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⁽⁵⁾			267		236		421		412		346		467		1,398		780			4,327

See footnotes following these tables.


			Year Ended September 30, 2004

			Colorado-						Mid-		West
			Kansas		Kentucky		Louisiana		States		Texas		Mississippi		Other⁽⁴⁾			Total Utility

METERS IN SERVICE
	Residential			205,028		159,214		348,390		274,662		270,854		248,629		—			1,506,777
	Commercial			19,190		18,077		22,754		36,187		25,818		29,355		—			151,381
	Industrial			85		409		—		712		548		682		—			2,436
	Agricultural			295		—		—		—		8,102		—		—			8,397
	Public authority and other			1,757		1,655		931		880		2,158		2,764		—			10,145

		Total		226,355		179,355		372,075		312,441		307,480		281,430		—			1,679,136

HEATING DEGREE DAYS⁽²⁾
	Actual			5,490		4,283		1,515		3,631		3,252		2,734		—			3,271
	Percent of normal			99%		98%		93%		95%		101%		90%		—			96%
SALES VOLUMES — MMcf⁽³⁾
Gas Sales Volumes
	Residential			16,271		10,980		14,997		17,257		18,402		14,301		—			92,208
	Commercial			6,093		4,865		6,699		12,502		6,953		7,114		—			44,226
	Industrial			304		1,713		—		7,852		3,393		9,068		—			22,330
	Agricultural			526		—		—		—		4,116		—		—			4,642
	Public authority and other			1,491		1,451		814		249		2,157		3,651		—			9,813

		Total		24,685		19,009		22,510		37,860		35,021		34,134		—			173,219
Transportation Volumes				8,879		27,059		7,073		22,001		20,579		2,155		—			87,746

Total Throughput				33,564		46,068		29,583		59,861		55,600		36,289		—			260,965


OPERATING MARGIN (000’s)⁽³⁾			$	65,539	$	52,567	$	106,184	$	112,904	$	85,805	$	80,135	$	—		$	503,134
OPERATING EXPENSES (000’s)⁽³⁾
	Operation and maintenance		$	25,934	$	16,077	$	35,084	$	40,806	$	47,134	$	29,128	$	1,308		$	195,471
	Depreciation and amortization		$	13,178	$	11,025	$	21,214	$	23,069	$	8,993	$	12,720	$	2,755		$	92,954
	Taxes, other than income		$	5,551	$	2,727	$	9,124	$	10,251	$	10,969	$	16,197	$	—		$	54,819

OPERATING INCOME (000’s)⁽³⁾			$	20,876	$	22,738	$	40,762	$	38,778	$	18,709	$	22,090	$	(4,063	)	$	159,890

CAPITAL EXPENDITURES (000’s)			$	22,226	$	20,902	$	36,865	$	36,863	$	36,196	$	21,503	$	14,736		$	189,291
PROPERTY, PLANT AND EQUIPMENT, NET (000’s)			$	235,386	$	174,473	$	309,267	$	400,302	$	246,381	$	199,443	$	104,052		$	1,669,304
OTHER STATISTICS, at year end
	Miles of pipe			6,405		3,851		8,063		7,878		15,125		6,294		—			47,616
	Employees⁽⁵⁾			278		239		431		427		349		519		499			2,742

See footnotes following these tables.


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


			Year Ended September 30

			2005⁽¹⁾		2004		2003		2002		2001

CUSTOMERS, end of year
	Industrial⁽⁶⁾			624		638		644		641		531
	Municipal⁽⁶⁾			69		80		94		101		68
	Other⁽⁶⁾			401		237		202		117		125

		Total		1,094		955		940		859		724

NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽³⁾⁽⁶⁾				273,201		265,090		294,785		273,692		98,869
PIPELINE TRANSPORTATION VOLUMES — MMcf ⁽³⁾				563,949		9,395		11,648		12,788		10,947
OPERATING REVENUES (000’s)⁽³⁾
	Natural gas marketing		$	2,106,278	$	1,618,602	$	1,668,493	$	1,031,874	$	447,096
	Pipeline and storage			164,742		19,758		20,298		18,720		29,996
	Other nonutility			5,302		3,393		2,853		5,985		29,440

		Total operating revenues	$	2,276,322	$	1,641,753	$	1,691,644	$	1,056,579	$	506,532

Equity in earnings of Woodward Marketing L.L.C.⁽⁶⁾			$	—	$	—	$	—	$	—	$	8,062

Employees, at year end				216		122		88		83		62

Notes to preceding tables:


⁽¹⁾	The operational and statistical information includes the operations of LGS since the July 1, 2001 acquisition date, 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. Degree-day information is adjusted for service areas that have weather normalized operations.

⁽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 other utility divisions.

⁽⁵⁾	The number of utility employees excludes 216, 122, 88, 83 and 62 other segment employees in 2005, 2004, 2003, 2002 and 2001.

⁽⁶⁾	Through March 31, 2001, substantially all of our natural gas marketing revenues and expenses were shown on the equity basis. Since April 1, 2001 natural gas marketing revenues and expenses have been consolidated.

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.

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 (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, certain 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 certain information regarding our ratemaking jurisdictions.


	*Jurisdictional Rate Summary*


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

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	11/25/96		38,451		10.10%		11.50%
	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

Date of Last

Debt/

Debt

Performance-Based

Division

Jurisdiction

Rate Action

Equity Ratio

Rider

WNA

Rate 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

LGS

10/1/04

53/47

Mid-States

Georgia

11/25/96

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

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.


	*Recent Ratemaking Activity*

Our current rate strategy focuses on addressing rate design and regulatory lag issues. We are seeking rate designs that decouple the recovery of our approved margins from customer usage patterns due to weather related variability, declining use per customer and energy conservation. Additionally, we are seeking to stratify rates for low income households and to recover the gas cost portion of our bad debt expense.

We are attempting to address regulatory lag issues by directing discretionary capital spending to jurisdictions that permit us to recover our investment in a more timely manner, working with our regulators to eliminate regulatory lag in our jurisdictions 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, 2005, 2004 and 2003 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 $6.3 million, $16.2 million and $18.6 million became effective in fiscal 2005, 2004 and 2003 as summarized below:


					Increase (Decrease) to Revenue for
	Most Recent				the Year Ended September 30
	Effective		Most Recent
Division	Date		Rate Action	Jurisdiction	2005		2004			2003

					(In thousands)
Atmos Pipeline — Texas		4/1/05	GRIP⁽¹⁾	Texas	$	1,802	$	—		$	—
Colorado-Kansas		4/1/04	Show Cause	Colorado		—		(1,900	)		—
		3/1/04	Rate Case	Kansas		—		2,500			—
Louisiana		11/1/02	Stable Rate Filing	Trans La		—		—			452	⁽²⁾
		11/1/02	Stable Rate Filing	LGS		—		—			15,300	⁽²⁾
		10/1/04	Stable Rate Filing	LGS		225		—			—
Mid-States		8/1/04	Rate Case	Virginia		—		372			—
Mississippi		(3)	Stable Rate Filing	Mississippi		4,300		10,545			—
West Texas		9/1/03	Rate Case	Amarillo		—		—			2,825
		3/1/04	Rate Case	Lubbock		—		1,525			—
		5/1/04	Rate Case	West Texas		—		3,200			—

					$	6,327	$	16,242		$	18,577


⁽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 who enter the program will be required to file a complete rate case at least once every five years.

⁽²⁾	In 2002, we submitted our 2001 rate stabilization filing and received tariff revisions which resulted in an increase in annual revenues of $0.5 million for our Trans La System and $15.3 million in our LGS System during the first 24-month period beginning in November 2002. Subsequent to the first 24-month period, adjusted rates have provided an increase in annual revenues of $0.4 million for our Trans La System and $11.9 million for our LGS System.

⁽³⁾	The MPSC 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 2005 but had not been completed as of September 30, 2005:


			Revenue
Division	Rate Action	Jurisdiction	Requested

			(In thousands)
Atmos Pipeline — Texas	GRIP	Texas	$	1,919
Louisiana	Stable Rate Filing	LGS⁽¹⁾		3,326
Mid-States	Rate Case	Georgia		4,023
Mid-Tex	2003 GRIP	Texas		6,691
	2004 GRIP	Texas		6,731
West Texas	GRIP	Texas		3,803

			$	26,493


⁽¹⁾	This rate increase was implemented during fiscal 2005 but has not been recognized in our results of operations as it is subject to refund pending the final resolution of that filing.

Our recent ratemaking activity is discussed in greater detail below.

Atmos Pipeline-Texas. 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 should result in additional revenues of approximately $1.8 million. The RRC approved this filing in March 2005. These capital costs are being recovered through a monthly customer charge that began in April 2005. The allowed rate of return is 8.258 percent.

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. It is anticipated that $1.9 million in additional annual revenue will be authorized through this filing. A decision on this filing must be made by the RRC before January 4, 2006.

Atmos Energy Colorado-Kansas Division. 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 1, 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 1, 2005. WNA became effective in Kansas in October 2003 in accordance with the Kansas Corporation Commission’s ruling in May 2003.

Atmos Energy Louisiana Division. 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 Rate Stabilization Clause filing in 2004 and is subject to refund, pending the final resolution of that filing. As the rate increase is subject to refund, we have not recognized the effects of this increase in our results of operations during fiscal 2005.

During fiscal 2004, the Louisiana Public Service Commission approved tariff revisions for our LGS System 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. On October 8, 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 1, 2003 for a period of 14 years. No retroactive adjustments were required under this agreement.

In January and February 2002, our Louisiana Division submitted its 2001 Rate Stabilization filings to the LPSC for the two gas systems we operate in Louisiana. The LPSC audited the filings and found our earnings to be deficient and that rate adjustments were appropriate. Approved tariff revisions, which became effective November 1, 2002, resulted in $15.3 million in additional revenues per year for our LGS System and $0.5 million for our Trans La System during the first 24-month period beginning in November 2002. Subsequent to the first 24-month period, adjusted rates provided total annual revenue increases of $11.9 million for our LGS System and $0.4 million for our Trans La System. As a result of the actions taken by the LPSC, we have decreased the overall weather impact on our revenues in Louisiana, primarily through increases in the fixed portion of customers’ monthly bills.

In 2001, in connection with its review of our acquisition of Louisiana Gas Service, the LPSC approved a rate structure that requires us to share with the customers of Louisiana Gas Service cost savings that result from the acquisition. The shared cost savings are the difference between operation and maintenance expense in any future year and the 1998 normalized expense for Louisiana Gas Service, indexed for inflation, annual

changes in labor costs and customer growth. Since January 1, 2002, customers have been assured they will receive annual savings, which will be indexed for inflation, annual changes in labor costs and customer growth. The sharing mechanism will remain in place for 20 years, subject to established modification procedures.

Atmos Energy Mid-States Division. During the third quarter of 2005, the Mid-States Division filed a rate case in its Georgia service area seeking a rate increase of $4.0 million. We anticipate that the rate case will be finalized in November 2005.

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.

In November 2005, we received a notice from the Tennessee Regulatory Authority that it was opening an investigation into allegations that we are overcharging customers in parts of Tennessee by approximately $10.0 million per year. We do not believe that we are overcharging our customers and we intend to participate fully in the investigation.

Atmos Energy Mid-Tex Division. 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 should result in additional revenues of approximately $6.7 million. These capital costs will be recovered through a monthly customer charge that began in October 2005.

In September 2005, the Mid-Tex Division made a GRIP filing to include in rate base approximately $29.4 million of distribution capital costs incurred during calendar year 2004. It is anticipated that $6.7 million in additional annual revenue will be authorized through this filing. The cities in this division’s service area and the RRC must rule on this filing before January 4, 2006. If necessary, the RRC will rule on an appeal of any cities actions in the first quarter of calendar year 2006.

On September 1, 2005, the Mid-Tex Division filed its annual gas cost reconciliation with the RRC. The filing involves approximately $14.0 million in refunds of amounts overcollected from customers between July 1, 2004 and June 30, 2005. The Mid-Tex Division has proposed to the RRC the accelerating of refunds to December through March rather than during the usual refund period of October through June to help offset higher gas costs for residential, commercial and industrial customers during the 2005 — 2006 heating season, which proposal is still under consideration.

In August 2005, we received a “show cause” order from the City of Dallas, which requires us to provide information that demonstrates good cause for showing that our existing distribution rates charged to customers in the city of Dallas should not be reduced. We are currently preparing our response to this order and anticipate filing it by the November 22, 2005 due date.

In September 2004, the Mid-Tex Division filed its 36-Month Gas Contract Review with the RRC. This proceeding involves a prudency review of gas purchases totaling $2.2 billion made by the Mid-Tex Division from November 1, 2000 through October 31, 2003. A hearing on this matter was held before the RRC in late June. No decision is expected from the RRC until the end of December 2005 or January 2006.

During the first quarter of fiscal 2005, the Mid-Tex Division pursued a filing initiated by TXU Gas seeking authorization of a surcharge to recover the rate case expenses incurred by the Mid-Tex Division, Atmos Pipeline — Texas Division and the intervening cities in connection with their last systemwide rate case completed in May 2004. The filing also covered the estimated expenses to prosecute the aforementioned recovery docket and the severed dockets from the systemwide rate case. On January 25, 2005, the RRC issued an order authorizing the recovery of the $10.2 million of expenses over a 3-year period with interest.

The Mid-Tex Division is also pursuing an appeal to the Travis County District Court of the Final Order in its last systemwide 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 most recent rate case completed in May 2004. Additionally, the Mid-Tex Division is seeking the right to surcharge for gas cost underrecoveries. The

case has been assigned to a judge, but the briefing schedule has been postponed indefinitely to allow the parties to pursue settlement discussions.

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 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, we will move from a semi-annual filing process to an annual filing process. Additionally, our WNA period will begin on November 1 instead of November 15, and will end 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. We will make our first annual filing under this new structure in September 2006.

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 on December 1, 2003. In September 2004, the MPSC authorized additional annualized revenue of $4.7 million on our May 2004 filing, which became effective on June 1, 2004. However, the MPSC originally disallowed certain deferred costs totaling $2.8 million. In connection with the modification of our rate design described above, the MPSC reversed its decision regarding these costs, and we included these costs into our rates in October 2005.

We filed our second semiannual filing for 2004 on November 5, 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 1, 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. We expect these capital costs will be recovered through a monthly customer charge beginning in December 2005.

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 1, 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.

In June 2003, the West Texas Division filed a rate case in Amarillo, Texas, requesting a $5.1 million increase in annual revenues. In August 2003, the City of Amarillo, Texas approved an annual increase of approximately $2.8 million, which was effective for bills rendered on or after September 1, 2003. The increase was primarily comprised of an increase in monthly customer charges. The agreement with Amarillo also provided for changes in the rate structure to recover the cost of uncollectible accounts, adjustments to base rates to compensate for declining gas usage per customer and provided WNA for the period October through May of each year, which became effective in October 2003.

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 manufactured gas plant sites in Tennessee, Iowa and Missouri and mercury contamination sites in Kansas. These claims are more fully described in Note 13 to the consolidated financial statements.

Our Mid-Tex and Atmos Pipeline — Texas operations are wholly intrastate in character and are subject to regulation by municipalities in Texas and the Railroad Commission of Texas. These acquired operations do not include any certificated interstate transmission facilities subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, any sales for resale under the rate jurisdiction of the FERC or any transportation service that is subject to FERC jurisdiction under the Natural Gas Act. Since 1988, the FERC has allowed, pursuant to Section 311 of the Natural Gas Policy Act, gas transportation services through the intrastate transmission facilities we acquired “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting the acquired operations to the jurisdiction of the FERC. We did not acquire any manufactured gas plant sites in the TXU Gas acquisition. Our acquisition agreement with TXU Gas addresses other environmental matters, which we expect to have no material adverse effect on us or our operations.

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, 2005, we had 4,543 employees, consisting of 4,327 employees in our utility segment and 216 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 such reports with, or furnish such reports to, the SEC. We will also

furnish copies of such reports free of charge upon written 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 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 amended 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 furnish copies of such information free of charge upon written request to Shareholder Relations at the address listed above.


ITEM 2.	*Properties*

Distribution, transmission and related assets

At September 30, 2005 our utility segment owned an aggregate of 81,604 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, 2005, our pipeline and storage segment owned 6,369 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, 2005, we held 1,098 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 key information regarding our underground gas storage facilities:


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

Utility Segment
Liberty North		Montgomery County, KS		2,800,000		2,000,000		4,800,000		40,000
St. Charles		Hopkins County, KY		2,685,196		3,422,283		6,107,479		44,600
Amory		Monroe County, MS		800,635		788,457		1,589,092		30,000
Bon Harbor		Daviess County, KY		778,600		1,300,000		2,078,600		24,000
Goodwin		Monroe County, MS		743,998		1,393,280		2,137,278		18,000
Hickory		Daviess County, KY		451,600		850,000		1,301,600		24,000
Columbus LNG Plant		Muscogee County, GA		450,000		50,000		500,000		30,000
Liberty South		Montgomery County, KS		439,000		300,000		739,000		5,000
Grandview		Daviess County, KY		305,400		350,000		655,400		4,500
Kirkwood		Hopkins County, KY		221,900		400,000		621,900		12,000
Buffalo		Wilson County, KS		200,000		180,000		380,000		5,000
Fredonia		Wilson County, KS		200,000		160,000		360,000		5,000

Total Utility Segment				10,076,329		11,194,020		21,270,349		242,100
Pipeline and Storage Segment
Tri-Cities⁽²⁾		Malakoff, TX		19,993,475		5,660,000		25,653,475		275,000
Bethel⁽²⁾		Howard, TX		7,100,000		3,000,000		10,100,000		600,000
New York City⁽²⁾		Bellvue, TX		5,650,000		2,083,025		7,733,025		120,000
Lapan⁽²⁾		Bellvue, TX		3,425,000		1,070,000		4,495,000		120,000
Lake Dallas⁽²⁾		Denton, TX		2,960,000		1,315,000		4,275,000		120,000
East Diamond		Hopkins County, KY		2,160,000		1,640,000		3,800,000		40,000
Barnsley		Hopkins County, KY		1,278,900		1,600,000		2,878,900		30,000
Napoleonville⁽³⁾		Assumption Parish, LA		438,583		300,973		739,556		56,000
Crofton		Christian County, KY		54,000		55,000		109,000		1,000

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.

⁽²⁾	Acquired on October 1, 2004 in connection with the TXU Gas acquisition.

⁽³⁾	We own 25 percent of this facility and Acadian Gas Pipeline System owns the remaining 75 percent of this facility. Acadian Gas Pipeline System operates this facility.

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		1,941,280		97,064
	Louisiana Intrastate Gas Company		600,000		60,000
	Texas Gas Transmission		11,372		1,194
	Southern Natural Gas Company		4,771		102
	Tennessee Gas Pipeline Company		4,466		91

Mid-States Division	Atmos Energy Marketing		1,993,543		16,634
	Southern Natural Gas Company		1,453,265		29,345
	Panhandle Eastern Pipeline		972,462		15,241
	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		630,500		11,218
	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		5,108
	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
	Egan Storage		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			27,225,869		770,251

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
	Virginia Gas Pipeline Company		170,000		17,000

Total Natural Gas Marketing Segment			8,662,015		216,686

Pipeline and Storage Segment
Trans Louisiana Gas Pipeline, Inc.	Gulf South Pipeline Company		750,000		20,000
	Bridgeline Gas Distribution LLC		300,000		30,000

Total Pipeline and Storage Segment			1,050,000		50,000

Total Contracted Storage Capacity			36,937,884		1,036,937


⁽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 2005.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of September 30, 2005, 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		58		8	Chairman, President and Chief Executive Officer
John P. Reddy		52		7	Senior Vice President and Chief Financial Officer
R. Earl Fischer		66		43	Senior Vice President, Utility Operations and President, Mid-Tex Division
JD Woodward III		55		4	Senior Vice President, Nonutility Operations
Louis P. Gregory		50		5	Senior Vice President and General Counsel
Wynn D. McGregor		52		17	Vice President, Human Resources

Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997. He previously served as Senior Vice President — Regulated Businesses of Consolidated Natural Gas Company (January 1996-March 1997) and was responsible for its transmission and distribution companies.

John P. Reddy was named Senior Vice President and Chief Financial Officer in September 2000. From April 2000 to September 2000, he was Senior Vice President, Chief Financial Officer and Treasurer. Mr. Reddy previously served the Company as Vice President, Corporate Development and Treasurer from December 1998 to March 2000. He joined the Company in August 1998 from Pacific Enterprises, a Los Angeles, California-based utility holding company whose principal subsidiary was Southern California Gas Co.

R. Earl Fischer was named Senior Vice President, Utility Operations in May 2000 and President of the Mid-Tex Division in October 2004. Effective October 1, 2005, Mr. Fischer relinquished his duties as President of the Mid-Tex Division. Mr. Fischer previously served the Company as President of the Texas Division from January 1999 to April 2000 and as President of the Kentucky Division from February 1989 to December 1998.

JD Woodward III was named Senior Vice President, Nonutility Operations in April 2001. Prior to joining the Company, Mr. Woodward was President of Woodward Marketing, L.L.C. from January 1995 to March 2001. Effective April 1, 2006, Mr. Woodward will retire from the Company and be succeeded by Mark H. Johnson, Vice President, Nonutility Operations.

Louis P. Gregory was named Senior Vice President and General Counsel in September 2000. Prior to joining the Company, he practiced law from April 1999 to August 2000 with the law firm of McManemin & Smith.

Wynn D. McGregor was named Vice President, Human Resources in January 1994. He previously served the Company as Director of Human Resources from February 1991 to December 1993 and as Manager, Compensation and Employment from December 1987 to January 1991. Effective October 1, 2005, Mr. McGregor was named Senior Vice President, Human Resources.

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 2005 and 2004 are listed below. The high and low prices listed are the closing NYSE quotes for shares of our common stock:


		2005						2004

						Dividends						Dividends
		High		Low		Paid		High		Low		Paid

Quarter ended:
	December 31	$	27.43	$	24.85	$	.310	$	24.99	$	24.15	$	.305
	March 31		29.09		26.19		.310		26.86		24.32		.305
	June 30		28.87		25.94		.310		26.05		23.68		.305
	September 30		29.76		28.23		.310		25.86		24.61		.305

						$	1.24					$	1.22

Dividend payments 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 agreements. 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, 2005 was 26,170. 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 2005 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, 2005.

Number of

Weighted-

Number of Securities

Securities to be

Average Exercise

Remaining Available for

Issued Upon

Price of

Future Issuance Under

Exercise of

Outstanding

Equity Compensation

Outstanding

Options,

Plans (Excluding

Options, Warrants

Warrants and

Securities Reflected in

and Rights

Rights

Column(a))

(a)

(b)

(c)

Equity compensation plans approved by security holders:

Long-Term Incentive Plan

964,704

22.20

1,290,292

Long-Term Stock Plan for the Mid-States Division

300

15.50

168,550

Total equity compensation plans approved by security holders

965,004

22.20

1,458,842

Equity compensation plans not

approved by security holders

—

Total

965,004

22.20

1,458,842


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

		2005⁽¹⁾		2004⁽²⁾		2003⁽³⁾			2002			2001⁽⁴⁾

		(In thousands, except per share data and ratios)
Results of Operations
Operating revenues		$	4,973,326	$	2,920,037	$	2,799,916		$	1,650,964		$	1,725,481
Gross profit			1,129,090		562,191		534,976			431,140			375,208
Operating expenses			780,435		368,496		347,136			275,809			244,927
Operating income			348,655		193,695		187,840			155,331			130,281
Miscellaneous income (expense)⁽²⁾			2,021		9,507		2,191			(1,321	)		6,188
Interest charges			132,658		65,437		63,660			59,174			47,011
Income before income taxes and cumulative effect of accounting change			218,018		137,765		126,371			94,836			89,458
Cumulative effect of accounting change, net income tax benefit			—		—		(7,773	)		—			—
Income tax expense			82,233		51,538		46,910			35,180			33,368
Net income		$	135,785	$	86,227	$	71,688		$	59,656		$	56,090
Weighted average diluted shares outstanding			79,012		54,416		46,496			41,250			38,247
Diluted net income per share		$	1.72	$	1.58	$	1.54		$	1.45		$	1.47
Cash flows from operations			386,944		270,734		49,541			297,395			82,995
Cash dividends paid per share		$	1.24	$	1.22	$	1.20		$	1.18		$	1.16
Total utility throughput (MMcf)			411,134		246,033		247,965			208,541			217,774
Total natural gas marketing sales volumes (MMcf)			238,097		222,572		225,961			204,027			55,469
Total pipeline transportation volumes (MMcf)			375,604		—		—			—			—
Financial Condition
Net property, plant and equipment⁽⁵⁾		$	3,374,367	$	1,722,521	$	1,624,394		$	1,380,070		$	1,409,432
Working capital⁽⁵⁾			151,675		283,310		16,248			(139,150	)		(90,968	)
Total assets⁽⁵⁾⁽⁶⁾			5,653,527		2,912,627		2,625,495			2,059,631			2,108,841
Short-term debt, inclusive of current maturities of long-term debt			148,073		5,908		127,940			167,771			221,942
Capitalization:
	Shareholders’ equity		1,602,422		1,133,459		857,517			573,235			583,864
	Long-term debt (excluding current maturities)		2,183,104		861,311		862,500			668,959			691,026

Total capitalization			3,785,526		1,994,770		1,720,017			1,242,194			1,274,890
Capital expenditures			333,183		190,285		159,439			132,252			113,109
Financial Ratios
Capitalization ratio⁽⁶⁾			40.7%		56.7%		46.4%			40.7%			39.0%
Return on average shareholders’ equity ⁽⁷⁾			9.0%		9.1%		9.9%			9.9%			10.4%

See footnotes on the following page.


⁽¹⁾	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.

⁽²⁾	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.

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

⁽⁴⁾	Financial results for fiscal 2001 include the results of Louisiana Gas Service Company from July 1, 2001 and Woodward Marketing L.L.C. from April 1, 2001, the date of each acquisition, and the equity earnings from our 45 percent investment in Woodward Marketing L.L.C. for the period October 1, 2001 through March 31, 2002.

⁽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, 2002 and 2001.

⁽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, 2002 and 2001.

⁽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, 2005.


			Year Ended September 30, 2005

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	3,102,041	$	1,783,926	$	85,333	$	2,026	$	—		$	4,973,326
Intersegment revenues				1,099		322,352		79,409		3,276		(406,136	)		—

				3,103,140		2,106,278		164,742		5,302		(406,136	)		4,973,326
Purchased gas cost				2,195,774		2,044,305		6,811		—		(402,654	)		3,844,236

	Gross profit			907,366		61,973		157,931		5,302		(3,482	)		1,129,090
Operating expenses				671,001		20,988		87,645		4,484		(3,683	)		780,435

Operating income				236,365		40,985		70,286		818		201			348,655
Miscellaneous income				6,776		771		2,030		2,575		(10,131	)		2,021
Interest charges				112,382		3,405		24,579		2,222		(9,930	)		132,658

Income before income taxes				130,759		38,351		47,737		1,171		—			218,018
Income tax expense				49,642		14,947		17,138		506		—			82,233

		Net income	$	81,117	$	23,404	$	30,599	$	665	$	—		$	135,785

Capital expenditures			$	300,574	$	649	$	31,960	$	—	$	—		$	333,183


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 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 the Company’s consolidated financial statements and notes thereto.


	*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 the Company 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 the Company’s documents or oral presentations, the words “anticipate”, “believe”, “expect”, “estimate”, “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 the Company’s strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions, such as warmer than normal weather in the Company’s utility service territories or colder than normal weather that could adversely affect our natural gas marketing activities; regulatory trends and decisions, including deregulation initiatives and the impact of rate proceedings before various state regulatory commissions; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness; national, regional and local economic conditions; the Company’s 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; risks relating to the acquisition of the TXU Gas operations, including without limitation, the Company’s increased indebtedness resulting from the acquisition of the TXU Gas operations; the impact of recent natural disasters on our operations, especially Hurricane Katrina, and other uncertainties discussed herein, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes 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, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.

FACTORS THAT MAY AFFECT OUR FUTURE PERFORMANCE

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 below. 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 these forward-looking statements.


	*Our operations are weather sensitive.*

Weather is one of the most significant factors influencing our performance. Our natural gas utility sales volumes and related revenues are correlated with heating requirements that result from cold winter weather. Our agricultural sales volumes are associated with the rainfall levels during the growing season in our

West Texas and Kansas irrigation markets. Although weather normalized rates in effect in several of our jurisdictions should mitigate the adverse effects of warmer than normal weather on our utility operating results, approximately fifteen to twenty percent of our utility gross profit margin is sensitive to weather, particularly our Louisiana and Mid-Tex divisions. This means we will not be able to increase customers’ bills to offset lower gas usage when the weather is warmer than normal.

Our Mid-Tex Division operations benefit from a rate structure that combines 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 provides for the recovery of most of our fixed costs for such operations under most weather conditions. However, this rate structure is not as beneficial during periods where weather is significantly warmer than normal.

Finally, 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.


	*We are subject to regulation which can directly impact our operations.*

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, our effectiveness in earning such rates and initiate rate proceedings or operating changes as needed. In addition, in the normal course of the regulatory environment, assets are placed in service and historical test periods are established before rate cases 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 temporarily 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, once our rates have been approved, they are still subject to challenge for their reasonableness by appropriate regulatory authorities. Also, our debt and equity financings are also subject to approval by regulatory bodies in certain states, which could limit our ability to take advantage of favorable short-term 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. Because of our enhanced technology and distribution system infrastructures, we believe that we are now positively positioned should unbundling evolve. Consequently, we expect there would be no significant adverse effect on our business should unbundling or further deregulation of the natural gas distribution service business occur.

Finally, 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 seek to minimize this risk by increasing our storage capacity and enhancing the flexibility of our natural gas marketing contracts.


	*Our operations are exposed to market risks that are beyond our control, which could result in financial losses.*

Our risk management operations in our natural gas marketing segment are subject to market risks beyond our control including market liquidity, commodity price volatility and counterparty creditworthiness. Market liquidity is affected by the number of trading partners in the market.

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 gas trading activities which could lead to financial losses. Physical trading also introduces price risk on any net open positions at the end of each trading day, as well as a risk of loss 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, at times, 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 result in an adverse impact on our financial condition or results of operations if market prices move in an unfavorable manner.

Our utility segment uses a combination of storage and financial hedges to partially insulate us against volatility in gas prices and to help moderate the effects of higher customer accounts receivable caused by higher gas prices. Our natural gas marketing segment manages margins and limits risk exposure on the sale of natural gas inventory or the offsetting fixed-price purchase or sale commitments for physical quantities of natural gas through the use of a variety of financial derivatives.

We could realize financial losses on these activities as a result of volatility in the market value of the underlying commodities or if a counterparty fails to perform under a contract.

Further, the use of financial instruments to conduct our hedging and market risk activities subjects us to counterparty risk. 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 believe this risk is mitigated due to the large number of counterparties used in our risk management activities.

Our net periodic pension and other postretirement costs are subject to market risk as the fluctuation in the fair value of the assets used to fund our various benefit plans could lead to significant fluctuations in these costs.

Finally, we are subject to interest rate risk on our commercial paper borrowings and floating rate debt. We could experience higher interest expense if interest rates increase or increased volatility if short-term interest rates become volatile.


	*National, regional and local economic conditions have a direct impact on our operations.*

Our operations are affected by the conditions and overall strength of the national, regional and local economies, including interest rates, changes in the capital markets and increases in the costs of our primary commodity, natural gas. These factors impact the amount of residential, industrial and commercial growth in our service territories. Additionally, these factors could adversely impact our customer collections.

Further, AEM’s operations are concentrated in the natural gas industry, and its customers and suppliers may be subject to economic risks affecting that industry.


	*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 as a source of liquidity to satisfy our liquidity requirements. Although we believe we will maintain sufficient access to these financial markets, adverse changes in the economy, the overall health of the industries in which we operate and changes to our credit ratings could limit access to these markets and 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 Service (Moody’s) and Fitch Ratings, Inc. (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 certain 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. The ability to control expenses is an important factor that will influence future results.

Rapid increases in the price of purchased gas, which has occurred recently and in some prior years, causes 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 situation could result in higher short-term debt levels and increased bad debt expense. Due to the significant increase in natural gas prices resulting primarily from the impact of recent natural disasters, we are anticipating increases in our short-term debt, accounts receivable and bad debt expense during fiscal 2006.

Finally, higher costs of natural gas in recent years have already caused many of our utility customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation methods.


	*Our operations are subject to increased competition.*

We are facing increased competition from other energy suppliers as well as electric companies and from energy marketing and trading companies. 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.


	*We have only limited recourse under the acquisition agreement for losses relating to the TXU Gas acquisition.*

The diligence conducted in connection with the TXU Gas acquisition and the indemnification provided in the acquisition agreement may not be sufficient to protect us from, or compensate us for, all losses resulting from the acquisition or TXU Gas’s prior operations. For example, under the terms of the acquisition agreement, the first $15 million of many indemnifiable losses are to be borne by us, and the agreement provides for sharing of losses with respect to unknown environmental matters that may affect the assets we acquired after we have borne $10 million in costs relating to such matters. In addition, under the terms of the acquisition agreement, the maximum aggregate amount of such losses for which TXU Gas will indemnify us is approximately $192.5 million. A material loss associated with the TXU Gas acquisition for which there is not adequate indemnification could negatively affect our results of operations, our financial condition and our reputation in the industry, thereby reducing the anticipated benefits of the acquisition.


	*Recent natural disasters, especially Hurricane Katrina, have adversely impacted our operations.*

St. Bernard and Plaquemines parishes. In total, approximately 230,000 of our natural gas customers were affected in these areas. A significant number of these customers will not require gas service for some time because of sustained damages. We cannot predict with certainty how many of these customers will return to these service areas and over what time period. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. Finally, although we believe our insurance will cover all losses in excess of our deductibles, it is possible that certain of these losses may not be fully recoverable.

OVERVIEW

In fiscal 2005, we earned $135.8 million in net income or $1.72 per diluted share, compared with net income of $86.2 million, or $1.58 per diluted share in fiscal 2004. The 58 percent year-over-year increase in net income was primarily attributable to the incremental results we achieved from our Mid-Tex and Atmos Pipeline — Texas divisions that we acquired on October 1, 2004. Strong earnings in our natural gas marketing segment primarily attributable to favorable results from the management of our storage portfolio also contributed to the increase in net income. These positive factors helped overcome the adverse effects on our utility segment of weather (adjusted for WNA) that was 11 percent warmer than normal, which reduced our net income by $22.8 million, or $0.29 per diluted share, and the impact of Hurricane Katrina, which reduced our net income by $3.8 million, or $0.05 per diluted share.

Fiscal 2005 was highlighted by our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company. The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs in Texas.

The purchase price of the TXU Gas acquisition was approximately $1.9 billion, before transaction costs and expenses, which we paid in cash. We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of approximately 9.9 million shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. In October 2004, we repaid the outstanding commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004, which generated net proceeds of approximately $1.4 billion and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of approximately $381.6 million.

As a result of the acquisition, effective October 1, 2004, we created the pipeline and storage segment which includes 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, which was previously included in our other nonutility segment.

The TXU Gas acquisition essentially doubled the size of the Company as measured by assets, revenues and customers. The following table presents selected financial information for the Mid-Tex Division and Atmos Pipeline — Texas Division operations for the year ended September 30, 2005:


		Year Ended
		September 30, 2005

				Atmos
				Pipeline —
		Mid-Tex		Texas
		Division		Division

		(In thousands, unless
		otherwise noted)
Operating revenues		$	1,326,940	$	154,405
Gross profit			398,234		149,487
Operation and maintenance			146,449		60,102
Depreciation and amortization			64,460		15,281
Taxes, other than income			102,360		8,264
Operating income			84,965		65,840
Miscellaneous income			2,272		150
Interest charges			47,668		23,344
Income tax expense			14,455		15,064
Net income		$	25,114	$	27,582

Utility sales volumes — MMcf			127,497		N/A
Utility transportation volumes — MMcf			46,757		N/A

	Total utility throughput — MMcf		174,254		N/A

Pipeline transportation volumes — MMcf			N/A		375,604

Heating Degree Days — Percent of Normal			80%		N/A

The impact of the TXU Gas acquisition, combined with continued strong performance in our natural gas marketing segment contributed to the following financial results during the year ended September 30, 2005:


	•	Our utility segment net income increased by $18.0 million. The increase reflects the impact of the acquisition of the Mid-Tex operations ($25.1 million) and the effect of rate increases in our West Texas and Mississippi jurisdictions that were not in effect during the first six months of fiscal 2004, partially offset by weather (adjusted for WNA) in our other utility operations that was five percent warmer than normal and one percent warmer than the prior year.

	•	Our natural gas marketing segment net income increased $6.8 million during the year ended September 30, 2005 compared with the year ended September 30, 2004. The increase in natural gas marketing net income primarily reflects favorable results from the management of our storage portfolio partially offset by an unfavorable movement in the forward indices used to value our storage financial instruments.

	•	Our pipeline and storage segment contributed $30.6 million in net income for the year ended September 30, 2005 compared with $2.8 million for the year ended September 30, 2004, primarily reflecting the acquisition of the Atmos Pipeline — Texas Division ($27.6 million).

	•	Our total debt to capitalization ratio at September 30, 2005 was 59.3 percent compared with 43.3 percent at September 30, 2004 reflecting the impact of the financing for the TXU Gas acquisition, partially offset by the repayment of $72.5 million in principal of substantially all of our First Mortgage bonds in June 2005.


	•	Operating cash flow provided $386.9 million compared with $270.7 million, reflecting increased net income and more effective net working capital management partially offset by lower than expected utility sales volumes due to the effect of warmer weather.

	•	Capital expenditures increased to $333.2 million from $190.3 million primarily reflecting spending for the Mid-Tex Division ($115.0 million) and the Atmos Pipeline — Texas Division ($31.4 million).

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.

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.

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, 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 AEM. AEM 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 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.

Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market monthly using the inside FERC (iFERC) price at the end of each month. Changes in fair value are recognized as unrealized gains and losses in the period of change. 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 and losses in the period of change. The difference in the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) is 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, resulting in the realization of the economic gross profit margin we anticipated at the

time we structured the original transaction. In addition, we continually manage our positions to optimize value as market conditions and other circumstances change.

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 1, 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. In addition, we continually managed our positions to optimize value as market conditions and other circumstances changed.

Effective April 1, 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 are now 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.

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 will be 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 present 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 absolute 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 will impact our pension and postretirement cost approximately $1.6 million. A 0.25 percent change in our expected rate of return will 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, 2005:


		For the Year Ended September 30

		2005		2004			2003

		(In thousands, unless otherwise noted)
Operating revenues		$	4,973,326	$	2,920,037		$	2,799,916
Gross profit			1,129,090		562,191			534,976
Operating expenses			780,435		368,496			347,136
Operating income			348,655		193,695			187,840
Miscellaneous income			2,021		9,507			2,191
Interest charges			132,658		65,437			63,660
Income before income taxes and cumulative effect of accounting change			218,018		137,765			126,371
Cumulative effect of accounting change, net of income tax benefit			—		—			(7,773	)
Income tax expense			82,233		51,538			46,910
Net income		$	135,785	$	86,227		$	71,688

Utility sales volumes — MMcf			296,283		173,219			184,512
Utility transportation volumes — MMcf			114,851		72,814			63,453

	Total utility throughput — MMcf		411,134		246,033			247,965

Natural gas marketing sales volumes — MMcf			238,097		222,572			225,961

Pipeline transportation volumes — MMcf			375,604		—			—

Heating Degree Days⁽¹⁾
	Actual (weighted average)		2,587		3,271			3,473
	Percent of normal		89%		96	%		101	%
Consolidated utility average transportation revenue per Mcf		$	0.51	$	0.42		$	0.47
Consolidated utility average cost of gas per Mcf sold		$	7.41	$	6.55		$	5.71


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

The following table shows our operating income by utility division and by segment for the three fiscal years ended September 30, 2005. The presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


		2005					2004						2003

				Heating						Heating						Heating
				Degree						Degree						Degree
				Days						Days						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		$	25,157		99	%	$	20,876			99	%	$	23,756			101	%
Kentucky			18,657		98	%		22,738			98	%		21,841			101	%
Louisiana			24,819		78	%		40,762			93	%		41,672			106	%
Mid-States			35,687		93	%		38,778			95	%		37,535			101	%
Mid-Tex			84,965		80	%		—			—			—			—
Mississippi			19,045		96	%		18,709			101	%		17,617			101	%
West Texas			27,520		99	%		22,090			90	%		19,650			97	%
Other			515		—			(4,063	)		—			(937	)		—

Utility segment			236,365		89	%		159,890			96	%		161,134			101	%
Natural gas marketing segment			40,985		—			27,726			—			13,569			—
Pipeline and storage segment			70,286		—			5,293			—			11,814			—
Other nonutility segment			1,019		—			786			—			1,323			—

	Consolidated operating income	$	348,655		89	%	$	193,695			96	%	$	187,840			101	%


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

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


	*Utility segment*

Our utility segment has historically contributed 70 to 85 percent of our consolidated net income. 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 67 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. Utility sales to agricultural customers, which typically use natural gas to power irrigation pumps during the period from March through September, are primarily affected by rainfall amounts and the price of natural gas.

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 partially offset through weather normalization adjustments in certain 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.

Our Mid-Tex Division does not have WNA. However, its operations benefit from a rate structure that combines 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 provides for the recovery of a significant portion of our fixed costs for such operations under average weather conditions. However, this rate structure is not as beneficial during periods where weather is significantly warmer than normal.


	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*

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 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.


	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, 2005 and 2004:


		Year Ended September 30

		2005			2004

		(In thousands, except
		storage balances)
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

Ending storage balance (Bcf)			6.9			5.5

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*

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

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 provide all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of this 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

Pipeline and storage gross profit increased to $157.9 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 375.6 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 $149.5 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 $87.6 million for the year ended September 30, 2005 from $5.1 million for the year ended September 30, 2004 due to the addition of $83.6 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*

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 1, 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 construct gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

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.

Year ended September 30, 2004 compared with year ended September 30, 2003


	*Utility segment*


	Operating income

Utility gross profit margin increased to $503.1 million for the year ended September 30, 2004 from $491.4 million for the year ended September 30, 2003. Total throughput for our utility business was 261.0 Bcf during the year compared to 254.7 Bcf in the prior year. Excluding intercompany throughput, consolidated throughput for our utility business was 246.0 Bcf during the year, compared with 248.0 Bcf in the prior year.

The increase in utility gross profit margin primarily reflects the impact of the acquisition of Mississippi Valley Gas Company whose operations are included for the entire first quarter in fiscal year 2004, compared with one month in the first quarter of the prior fiscal year resulting in an increase in utility gross profit margin and total throughput of $12.8 million and 5.0 Bcf. Utility gross profit margin was also favorably impacted by rate increases received in Kansas, Texas and Mississippi and a $10.2 million year-over-year increase in the effect of WNA in our WNA service areas. These increases were partially offset by the impact of weather that was six percent warmer than that of the prior year and four percent warmer than normal, resulting in a decrease of approximately $13.8 million and lower irrigation sales in our West Texas Division resulting in a decrease of approximately $2.1 million. Warmer than normal weather particularly impacted our service areas in our Louisiana, Mid-States and West Texas divisions. The decrease in throughput also reflects a decrease in consumption attributable to the impact of conservation and the continued introduction of more efficient gas appliances in our service areas. Finally, our utility gross profit margin for the year ended September 30, 2004 reflects a one-time reduction resulting from a regulatory ruling to refund $1.9 million to our customers in our Colorado service area.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased 3.9 percent to $343.2 million for the year ended September 30, 2004 from $330.3 million for the year ended September 30, 2003. Operation and maintenance expense increased, primarily due to the addition of $6.1 million related to the MVG acquisition in December 2002 and higher labor and benefit costs. Taxes other than income taxes increased $1.5 million, primarily due to additional franchise, payroll and property taxes associated with the MVG assets acquired in December 2002. Franchise and state gross receipts taxes are paid by our customers as a component of their monthly bills; thus, these amounts are offset in revenues through customer billings and have no effect on net income. Depreciation and amortization expense increased $9.1 million, which primarily reflects MVG depreciation for the full year of fiscal 2004 compared with ten months in the prior year. These increases were partially offset by a $7.9 million reduction in our provision for doubtful accounts attributable to continued improvement in accounts receivable collections during fiscal 2004.

As a result of the aforementioned factors, our utility segment operating income for the year ended September 30, 2004 decreased to $159.9 million from $161.1 million for the year ended September 30, 2003.


	Miscellaneous income (expense)

Miscellaneous income for the year ended September 30, 2004 was $5.8 million, compared with expense of $0.2 million for the year ended September 30, 2003. The $6.0 million change was attributable primarily to the absence in 2004 of weather insurance amortization totaling $5.0 million, which was recognized in the prior year due to the termination of our weather insurance policy in the third quarter of fiscal 2003 and the recognition of a $0.8 million gain on the sale of real property during fiscal 2004.


	Interest charges

Interest charges increased 3.5 percent for the year ended September 30, 2004 to $65.4 million from $63.2 million for the year ended September 30, 2003. The increase was attributable primarily to a higher average outstanding debt balance resulting from the financing obtained to fund the acquisition of MVG in December 2002.


	*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, 2004 and 2003:


		Year Ended
		September 30

		2004			2003

		(In thousands, except
		storage balances)
Storage Activities
	Realized margin	$	(1,900	)	$	(7,250	)
	Unrealized margin		357			5,362

Total Storage Activities			(1,543	)		(1,888	)
Marketing Activities
	Realized margin		51,347			25,077
	Unrealized margin		(3,173	)		976

Total Marketing Activities			48,174			26,053

Gross profit		$	46,631		$	24,165

Ending storage balance (Bcf)			5.5			5.7

Our natural gas marketing segment’s gross profit was $46.6 million for the year ended September 30, 2004 compared to gross profit margin of $24.2 million for the year ended September 30, 2003. Natural gas marketing sales volumes were 265.1 Bcf during the current year compared with 294.8 Bcf for the prior year. Excluding intercompany sales volumes, natural gas marketing sales volumes were 222.6 Bcf during the current year compared with 226.0 Bcf in the prior year. The decrease in consolidated natural gas marketing sales volumes was primarily due to overall warmer temperatures during the 2003-2004 heating season compared with the prior year. Our natural gas marketing gross profit margin for the year ended September 30, 2004 included an unrealized loss on open contracts of $2.8 million compared with an unrealized gain on open contracts of $6.3 million in the prior year.

The contribution to gross profit from our storage activities was a loss of $1.5 million for the year ended September 30, 2004 compared to a loss of $1.9 million for the year ended September 30, 2003. The $0.4 million improvement primarily was attributable to a $5.4 million improvement in the realized storage contribution for the year ended September 30, 2004 compared to the prior year offset by a $5.0 million decrease in unrealized income associated with our storage portfolio compared to the prior year. The improvement in the realized storage contribution for the year ended September 30, 2004 primarily was due to

our inability during the 2002-2003 heating season to withdraw planned volumes from storage to meet our customer requirements caused by operational, contractual and regulatory limitations relating to our storage facilities, which reduced our realized storage contributions during fiscal 2003. This situation did not recur in fiscal 2004. The decrease in unrealized income in the current year was primarily attributable to a less favorable movement during the year ended September 30, 2004 in the forward indices used to value the storage financial instruments than in the prior year combined with slightly lower physical natural gas storage quantities at September 30, 2004 compared to the prior year.

Our marketing activities contributed $48.2 million to our gross profit margin for the year ended September 30, 2004 compared to $26.1 million for the year ended September 30, 2003. The increase in the marketing contribution primarily was attributable to our continued efforts to amend contracts with third parties to transfer risk to our customers and to provide higher gross profit margins and improved position management during the current year.

The improved gross profit margin resulted in an increase in our natural gas marketing segment operating income to $27.7 million for the year ended September 30, 2004 compared with operating income of $13.6 million for the year ended September 30, 2003.


	Miscellaneous income

Miscellaneous income for the year ended September 30, 2004 was $0.8 million, compared with income of $1.9 million for the year ended September 30, 2003. The $1.1 million decrease was attributable primarily to lower interest income earned on cash held on deposit in margin accounts due to favorable valuations on our financial derivatives, which reduced the need to deposit cash into margin accounts.


	*Pipeline and storage segment*


	Operating income

Our pipeline and storage operating income decreased to $5.3 million for the year ended September 30, 2004 from $11.8 million for the year ended September 30, 2003. The decrease in our pipeline and storage operating income was primarily attributable to a decrease in demand charges recognized by Atmos Pipeline and Storage, L.L.C. for storage services provided during the year ended September 30, 2004 compared to the prior year and lower transported volumes of approximately 2.3 Bcf by APS due to overall warmer weather during the winter heating season. The decrease was also attributable to a $1.5 million decrease in monthly facilities fees charged by Trans Louisiana Gas Pipeline, Inc. as a result of a settlement reached with the Louisiana Public Service Commission in October 2003. Our pipeline and storage operating income for the year ended September 30, 2004 also included an unrealized loss on open contracts of $1.1 million compared with no unrealized gain our loss in the prior year as APS started to hedge its storage inventory during the fourth quarter of 2004.


	*Other nonutility segment*


	Operating income

Our other nonutility operating income decreased to $0.8 million for the year ended September 30, 2004 from $1.3 million for the year ended September 30, 2003. The decrease in our other nonutility operating income was attributable primarily to a one-time charge of $0.4 million associated with the wind-down of a noncore business.


	Miscellaneous income

Miscellaneous income for the year ended September 30, 2004 was $8.3 million, compared with income of $6.5 million for the year ended September 30, 2003. The $1.8 million increase was attributable primarily to a $5.9 million pretax gain associated with the sale in January 2004 of our general and limited partnership interests in USP and the sale in June 2004 of the remaining limited partnership units in Heritage Propane Partners, L.P. formerly owned by USP. This increase was offset partially by lower equity earnings from our investment in USP resulting from the sale and the absence in 2004 of a $3.9 million gain recorded in 2003 associated with a sales-type lease of a distributed electric generation plant.

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 2006. However, during fiscal 2006, we anticipate that higher natural gas prices primarily resulting from the recent natural disasters will increase our need to utilize our short-term credit facilities to temporarily finance the purchase of natural gas to fulfill our contractual obligations. 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, 2005 and 2004:


	September 30

	2005				2004

	(In thousands, except percentages)
Short-term debt	$	144,809	3.7	%	$	—	—
Long-term debt		2,186,368	55.6	%		867,219	43.3	%
Shareholders’ equity		1,602,422	40.7	%		1,133,459	56.7	%

Total capitalization, including short-term debt	$	3,933,599	100.0	%	$	2,000,678	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 59.3 percent and 43.3 percent at September 30, 2005 and 2004. The increase in the debt to capitalization ratio was attributable to the issuance of $1.39 billion in senior unsecured long-term debt, partially offset by the issuance of 16.1 million shares of our common stock in October 2004 to partially finance the TXU Gas acquisition. 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 from the closing of the TXU Gas acquisition, 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, access to the equity capital markets and reduced annual maintenance and capital expenditures.

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 products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.


	*Cash flows from operating activities*

Year-over-year changes in our operating cash flows are attributable primarily 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, 2005, we generated operating cash flow of $386.9 million compared with $270.7 million in fiscal 2004 and $49.5 million in fiscal 2003. The significant factors impacting our operating cash flow for the last three fiscal years are summarized below.


	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.


	Year ended September 30, 2003

Fiscal 2003 operating cash flow was adversely impacted by a $60.0 million increase in accounts receivable due to higher revenues and the timing of customer account collections. The increase in revenues was attributable to a 19 percent increase in consolidated utility throughput as a result of the impact of our MVG acquisition. Operating cash flow was also adversely impacted by a significant increase in natural gas prices. These increases resulted in a $64.9 million increase in gas stored underground and a $24.2 million increase in deferred gas costs. Finally, operating cash flow reflects the impact of the funding of our pension plan in June 2003, which included a $48.6 million cash payment.


	*Cash flows from investing activities*

During the last three years, a substantial portion of our cash resources was used to fund acquisitions, our ongoing construction program to provide natural gas services to our customer base, enhance the integrity of our pipelines and improvements to information systems.

For the year ended September 30, 2005, we incurred $333.2 million for capital expenditures compared with $190.3 million for the year ended September 30, 2004 and $159.4 million for the year ended September 30, 2003. Capital expenditures for the year ended September 30, 2005 include approximately $115.0 million for the Atmos Energy Mid-Tex Division and $31.4 million for the Atmos Pipeline — Texas Division.

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 reflect 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, 2005, our financing activities provided $1.7 billion in cash compared with $80.4 million and $151.6 million provided for the years ended September 30, 2004 and 2003. Our significant financing activities for the years ended September 30, 2005, 2004 and 2003 are summarized as follows:


	•	In October 2004, we sold 16.1 million common shares, including the underwriters’ exercise of their overallotment option of 2.1 million shares, under a new registration statement declared effective in September 2004, generating net proceeds of $381.6 million. Additionally, we issued senior unsecured debt under the registration statement consisting of $400 million of 4.00% senior notes due 2009, $500 million of 4.95% senior notes due 2014, $200 million of 5.95% senior notes due 2034 and $300 million of floating rate senior notes due 2007. The floating rate notes bear interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. The net proceeds received from the sale of these senior notes were $1.39 billion. The net proceeds from these issuances, combined with the net proceeds from our July 2004 offering were used to repay the approximately $1.7 billion in outstanding commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition.

	•	During the year ended September 30, 2005 we borrowed a net $144.8 million under our short-term facilities whereas during the year ended September 30, 2004 and 2003, we repaid a net $118.6 million and $27.2 million under our short-term facilities. Borrowings under our short-term facilities during fiscal 2005 reflect the impact of seasonal natural gas purchases and the effect of higher natural gas prices than in prior years. Prior year repayments under our short-term facilities reflected the timing of cash receipts which enabled us to reduce our short-term debt.

	•	We repaid $103.4 million of long-term debt during the year ended September 30, 2005 compared with $9.7 million during the year ended September 30, 2004 and $73.2 million during the year ended September 30, 2003. 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 $1.3 million in fiscal 2005 and should result in interest savings of $4.8 million in fiscal 2006.

	•	During the year ended September 30, 2005 we paid $99.0 million in cash dividends compared with dividend payments of $66.7 million and $55.3 million for the years ended September 30, 2004 and 2003. The increase in dividends paid over the prior year reflects the 17.7 million increase in the number of common shares outstanding and an increase in the dividend rate from $1.22 per share during the year ended September 30, 2004 to $1.24 per share during the year ended September 30, 2005.

During the year ended September 30, 2005 we issued 1.6 million shares of common stock through various plans in addition to the 16.1 million common shares issued in our October 2004 public offering, which generated net proceeds of $37.2 million. The following table shows the number of shares issued for the years ended September 30, 2005, 2004 and 2003:


			For the Year Ended September 30

			2005		2004		2003

Shares issued:
	Direct stock purchase plan			450,212		556,856		585,743
	Retirement savings plan			441,350		320,313		360,725
	Long-term incentive plan			745,788		498,230		181,429
	Long-term stock plan for Mid-States Division			—		6,000		13,000
	Outside directors stock-for-fee plan			2,341		3,133		2,969
	October 2004 Offering			16,100,000		—		—
	July 2004 Offering			—		9,939,393		—
	Acquisition of MVG			—		—		3,386,287
	Pension account plan funding			—		—		1,169,700
	2003 Offering			—		—		4,100,000

		Total shares issued		17,739,691		11,323,925		9,799,853

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 on January 30, 2002. On January 16, 2003, we issued $250.0 million of 5.125% Senior Notes due in 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and for general corporate purposes. Additionally, we sold 4.1 million shares of our common stock in connection with our 2003 Offering under the registration statement to provide additional funding for our Pension Account Plan. 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 on September 15, 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 the new registration statement, generating net proceeds of $382.5 million before other offering costs. Additionally, we issued senior unsecured debt under the registration statement consisting of $400 million of 4.00% Senior Notes due 2009, $500 million of 4.95% Senior Notes due 2014, $200 million of 5.95% Senior Notes due 2034 and $300 million of floating rate Senior Notes due 2007. The floating rate notes bear interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. The initial weighted average effective interest rate on these notes was 4.76 percent. The net proceeds from the sale of these senior notes were $1.39 billion.

The net proceeds from the October 2004 common stock and senior notes offerings, combined with the net proceeds from our July 2004 offering were used to pay off the $1.7 billion in outstanding commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. After issuing the debt and equity in October 2004 we have approximately $401.5 million of availability remaining under this registration statement.

Credit Facilities

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on a when-and-as-needed basis at the discretion of the bank. 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 and capital expenditures have increased substantially as a result of the acquisition of the natural gas distribution and pipeline operations of TXU Gas. On October 22, 2004, we replaced our $350.0 million credit facility with a new $600.0 million committed credit facility that serves as a backup liquidity facility for our commercial paper program. We believe this facility, combined with our operating cash flow will be sufficient to fund these increased working capital needs. On March 30, 2005, AEM amended and extended its uncommitted demand working capital credit facility to March 31, 2006. At September 30, 2005, there was $129.9 million outstanding under our commercial paper program and $14.9 million outstanding under our bank credit facilities. These facilities are described in further detail in Note 6 to the consolidated financial statements.

In anticipation of increased short-term liquidity needs due to the recent increases in natural gas prices, we worked with our regulators, who approved an increase in the amounts available to our utility operations under short-term credit facilities to $968.0 million, consisting of a new $600.0 million 3-year revolving credit facility to replace our existing $600.0 million 364-day credit facility that expired in October 2005, a new $300.0 million 364-day revolving credit facility, a new $25.0 million uncommitted facility and our existing $25.0 million uncommitted and $18.0 million committed credit facilities. Additionally, we are working with our lenders to obtain up to an additional $330.0 million of capacity under our uncommitted demand working capital credit facility to provide additional short-term liquidity to support our natural gas marketing operations.

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, Moody’s Investors Service and Fitch Ratings, Inc. 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, S&P and Moody’s maintain a stable outlook and Fitch maintains a negative outlook. None of our ratings are currently under review.

A credit rating is not a recommendation to buy, sell or hold securities. All of our current ratings for long-term debt are categorized as investment grade. 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 are required by the financial covenants in both of our revolving credit facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2005, our total-debt-to-total-capitalization ratio, as defined in such facility, was 61 percent.

AEM is required by the financial covenants in its uncommitted demand working capital facility to maintain a maximum ratio of total liabilities to tangible net worth of 5 to 1, along with minimum levels of net working capital ranging from $20 million to $50 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $51 million, and its maximum cumulative loss from March 30, 2005 cannot exceed $4 million to $10 million, depending on the total amount of borrowing elected from time to time by AEM. At September 30, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined in such facility, was 2.18 to 1.

Our Series P First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1985 may not exceed the sum of our accumulated net income for periods after December 31, 1985 plus $9.0 million. At September 30, 2005, approximately $157.9 million of retained earnings was unrestricted with respect to the payment of dividends.

We were in compliance with all of our debt covenants as of September 30, 2005. 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 our two 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.

Contractual Obligations and Commercial Commitments

The following tables provide information about contractual obligations and commercial commitments at September 30, 2005.


		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⁾		$	2,190,142	$	3,264	$	307,017	$	403,415	$	1,476,446
Short-term debt⁽¹⁾			144,809		144,809		—		—		—
Interest charges			1,155,103		118,488		222,554		191,500		622,561
Gas purchase commitments⁽²⁾			1,275,427		890,856		319,141		25,491		39,939
Capital lease obligations⁽³⁾			3,404		631		795		602		1,376
Operating leases⁽³⁾			163,434		15,327		29,461		26,193		92,453
Demand fees for contracted storage⁽⁴⁾			15,037		7,440		6,218		1,068		311
Derivative obligations⁽⁵⁾			77,236		61,920		15,316		—		—
Postretirement benefit plan contributions⁽⁶⁾			164,455		14,896		24,477		29,162		95,920

	Total contractual obligations	$	5,189,047	$	1,257,631	$	924,979	$	677,431	$	2,329,006


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

⁽²⁾	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, 2005.

⁽³⁾	See Note 14 to the consolidated financial statements.

⁽⁴⁾	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.

⁽⁵⁾	Represents liabilities for natural gas commodity derivative contracts that were valued as of September 30, 2005. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk.

⁽⁶⁾	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, 2005, AEM was committed to purchase 32.3 Bcf within one year, 29.2 Bcf between one to three years and 9.9 Bcf after three years under indexed contracts. AEM was committed to purchase 1.3 Bcf within one year and 0.4 Bcf within one to three years under fixed price contracts with prices ranging from $5.24 to $17.50.

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, 2005 are reflected in the table above.

In January 2005, we signed a letter of intent with a third party to jointly construct, own and operate a 45-mile large diameter natural gas pipeline in the northern portion of the Dallas/ Fort Worth Metroplex. Under terms of the letter of intent, the third party will provide the initial capital to build the pipeline and we expect to contribute $45.0 million within two years of signing a definitive agreement. We expect to execute

this agreement during the first quarter of fiscal 2006 and the pipeline is currently expected to be placed into service in fiscal 2006. Additionally, during the third quarter of 2005, we entered into two agreements with third parties to transport natural gas through our Texas intrastate pipeline system beginning in fiscal 2006. To handle the increased volumes for these projects, we will install compression equipment and other pipeline infrastructure. We expect to spend approximately $32.0 million in 2006 for these projects.

Risk Management 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 partially insulate us and our customers against gas price volatility during the winter heating season. 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. 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 will be 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, will be 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, 2005 (in thousands):


					Natural Gas
		Utility			Marketing

Fair value of contracts at September 30, 2004		$	(8,612	)	$	13,018
	Contracts realized/settled		(43,233	)		(24,589	)
	Fair value of new contracts		(18,998	)		—
	Other changes in value		164,153			(50,327	)

Fair value of contracts at September 30, 2005		$	93,310		$	(61,898	)

The fair value of our utility and natural gas marketing derivative contracts at September 30, 2005, is segregated below by time period and fair value source.


	Fair Value of Contracts at September 30, 2005

	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	$	44,039		$	(14,795	)	$	—	$	—	$	29,244
Prices provided by other external sources		2,021			723			—		—		2,744
Prices based on models and other valuation methods		(67	)		(509	)		—		—		(576	)

Total Fair Value	$	45,993		$	(14,581	)	$	—	$	—	$	31,412


	*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 gross profit margins. 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 monthly using the iFERC price at the end of each month with changes in fair value recognized as unrealized gains and losses in the period of change. 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 (iFERC) and the related fair-value hedge (NYMEX) is 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 forecasted gross profit margin that it captured through the purchase and sale of physical natural gas and the associated financial derivatives. The forecasted gross profit margin, less the effect of unrealized gains or losses recognized in the financial statements, provides a measure of the net increase or decrease in the gross profit margin that could occur in future periods if AEM’s optimization efforts are fully successful.

As of September 30, 2005, based upon AEM’s derivatives position and inventory withdrawal schedule, the forecasted gross profit margin was approximately $13.0 million. Approximately $14.8 million of net unrealized losses were recorded in the financial statements as of September 30, 2005. Therefore, the projected increase in future gross profit margin is approximately $27.8 million.

The forecasted gross profit margin calculation is based upon planned injection and withdrawal schedules, and the realization of the forecasted gross profit margin 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 forecasted gross profit margin or the projected increase in future gross profit margin calculated as of September 30, 2005 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, permanent impacts on earnings may result.

Pension and Postretirement Benefits Obligations


	*Net Periodic Pension and Postretirement Benefit Costs*

For the fiscal year ended September 30, 2005, our total net periodic pension and other benefits costs was $36.4 million, compared with $26.1 million and $28.0 million for the years ended September 30, 2004 and 2003. A portion of these costs is capitalized into our utility rate base, as these costs are recoverable through our gas utility rates. Costs that are not capitalized are recorded as a component of operation and maintenance expense.

The increase in total net periodic pension and other benefits cost during fiscal 2005 compared with the prior year 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 approximates 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.

The decrease in total net periodic pension and other benefits cost during fiscal 2004 compared with fiscal 2003 primarily reflects the impact of adopting the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), beginning with the second quarter of 2004, which reduced our accumulated postretirement benefit obligation by $24.3 million and our net postretirement benefit obligation costs by $4.1 million. The total income statement impact was $2.3 million as a portion of this benefit was capitalized.

Further, the expected return on plan assets, which reduces our net pension and postretirement costs, increased as compared with the prior year primarily due to an increase in total assets attributable to the full year effect of the contributions we made to the Atmos Pension Account Plan in fiscal 2003 and the inclusion of the MVG pension plan assets during fiscal 2003 partially offset by a 25 basis point decrease in the expected return on plan asset assumption used to determine fiscal 2004 net periodic pension cost.

These decreases were partially offset by an increase in the service cost and the recognized actuarial loss attributable to a 125 basis point decrease in the discount rate used to determine our fiscal 2004 net periodic pension and other benefits costs compared with the discount rate used to determine our fiscal 2003 costs, resulting from a decrease in interest rates in the period leading up to our June 30 measurement date.


	*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 2005, we voluntarily contributed $3.0 million to the Atmos Energy Corporation Master Retirement Trust (the Trust) to maintain the level of funding we desire relative to our accumulated benefit obligation. We elected to contribute to the Trust 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. In June 2003, we contributed to the Trust for the benefit of the Atmos Energy Corporation Pension Account Plan $48.6 million in cash and 1,169,700 shares of Atmos restricted common stock with the-then market value of $28.8 million. We did not contribute to our pension plans during fiscal 2004.

We contributed $10.0 million, $13.8 million and $18.6 million to our postretirement benefits plans for the years ended September 30, 2005, 2004 and 2003. 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 2006*

As noted above, high grade corporate bond yields were decreasing in the period leading up to our June 30, 2005 measurement date. Therefore, we reduced the discount rate for determining our fiscal 2006 pension and benefit costs by 125 basis points to 5 percent. Additionally, we reduced the expected return on our pension plan assets by 25 basis points to 8.5 percent. The effect of these assumption changes, coupled with the effects of updating our annual valuation will result in an increase in our net pension and postretirement costs of approximately $15 million.

We are not required to make a minimum funding contribution to our pension plans during fiscal 2006 nor, at this time, do we intend to make voluntary contributions during 2006. However, we anticipate contributing approximately $11.9 million to our postretirement medical plans during fiscal 2006.

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.

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, 2005 three month market strip would increase our purchased gas cost by approximately $5.9 million in fiscal 2006.


	*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. Because AEH did not have any net open positions (including existing storage and related financial contracts) at September 30, 2005, there would be no impact on our consolidated net income due to fluctuations in the forward NYMEX price.

However, changes in the difference between the indices used to mark to market our physical inventory (iFERC) and the related fair-value hedge (NYMEX) can result in volatility in our reported net income; however, 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 storage position at September 30, 2005 of 7.4 Bcf, a $0.50 change in the difference between the iFERC and NYMEX indices could impact our reported net income by approximately $2.3 million.

Interest Rate Risk

Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program, other short-term borrowings and floating rate debt. 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 of a one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings outstanding during fiscal 2005 increased by an average of one percent, our interest expense would have increased by approximately $0.4 million during 2005.

We also assess market risk for our fixed-rate, long-term obligations. We estimate market risk for our fixed-rate, 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 fixed-rate, long-term obligations outstanding as of September 30, 2005 would have increased by approximately $160.2 million.

As of September 30, 2005, we were not engaged in any other activities which 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			62
Financial statements and supplementary data:
	Consolidated balance sheets at September 30, 2005 and 2004		63
	Consolidated statements of income for the years ended September 30, 2005, 2004 and 2003		64
	Consolidated statements of shareholders’ equity for the years ended September 30, 2005, 2004 and 2003		65
	Consolidated statements of cash flows for the years ended September 30, 2005, 2004 and 2003		66
	Notes to consolidated financial statements		67
	Selected Quarterly Financial Data (Unaudited)		121
Financial statement schedule for the years ended September 30, 2005, 2004 and 2003
	Schedule II. Valuation and Qualifying Accounts		129

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, 2005 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2005. 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, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended September 30, 2005, 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, 2005, 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 16, 2005 expressed an unqualified opinion thereon.


	ERNST & YOUNG LLP

Dallas, Texas

November 16, 2005

ATMOS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


			September 30

			2005			2004

			(In thousands,
			except share data)
ASSETS
Property, plant and equipment			$	4,631,684		$	2,595,374
Construction in progress				133,926			38,277

				4,765,610			2,633,651
Less accumulated depreciation and amortization				1,391,243			911,130

	Net property, plant and equipment			3,374,367			1,722,521
Current assets
	Cash and cash equivalents			40,116			201,932
	Cash held on deposit in margin account			80,956			—
	Accounts receivable, less allowance for doubtful accounts of $15,613 in 2005 and $7,214 in 2004			454,313			211,810
	Gas stored underground			450,807			200,134
	Other current assets			238,238			99,319

		Total current assets		1,264,430			713,195
Goodwill and intangible assets				737,787			245,528
Deferred charges and other assets				276,943			231,383

			$	5,653,527		$	2,912,627

CAPITALIZATION AND LIABILITIES
Shareholders’ equity
	Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2005 — 80,539,401 shares, 2004 — 62,799,710 shares		$	403		$	314
	Additional paid-in capital			1,426,523			1,005,644
	Accumulated other comprehensive loss			(3,341	)		(14,529	)
	Retained earnings			178,837			142,030

		Shareholders’ equity		1,602,422			1,133,459
Long-term debt				2,183,104			861,311

		Total capitalization		3,785,526			1,994,770
Commitments and contingencies
Current liabilities
	Accounts payable and accrued liabilities			461,314			185,295
	Other current liabilities			503,368			238,682
	Short-term debt			144,809			—
	Current maturities of long-term debt			3,264			5,908

		Total current liabilities		1,112,755			429,885
Deferred income taxes				292,207			241,257
Regulatory cost of removal obligation				263,424			103,579
Deferred credits and other liabilities				199,615			143,136

			$	5,653,527		$	2,912,627

See accompanying notes to consolidated financial statements

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


			Year Ended September 30

			2005			2004			2003

			(In thousands, except per share data)
Operating revenues
	Utility segment		$	3,103,140		$	1,637,728		$	1,554,082
	Natural gas marketing segment			2,106,278			1,618,602			1,668,493
	Pipeline and storage segment			164,742			19,758			20,298
	Other nonutility segment			5,302			3,393			2,853
	Intersegment eliminations			(406,136	)		(359,444	)		(445,810	)

				4,973,326			2,920,037			2,799,916
Purchased gas cost
	Utility segment			2,195,774			1,134,594			1,062,679
	Natural gas marketing segment			2,044,305			1,571,971			1,644,328
	Pipeline and storage segment			6,811			9,383			3,061
	Other nonutility segment			—			—			—
	Intersegment eliminations			(402,654	)		(358,102	)		(445,128	)

				3,844,236			2,357,846			2,264,940

Gross profit				1,129,090			562,191			534,976
Operating expenses
	Operation and maintenance			427,734			214,470			205,090
	Depreciation and amortization			178,005			96,647			87,001
	Taxes, other than income			174,696			57,379			55,045

		Total operating expenses		780,435			368,496			347,136

Operating income				348,655			193,695			187,840
Miscellaneous income				2,021			9,507			2,191
Interest charges				132,658			65,437			63,660

Income before income taxes and cumulative effect of accounting change				218,018			137,765			126,371
Income tax expense				82,233			51,538			46,910

Income before cumulative effect of accounting change				135,785			86,227			79,461
Cumulative effect of accounting change, net of income tax benefit				—			—			(7,773	)

		Net income	$	135,785		$	86,227		$	71,688

Per share data
	Basic income per share:
		Income before cumulative effect of accounting change	$	1.73		$	1.60		$	1.72
		Cumulative effect of accounting change, net of income tax benefit		—			—			(.17	)

		Net income	$	1.73		$	1.60		$	1.55

	Diluted income per share:
		Income before cumulative effect of accounting change	$	1.72		$	1.58		$	1.71
		Cumulative effect of accounting change, net of income tax benefit		—			—			(.17	)

		Net income	$	1.72		$	1.58		$	1.54

Weighted average shares outstanding:
	Basic			78,508			54,021			46,319

	Diluted			79,012			54,416			46,496

See accompanying notes to consolidated financial statements

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY


			Common Stock						Accumulated
							Additional		Other
			Number of		Stated		Paid-in		Comprehensive			Retained
			Shares		Value		Capital		Loss			Earnings			Total

			(In thousands, except share data)
Balance, September 30, 2002				41,675,932	$	208	$	508,265	$	(41,380	)	$	106,142		$	573,235
Comprehensive income:
	Net income			—		—		—		—			71,688			71,688
	Minimum pension liability, net			—		—		—		39,432			—			39,432
	Unrealized holding gains on investments, net			—		—		—		489			—			489

		Total comprehensive income														111,609
Cash dividends ($1.20 per share)				—		—		—		—			(55,291	)		(55,291	)
Common stock issued:
	Public offering			4,100,000		20		99,102		—			—			99,122
	Acquisition of Mississippi Valley Gas Company			3,386,287		17		74,633		—			—			74,650
	Contribution to Atmos Pension Account Plan			1,169,700		6		28,757		—			—			28,763
	Direct stock purchase plan			585,743		3		13,209		—			—			13,212
	Retirement savings plan			360,725		2		8,277		—			—			8,279
	Long-term incentive plan			181,429		1		3,664		—			—			3,665
	Long-term stock plan for Mid-States Division			13,000		—		206		—			—			206
	Outside directors stock-for-fee plan			2,969		—		67		—			—			67

Balance, September 30, 2003				51,475,785		257		736,180		(1,459	)		122,539			857,517
Comprehensive income:
	Net income			—		—		—		—			86,227			86,227
	Unrealized holding gains on investments, net			—		—		—		615			—			615
	Treasury lock agreements, net			—		—		—		(21,268	)		—			(21,268	)
	Cash flow hedges, net			—		—		—		7,583			—			7,583

		Total comprehensive income														73,157
Cash dividends ($1.22 per share)				—		—		—		—			(66,736	)		(66,736	)
Common stock issued:
	Public offering			9,939,393		50		235,419		—			—			235,469
	Direct stock purchase plan			556,856		3		13,726		—			—			13,729
	Retirement savings plan			320,313		2		8,300		—			—			8,302
	Long-term incentive plan			498,230		2		11,848		—			—			11,850
	Long-term stock plan for Mid-States Division			6,000		—		94		—			—			94
	Outside directors stock-for-fee plan			3,133		—		77		—			—			77

Balance, September 30, 2004				62,799,710		314		1,005,644		(14,529	)		142,030			1,133,459
Comprehensive income:
	Net income			—		—		—		—			135,785			135,785
	Unrealized holding gains on investments, net			—		—		—		1,528			—			1,528
	Treasury lock agreements, net			—		—		—		(2,714	)		—			(2,714	)
	Cash flow hedges, net			—		—		—		12,374			—			12,374

		Total comprehensive income														146,973
Cash dividends ($1.24 per share)				—		—		—		—			(98,978	)		(98,978	)
Common stock issued:
	Public offering			16,100,000		80		381,271		—			—			381,351
	Direct stock purchase plan			450,212		3		12,486		—			—			12,489
	Retirement savings plan			441,350		2		11,767		—			—			11,769
	Long-term incentive plan			745,788		4		14,116		—			—			14,120
	Amortization of restricted stock			—		—		1,175		—			—			1,175
	Outside directors stock-for-fee plan			2,341		—		64		—			—			64

Balance, September 30, 2005				80,539,401	$	403	$	1,426,523	$	(3,341	)	$	178,837		$	1,602,422

See accompanying notes to consolidated financial statements

ATMOS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


				Year Ended September 30

				2005			2004			2003

				(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income			$	135,785		$	86,227		$	71,688
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect of accounting change, net of income tax benefit			—			—			7,773
		Gain on sales of assets			—			(6,700	)		—
		Depreciation and amortization:
			Charged to depreciation and amortization		178,005			96,647			87,001
			Charged to other accounts		791			1,465			2,193
		Deferred income taxes			12,669			36,997			53,867
		Other			11,522			(1,772	)		(5,885	)
	Changes in assets and liabilities:
		(Increase) decrease in cash held on deposit in margin account			(80,956	)		17,903			(7,711	)
		(Increase) decrease in accounts receivable			(166,692	)		2,158			(60,026	)
		Increase in gas stored underground			(112,796	)		(31,030	)		(64,875	)
		Increase in other current assets			(56,828	)		(9,233	)		(15,747	)
		Decrease in deferred charges and other assets			30,059			17,178			21,258
		Increase in accounts payable and accrued liabilities			224,375			4,586			19,417
		Increase (decrease) in other current liabilities			218,715			48,877			(40,636	)
		Increase (decrease) in deferred credits and other liabilities			(7,705	)		7,431			(18,866	)

			Net cash provided by operating activities		386,944			270,734			49,451
CASH FLOWS USED IN INVESTING ACTIVITIES
	Capital expenditures				(333,183	)		(190,285	)		(159,439	)
	Acquisitions, net of cash received				(1,916,696	)		(1,957	)		(74,650	)
	Proceeds from sales of assets				—			27,919			—
	Other, net				(2,131	)		(570	)		704

			Net cash used in investing activities		(2,252,010	)		(164,893	)		(233,385	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Net increase (decrease) in short-term debt				144,809			(118,595	)		(27,196	)
	Net proceeds from issuance of long-term debt				1,385,847			5,000			253,267
	Settlement of Treasury lock agreements				(43,770	)		—			—
	Proceeds from bridge loan				—			—			147,000
	Repayment of bridge loan				—			—			(147,000	)
	Repayment of long-term debt				(103,425	)		(9,713	)		(73,165	)
	Repayment of Mississippi Valley Gas debt				—			—			(70,938	)
	Cash dividends paid				(98,978	)		(66,736	)		(55,291	)
	Issuance of common stock				37,183			34,715			25,720
	Net proceeds from equity offering				381,584			235,737			99,229

			Net cash provided by financing activities		1,703,250			80,408			151,626

Net increase (decrease) in cash and cash equivalents					(161,816	)		186,249			(32,308	)
Cash and cash equivalents at beginning of year					201,932			15,683			47,991

Cash and cash equivalents at end of year				$	40,116		$	201,932		$	15,683

See accompanying notes to consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Nature of Business

Atmos Energy Corporation (“Atmos” or “the Company”) and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. Through our natural gas utility business, we distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public-authority and industrial customers through our seven regulated natural gas utility divisions, in the service areas described below:


Division		Service Area

Atmos Energy Colorado-Kansas Division		Colorado, Kansas, Missouri⁽³⁾
Atmos Energy Kentucky Division		Kentucky
Atmos Energy Louisiana Division		Louisiana
Atmos Energy Mid-States Division		Georgia⁽³⁾, Illinois⁽³⁾, Iowa ⁽³⁾, Missouri⁽³⁾, Tennessee, Virginia⁽³⁾
Atmos Energy Mid-Tex Division⁽¹⁾		Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy Mississippi Division⁽²⁾		Mississippi
Atmos Energy West Texas Division		West Texas


⁽¹⁾	Acquired in October 2004.

⁽²⁾	The name of this division was changed from the Mississippi Valley Gas Company Division in April 2005.

⁽³⁾	Denotes locations where we have more limited service areas.

As further described in Note 3, on October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company. The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, storage, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. We also acquired a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs, all within Texas. As a result of the TXU Gas acquisition, on October 1, 2004, we created the Atmos Energy Mid-Tex Division, which provides gas distribution services to our approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also created the Atmos Pipeline — Texas Division to manage and operate the TXU Gas pipeline and storage operations we acquired.

In addition, we transport natural gas for others through our distribution system. Our utility business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which the utility divisions operate. Our shared-services division is located in Dallas, Texas, and our customer support centers are located in Amarillo, Texas, and Metairie, Louisiana. In addition, on April 1, 2005, we took over the operations of a Waco, Texas customer support center, and all call center services formerly provided by TXU Gas under a transitional services agreement were terminated. We closed the purchase of the related assets on October 3, 2005 for approximately $1.7 million.

Our nonutility businesses operate in 22 states and include our natural gas marketing operations, our pipeline and storage operations and our other nonutility operations. These operations are either organized under or managed by Atmos Energy Holdings, Inc., which is wholly-owned by the Company.

Our natural gas marketing operations are managed by Atmos Energy Marketing, LLC, which is wholly-owned by AEH. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas customers, primarily in the southeastern and midwestern states and to our Kentucky, Louisiana and Mid-States divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of derivative instruments.

Our pipeline and storage operations consist of the operations of our Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and of Atmos Pipeline and Storage, LLC, which is wholly-owned by AEH. The Atmos Pipeline–Texas Division was purchased from TXU Gas and transports natural gas to the Atmos Energy Mid-Tex Division, transports natural gas to third parties and manages five underground storage reservoirs in Texas. Through APS, we own or have 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.

Our other nonutility businesses consist primarily of the operations of Atmos Energy Services, LLC and Atmos Power Systems, Inc., which are wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations, other than the Mid-Tex Division. These services, which began on April 1, 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. Through Atmos Power Systems, Inc., we construct gas-fired electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

Prior to January 20, 2004, United Cities Propane Gas, Inc., a wholly-owned subsidiary of AEH, owned an approximate 19 percent membership interest in U.S. Propane L.P., a joint venture formed in February 2000 with three other utility companies. Through our ownership in USP, we owned an approximate 5 percent indirect interest in Heritage Propane Partners, L.P. During 2004, we sold our interest in USP and Heritage. We received cash proceeds of $26.6 million and recorded a pretax book gain of $5.9 million with these transactions. We no longer have an interest in the propane industry.


2.	Summary of Significant Accounting Policies

Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated.

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

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes, risk management and trading activities and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results could differ from those estimates.

We record regulatory assets as a component of deferred charges and other assets for costs that have been deferred for which future recovery through customer rates is considered probable. Regulatory liabilities are

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recorded either on the face of the balance sheet or as a component of current liabilities, deferred income taxes or deferred credits and other liabilities when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Significant regulatory assets and liabilities as of September 30, 2005 and 2004 included the following:


		September 30

		2005		2004

		(In thousands)
Regulatory assets:
	UCG merger and integration costs, net⁽¹⁾	$	—	$	1,992
	Other merger and integration costs, net		9,150		9,442
	Deferred gas costs		38,173		8,756
	Deferred MVG operating expenses		—		4,801
	Environmental costs		1,357		3,104
	Rate case costs		11,314		537
	Deferred franchise fees		6,710		—
	Other		9,313		7,353

		$	76,017	$	35,985

Regulatory liabilities:
	Deferred gas costs	$	134,048	$	54,514
	Regulatory cost of removal obligation		274,989		111,232
	Deferred income taxes, net		3,185		1,962
	Other		8,084		5,479

		$	420,306	$	173,187


⁽¹⁾	Fully amortized as of December 2004.

Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. During the fiscal years ended September 30, 2005, 2004 and 2003, we recognized $2.3 million, $8.2 million and $8.2 million in amortization expense related to these costs. Environmental costs have been deferred to future rate filings in accordance with rulings received from various regulatory commissions.

During the third quarter of 2005, the Mid-States Division filed a rate case in its Georgia service area seeking a rate increase of $4.0 million. We anticipate that the rate case will be finalized in November 2005. During 2005, our Mid-Tex, West Texas and Atmos Pipeline — Texas divisions made GRIP filings to include $94.6 million of capital expenditures in their rate base which should result in additional revenue of approximately $19.1 million. Rulings on these filings are anticipated by January 4, 2006.

In September 2004, the Mississippi Public Service Commission authorized additional annualized revenue of $4.7 million on our Mississippi Division’s May 2004 filing, which became effective on June 1, 2004. However, the MPSC originally disallowed certain deferred costs totaling $2.8 million. In connection with the modification of our rate design, the MPSC reversed its decision regarding these costs, and we included these costs into our rates in October 2005.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Revenue is recognized in our pipeline and storage segment as the services are provided.

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.

Cash and cash equivalents — We consider all highly liquid investments with an initial or remaining maturity of three months or less to be cash equivalents.

Accounts receivable and allowance for doubtful accounts — Accounts receivable consist of natural gas sales to residential, commercial, industrial, municipal, agricultural and other customers. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collections experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our utility operations and natural gas held by our natural gas marketing and other nonutility subsidiaries to conduct their operations. The average cost method is used for all our utility divisions, except for the Mid-States Division, where it is valued on the first-in first-out method basis, in accordance with regulatory requirements. The average gas cost method is also used for our natural gas marketing segment and our Atmos Pipeline — Texas Division. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.

Utility property, plant and equipment — Utility property, plant and equipment is stated at original cost net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

ratemaking purposes when the completed projects are placed in service. Interest expense of $2.5 million, $1.2 million and $0.8 million was capitalized in 2005, 2004 and 2003.

Major renewals, including replacement pipe, and betterments that are recoverable under our regulatory rate base are capitalized while the costs of maintenance and repairs that are not recoverable through rates are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the utility plant in service account included in the rate base and depreciation begins.

Utility property, plant and equipment is depreciated at various rates on a straight-line basis over the estimated useful lives of the assets. These rates are approved by our regulatory commissions and are comprised of two components, one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 4.0 percent for the year ended September 30, 2005 and 3.8 percent for the years ended September 30, 2004 and 2003.

Nonutility property, plant and equipment — Nonutility property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from 8 to 38 years.

Asset retirement obligations — SFAS 143, Accounting for Asset Retirement Obligations requires that we record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense. As of September 30, 2005 and 2004, we have asset retirement obligations as defined under SFAS 143; however, we cannot determine when the legal obligation will be incurred. Accordingly, we have not recorded a liability for these obligations.

Impairment of long-lived assets — We periodically evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. To date, no impairment has been recognized.

Goodwill and intangible assets — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.

Intangible assets are amortized over their useful lives of 10 years. These assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. To date, no impairment has been recognized.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Marketable securities — As of September 30, 2005 and 2004, all of our marketable securities were classified as available-for-sale securities based upon the criteria of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities. In accordance with that standard, these securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value.

Derivatives and hedging activities — Our derivative and hedging activities are tailored to the segment to which they relate. 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. These assets and liabilities are recorded as components of other current assets, deferred charges and other assets, other current liabilities or deferred credits and other liabilities depending on the expiration or maturity date of the instrument.


	*Utility Segment*

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, maturity and settlement of contracts and newly originated transactions. However, because the gains or losses 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 gain or loss is recovered through our rates.


	*Natural Gas Marketing Segment*

Our natural gas marketing risk management activities are conducted through AEM. AEM is exposed to risks associated with changes in the market price of natural gas, and we manage our exposure to the risk of natural gas price changes 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.

Under SFAS 133, natural gas inventory is designated as the hedged item in a fair-value hedge and is marked to market on a monthly basis using the iFERC price at the end of each month. Changes in fair value

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

are recognized as unrealized gains and losses in revenue in the period of change. 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.

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 1, 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 are realized as a component of revenue in the period in which we fulfill the requirements of the fixed-price contract and the derivatives are 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 are 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 1, 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 have 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 are now 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 revenues and is not material to our financial position, results of operations or cash flows. In addition, we continually manage our positions to optimize value as market conditions and other circumstances change.


	*Treasury Activities*

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, to the extent effective, unrealized gains and losses associated with the Treasury lock agreements are 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. Approximately $11.6 million of the $43.8 million obligation will be 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, will be recognized as a component of interest expense over a ten year period from the date of settlement.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 present market conditions.

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 expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of the annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making 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 cost based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.

Income taxes — Income taxes are provided based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on current and accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.

Stock-based compensation plans — We have two stock-based compensation plans that provide for the granting of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to officers and key employees: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for the Mid-States Division. Nonemployee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock. These plans are

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

more fully described in Note 8. As permitted by SFAS 123, Accounting for Stock-Based Compensation, we accounted for these plans under the intrinsic-value method described in Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees through September 30, 2005. Under this method, no compensation cost for stock options is recognized for stock-option awards granted at or above fair-market value.

Awards of restricted stock are valued at the market price of the Company’s common stock on the date of grant. The unearned compensation is amortized to operation and maintenance expense over the vesting period of the restricted stock. As discussed below, beginning October 1, 2005 we will account for our stock-based compensation in accordance with SFAS 123 (revised), Share-Based Payment.

Had compensation expense for our stock options issued under the Long-Term Incentive Plan been recognized based on the fair value on the grant date under the methodology prescribed by SFAS 123, our net income and earnings per share for the years ended September 30, 2005, 2004 and 2003 would have been impacted as shown in the following table:


		Year Ended September 30

		2005			2004			2003

		(In thousands, except per share data)
Net income — as reported		$	135,785		$	86,227		$	71,688
Restricted stock compensation expense included in income, net of tax			2,431			978			370
Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of taxes			(3,161	)		(2,092	)		(1,362	)

Net income — pro forma		$	135,055		$	85,113		$	70,696

Earnings per share:
	Basic earnings per share — as reported	$	1.73		$	1.60		$	1.55

	Basic earnings per share — pro forma	$	1.72		$	1.57		$	1.53

	Diluted earnings per share — as reported	$	1.72		$	1.58		$	1.54

	Diluted earnings per share — pro forma	$	1.71		$	1.56		$	1.52

Accumulated other comprehensive loss — Accumulated other comprehensive loss, net of tax, as of September 30, 2005 and 2004 consisted of the following unrealized gains (losses):


	September 30

	2005			2004

	(In thousands)
Unrealized holding gains (losses) on investments	$	684		$	(844	)
Treasury lock agreements		(23,982	)		(21,268	)
Cash flow hedges		19,957			7,583

	$	(3,341	)	$	(14,529	)

Recent accounting pronouncements — During 2003, the Emerging Issues Task Force (EITF) added to its agenda EITF Issue 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, to address the meaning of “other-than-temporary” impairment and its application to certain investments carried at cost. In November 2003, the Task Force developed new disclosure requirements concerning unrealized losses on available-for-sale debt and equity securities accounted for under SFAS 115, Accounting for Certain Investments in Debt and Equity Securities. We have adopted the disclosure

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

requirements prescribed by EITF 03-01, which are contained in Note 9. In March 2004, the Task Force issued guidance regarding the measurement and recognition of an “other-than-temporary” impairment, which was subsequently delayed in September 2004. In June 2005, the Task Force decided not to provide additional guidance on the meaning of “other-than-temporary” impairment. The project was retitled FASB Staff Position (FSP) 115-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, which replaces the guidance found in EITF 03-01 and states that the assessment of whether impairment is “other-than-temporary” would be based upon existing “other-than-temporary” impairment guidance and the effective date for the use of this guidance would be for reporting periods beginning after December 15, 2005. The final FSP is expected to be issued in fourth quarter of calendar 2005 and should have no impact on our financial position, results of operations and cash flows.

In December 2004, the FASB issued SFAS 123 (revised), Share-Based Payment (SFAS 123(R)). This standard revises SFAS 123, Accounting for Stock-Based Compensation and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. Under SFAS 123(R), public companies will be required to measure the cost of employee services received in exchange for stock options and similar awards based on the grant-date fair value of the award and recognize this cost in the income statement over the period during which an employee is required to provide service in exchange for the award. In April 2005, the Securities and Exchange Commission deferred the required effective date of SFAS 123(R) until the beginning of a registrant’s next fiscal year. Accordingly, SFAS 123(R) will become effective for the Company for fiscal 2006 beginning on October 1, 2005.

SFAS 123(R) allows companies to adopt the new standard using the prospective, modified prospective or modified retrospective method. We will adopt SFAS 123(R) as of October 1, 2005 using the modified prospective method. Under this method, we will recognize compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service has not yet been rendered as of October 1, 2005, based upon the grant-date fair value of those awards calculated under SFAS 123 for pro forma disclosure purposes. We expect that the adoption of SFAS 123(R) will reduce our fiscal 2006 net income by approximately $0.5 million.

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred — generally upon acquisition, construction or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005. We are currently evaluating the impact that FIN 47 may have on our financial position, results of operations and cash flows.


3.	Acquisitions


	*TXU Gas Company*

On October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company. The purchase was accounted for as an asset purchase. The TXU Gas operations we acquired are regulated businesses engaged in the purchase, transmission, storage, distribution and sale of natural gas in the north-central, eastern and western parts of Texas. Through these newly acquired operations, we provide gas distribution services to approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area. We also now own and operate a system consisting of 6,162 miles of gas transmission and gathering lines and five underground storage reservoirs in Texas.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The purchase price for the TXU Gas acquisition was approximately $1.9 billion (after closing adjustments and before transaction costs and expenses), which we paid in cash. We acquired approximately $112 million of working capital of TXU Gas after the final working capital and capital expenditures settlement was negotiated during the third quarter of 2005, which resulted in a net payment to TXU Corporation of approximately $4.1 million. We did not assume any indebtedness of TXU Gas in connection with the acquisition. TXU Gas retained certain assets, provided for the repayment of all of its indebtedness and redeemed all of its preferred stock prior to closing and retained and agreed to pay certain other liabilities under the terms of the acquisition agreement.

We funded the purchase price for the TXU Gas acquisition with approximately $235.7 million in net proceeds from our offering of approximately 9.9 million shares of common stock, which we completed on July 19, 2004, and approximately $1.7 billion in net proceeds from our issuance on October 1, 2004 of commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 to provide bridge financing for the TXU Gas acquisition. In October 2004, we paid off the outstanding commercial paper used to fund the acquisition through the issuance of senior unsecured notes on October 22, 2004, which generated net proceeds of approximately $1.39 billion, and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of $381.6 million.

The following table summarizes the fair values of the assets acquired and liabilities assumed on October 1, 2004 (in thousands):


Cash purchase price		$	1,908,999
Transaction costs and expenses			7,697

	Total purchase price	$	1,916,696

Net property, plant and equipment		$	1,471,643
Accounts receivable			75,811
Gas stored underground			137,877
Other current assets			22,094
Goodwill			493,603
Deferred charges and other assets			42,069
Deferred income taxes			7,925
Accounts payable and accrued liabilities			(51,644	)
Other current liabilities			(77,756	)
Regulatory cost of removal obligation			(138,991	)
Deferred credits and other liabilities			(65,935	)

	Total	$	1,916,696

The sale of TXU Gas’s assets was held through a competitive bid process. We believe the resulting goodwill is recoverable given the expected synergies we can achieve as a result of the TXU Gas acquisition. To that end, the TXU Gas acquisition significantly expands our existing utility operations in Texas. The North Texas operations of TXU Gas bridge our geographic operations between our existing utility operations in West Texas and Louisiana. TXU Gas’s headquarters and service area are centered in Dallas, Texas, which is also the location of our corporate headquarters. Further, the addition of the regulated pipelines and storage operations in North Texas may create additional gas marketing and other opportunities for our non-regulated subsidiaries, which include gas marketing and storage operations. The goodwill generated in the acquisition is deductible for tax purposes.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The table below reflects the unaudited pro forma results of the Company and TXU Gas for the year ended September 30, 2004 as if the acquisition and related financing had taken place at the beginning of fiscal 2004 (in thousands, except per share data):


	Year Ended
	September 30, 2004

Operating revenue	$	4,174,500
Net income		118,746
Net income per diluted share	$	1.68


	*ComFurT Gas Inc.*

Effective March 1, 2004, we completed the acquisition of the natural gas distribution assets of ComFurT Gas Inc., a privately held natural gas utility and propane distributor based in Buena Vista, Colorado, for approximately $2.0 million in cash. This company served approximately 1,800 natural gas utility customers. The acquisition enabled us to expand our contiguous service area in our Colorado-Kansas division. Unaudited pro forma results of the Company and ComFurT have not been presented as the acquisition was not material to our financial position or results of operations.


	*Mississippi Valley Gas Company*

On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company, Mississippi’s largest natural gas utility. The acquisition of MVG enabled us to expand our service area into Mississippi. MVG served approximately 261,500 residential, commercial, industrial and other customers located primarily in the northern and central regions of Mississippi. MVG’s rate design provides timely returns on capital investment and earnings stability and enabled us to leverage our existing centralized management structure, shared services organization and information systems to manage costs in all of Atmos Energy’s utility service areas over the long term.

We paid approximately $74.7 million in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. We also repaid approximately $70.9 million of MVG’s outstanding debt. The results of operations of MVG have been consolidated with our results of operations from the acquisition date.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Goodwill and Intangible Assets

Goodwill and intangible assets were comprised of the following as of September 30, 2005 and 2004.


	September 30

	2005		2004

	(In thousands)
Goodwill	$	734,280	$	241,368
Intangible assets		3,507		4,160

Total	$	737,787	$	245,528

The following presents our goodwill balance allocated by segment and changes in the balance for the year ended September 30, 2005:


				Natural		Pipeline
				Gas		and		Other
	Utility			Marketing		Storage		Nonutility
	Segment			Segment		Segment		Segment			Total

	(In thousands)
Balance as of September 30, 2004	$	206,656		$	24,282	$	—	$	10,430		$	241,368
Intersegment transfer of assets⁽¹⁾		—			—		10,430		(10,430	)		—
TXU Gas acquisition (Note 3)		360,835			—		132,768		—			493,603
Other		(691	)		—		—		—			(691	)

Balance as of September 30, 2005	$	566,800		$	24,282	$	143,198	$	—		$	734,280

⁽¹⁾

Effective October 1, 2004, we created the pipeline and storage segment which includes the regulated pipeline and storage operations of the Atmos Pipeline–Texas Division as well as the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC, previously included in our other nonutility segment. Accordingly, goodwill allocable to Atmos Pipeline and Storage, LLC was transferred to the pipeline and storage segment.

Information regarding our intangible assets is included in the following table. As of September 30, 2005 and 2004, we had no indefinite-lived intangible assets.


			September 30, 2005							September 30, 2004

	Useful		Gross							Gross
	Life		Carrying		Accumulated					Carrying		Accumulated
	(Years)		Amount		Amortization			Net		Amount		Amortization			Net

								(In thousands)
Customer contracts		10	$	6,521	$	(3,014	)	$	3,507	$	6,521	$	(2,361	)	$	4,160

The following table presents actual amortization expense recognized during 2005 and an estimate of future amortization expense based upon our intangible assets at September 30, 2005.


Amortization expense (in thousands):
Actual for the fiscal year ending September 30, 2005		$	653
Estimated for the fiscal year ending:
	September 30, 2006		585
	September 30, 2007		585
	September 30, 2008		585
	September 30, 2009		585
	September 30, 2010		585

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Derivative Instruments and Hedging Activities

We conduct risk management activities through both our utility and natural gas marketing segments. These activities are more fully described in Note 2. Also, as discussed in Note 2, 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. Our determination of the fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains and losses on open contracts. In our determination of fair value, we consider various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts.

The following table shows the fair values of our risk management assets and liabilities by segment at September 30, 2005 and 2004:


				Natural Gas
	Utility			Marketing			Total

	(In thousands)
September 30, 2005:
Assets from risk management activities, current	$	93,310		$	14,603		$	107,913
Assets from risk management activities, noncurrent		—			735			735
Liabilities from risk management activities, current		—			(61,920	)		(61,920	)
Liabilities from risk management activities, noncurrent		—			(15,316	)		(15,316	)

Net assets (liabilities)	$	93,310		$	(61,898	)	$	31,412

September 30, 2004:
Assets from risk management activities, current	$	25,692		$	18,748		$	44,440
Assets from risk management activities, noncurrent		—			562			562
Liabilities from risk management activities, current		(34,304	)		(5,154	)		(39,458	)
Liabilities from risk management activities, noncurrent		—			(1,138	)		(1,138	)

Net assets (liabilities)	$	(8,612	)	$	13,018		$	4,406


	*Utility Hedging Activities*

We use a combination of storage, fixed physical contracts and fixed financial contracts to partially insulate us and our customers against gas price volatility during the winter heating season. For the 2004-2005 heating season, we hedged approximately 59 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $6.23 per Mcf.

In June 2001, we purchased a three-year weather-insurance policy with an option to cancel the third year of coverage. The insurance covered our Texas and Louisiana operations to protect against weather that was at least 7 percent warmer than normal for the entire heating season of October through March, beginning with the 2001-2002 heating season. The prepaid cost of the three-year policy was $13.2 million and was amortized over the appropriate heating seasons based on heating degree days. In the third quarter of fiscal 2003, we cancelled this policy, primarily as a result of rate relief in Louisiana and at that time, prospects for weather normalization adjustments in Texas. During fiscal 2003, we recognized amortization expense of $5.0 million. However, we did not collect under this policy because weather was not at least 7 percent warmer than normal.

Our utility hedging activities also includes the fair value of our treasury lock agreements which are described in further detail below.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Nonutility Hedging Activities*

For the year ended September 30, 2005, the increase in the deferred hedging gain in accumulated other comprehensive loss was attributable to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts totaling $2.0 million and the recognition of $10.4 million in net deferred hedge losses in net income when the derivatives matured according to their terms. The net deferred hedge gains associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. Substantially all of the deferred hedging gain as of September 30, 2005 is expected to be recognized in net income within the next fiscal year.

Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on September 30, 2005, AEH had no net open positions (including existing storage).


	Adoption of EITF 02-03

On October 25, 2002, EITF 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management, was issued. It rescinded EITF 98-10, Accounting for Energy Trading and Risk Management Activities, and required that all energy trading contracts entered into after October 25, 2002 be accounted for pursuant to the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. Beginning January 1, 2003, we have no longer marked our storage and transportation contracts to market value each month in accordance with EITF 98-10 and adopted EITF 02-03. As a result, we recorded $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle in fiscal 2003.


	*Treasury Activities*

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-then anticipated issuance of $875 million of long-term debt subsequent to September 30, 2004. This long-term debt was issued on October 22, 2004 and was used to repay a portion of the commercial paper used to fund the TXU Gas acquisition, as described in Note 3.

We designated these Treasury lock agreements as cash flow hedges of an anticipated transaction. Accordingly, to the extent effective, unrealized gains and losses associated with the Treasury locks were recorded as a component of accumulated other comprehensive loss. 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 will be 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, will be recognized as a component of interest expense over a ten year period from the date of settlement.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents our hedging transactions that were recorded to other comprehensive income (loss), net of taxes during the years ended September 30, 2005 and 2004.


		Year Ended
		September 30

		2005			2004

		(In thousands)
Increase (decrease) in fair value:
	Treasury lock agreements	$	(5,869	)	$	(21,268	)
	Forward commodity contracts		1,988			11,078
Recognition of (gains) losses in earnings due to settlements:
	Treasury lock agreements		3,155			—
	Forward commodity contracts		10,386			(3,495	)

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾		$	9,660		$	(13,685	)


⁽¹⁾	Utilizing an income tax rate of approximately 38 percent comprised of the effective rates in each taxing jurisdiction.

The following amounts net of deferred taxes represent the expected recognition into earnings for our derivative instruments, based upon the fair values of these derivatives as of September 30, 2005:


	Treasury
	Lock			Forward
	Agreements			Contracts			Total

	(In thousands)
2006	$	(3,442	)	$	19,864		$	16,422
2007		(3,442	)		174			(3,268	)
2008		(3,442	)		(81	)		(3,523	)
2009		(3,442	)		—			(3,442	)
2010		(2,123	)		—			(2,123	)
Thereafter		(8,091	)		—			(8,091	)

Total	$	(23,982	)	$	19,957		$	(4,025	)

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Debt


	*Long-term debt*

Long-term debt at September 30, 2005 and 2004 consisted of the following:


			2005			2004

			(In thousands)
Unsecured floating rate Senior Notes, due 2007			$	300,000		$	—
Unsecured 4.00% Senior Notes, due 2009				400,000			—
Unsecured 7.375% Senior Notes, due 2011				350,000			350,000
Unsecured 10% Notes, due 2011				2,303			2,303
Unsecured 5.125% Senior Notes, due 2013				250,000			250,000
Unsecured 4.95% Senior Notes, due 2014				500,000			—
Unsecured 5.95% Senior Notes, due 2034				200,000			—
Medium term notes
	Series A, 1995-2, 6.27%, due 2010			10,000			10,000
	Series A, 1995-1, 6.67%, due 2025			10,000			10,000
Unsecured 6.75% Debentures, due 2028				150,000			150,000
First Mortgage Bonds
	Series J, 9.40% due 2021			—			17,000
	Series P, 10.43% due 2013			10,000			11,250
	Series Q, 9.75% due 2020			—			16,000
	Series T, 9.32% due 2021			—			18,000
	Series U, 8.77% due 2022			—			20,000
	Series V, 7.50% due 2007			—			4,167
Rental property, propane and other term notes due in installments through 2013				7,839			9,830

		Total long-term debt		2,190,142			868,550
Less:
	Original issue discount on unsecured senior notes and debentures			(3,774	)		(1,331	)
	Current maturities			(3,264	)		(5,908	)

			$	2,183,104		$	861,311

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 on January 30, 2002. On January 16, 2003, we issued $250.0 million of 5.125% Senior Notes due 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes. Additionally, we sold 4.1 million shares of our common stock in connection with our June and July 2003 Offering under the registration statement to provide additional funding for our Pension Account Plan. In July 2004, we sold 9.9 million shares of our common stock, including the underwriters’ exercise of their overallotment option. We used the net proceeds from this offering, together with borrowings under a bridge financing facility to consummate the acquisition of substantially all of the assets of TXU Gas and pay related fees and expenses.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As a result of the offering, we exhausted the remaining availability under our December 2001 registration statement.

In August 2004, we filed another registration statement with the SEC, which was declared effective by the SEC on September 15, 2004, under which we may issue, from time to time, up to $2.2 billion in new common stock and/or debt. In October 2004, we sold 16.1 million common shares, including the underwriters’ exercise of their overallotment option, under the new registration statement, generating net proceeds of $382.5 million before other offering costs. Additionally, we issued senior unsecured debt under the registration statement consisting of $400 million of 4.00% Senior Notes due 2009, $500 million of 4.95% Senior Notes due 2014, $200 million of 5.95% Senior Notes due 2034 and $300 million of floating rate Senior Notes due 2007. The floating rate notes will bear interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At September 30, 2005, the interest rate on our floating rate debt was 3.974 percent. The net proceeds from the sale of these senior notes were $1.39 billion.

The net proceeds from the October 2004 common stock and senior notes offerings, combined with the net proceeds from our July 2004 offering were used to pay off the $1.7 billion in outstanding commercial paper backstopped by a senior unsecured revolving credit agreement, which we entered into on September 24, 2004 for bridge financing for the TXU Gas acquisition. After issuing the debt and equity in October 2004 we have approximately $401.5 million in availability remaining under the registration statement. Also, as a result of this refinancing in October 2004, we canceled the senior unsecured revolving credit facility.

On June 30, 2005, we elected to utilize excess cash to repay $72.5 million in principal on five series of our First Mortgage Bonds prior to their scheduled maturity. In connection with the 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.


	*Short-term debt*

At September 30, 2005, there was $129.9 million outstanding under our commercial paper program and $14.9 million outstanding under our bank credit facilities. At September 30, 2004, there were no short-term amounts outstanding under our commercial paper program or bank credit facilities.

Credit facilities


	*Committed credit facilities*

As of September 30, 2005, we had two short-term committed revolving credit facilities totaling $618.0 million, one of which was an unsecured facility for $600.0 million that bears interest at the Eurodollar rate plus 0.625 percent and served as a backup liquidity facility for our $600.0 million commercial paper program. We entered into this facility on October 22, 2004 to replace our $350.0 million credit facility that served as the backup liquidity facility for our $350.0 million commercial paper program. At September 30, 2005, $129.9 million of commercial paper was outstanding under this facility.

In October 2005, this facility expired and we replaced it with a new $600.0 million 3-year revolving credit facility that became effective October 18, 2005. This facility bears interest at a rate ranging from LIBOR plus

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

0.40% to 1.00%. Based upon our current credit ratings, borrowings would bear interest at our option of either a base rate or LIBOR plus 0.55%. Additionally, the facility is subject to quarterly commitment fees ranging from .075% to .200%, dependent on our credit ratings. Based upon our current credit ratings, the commitment fee is 0.100%. On November 10, 2005, a new $300.0 million 364-day revolving credit facility became effective with substantially the same terms as our $600.0 million facility.

We have a third unsecured facility in place for $18.0 million that bears interest at the Federal Funds rate plus 0.5 percent. This facility expired on March 31, 2005 and was renewed effective April 1, 2005 for an additional twelve months with no material changes to its terms and pricing. At September 30, 2005, $14.9 million was outstanding under this facility.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in both revolving credit facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At September 30, 2005, our total-debt-to-total-capitalization ratio, as defined, was 61 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under both revolving credit facilities are subject to adjustment depending upon our credit ratings. The new revolving credit facilities each contain the same limitation with respect to our total-debt to-total capitalization ratio.


	*Uncommitted credit facilities*

AEM had a $250.0 million uncommitted demand working capital credit facility that bore interest at the Eurodollar rate plus 2.5 percent that was scheduled to expire on March 31, 2005. On March 30, 2005, the facility was amended and extended to March 31, 2006. This facility is guaranteed by AEH.

Borrowings under the amended facility can be made either as revolving loans or offshore rate loans. Revolving loan borrowings will bear interest at a floating rate equal to a base rate (defined as the higher of 0.50% per annum above the Federal Funds rate or the lender’s prime rate) plus 0.50%. Offshore rate loan borrowings will bear interest at a floating rate equal to a base rate based upon LIBOR plus an applicable margin, ranging from 1.375% to 1.75% per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. Borrowings drawn down under letters of credit issued by the banks will bear interest at a floating rate equal to the base rate, as defined above plus an applicable margin, which will range from 1.125% to 2.00% per annum, depending on the excess tangible net worth of AEM and whether the letters of credit are swap-related standby letters of credit.

AEM is required by the financial covenants in the credit facility to maintain a maximum ratio of total liabilities to tangible net worth of 5 to 1, along with minimum levels of net working capital ranging from $20 million to $50 million. Additionally, AEM must maintain a minimum tangible net worth ranging from $21 million to $51 million, and must not have a maximum cumulative loss from March 30, 2005 exceeding $4 million to $10 million, depending on the total amount of borrowing elected from time to time by AEM. At September 30, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined, was 2.18 to 1.

At September 30, 2005, no amounts were outstanding under this credit facility. However, at September 30, 2005, AEM letters of credit totaling $123.6 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $26.3 million at September 30, 2005. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

We also have an unsecured short-term uncommitted credit line for $25.0 million that is used for working capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2005, but letters of credit reduced the amount available by $4.2 million. This uncommitted line is renewed or renegotiated at least annually with varying terms, and we pay no fee for the availability of the line. Borrowings under this line are made on a when- and as-available basis at the discretion of the bank.

AEH, the parent company of AEM, has a $100.0 million intercompany uncommitted demand credit facility with the Company which bears interest at LIBOR plus 2.75%. This facility has been approved by our state regulators through December 31, 2006. At September 30, 2005, there was $51.3 million outstanding under this facility.

In addition, AEM had a $100.0 million intercompany uncommitted demand credit facility with AEH for its nonutility business which bears interest at the LIBOR rate plus 2.75 percent. On July 1, 2005, this facility was renewed and the amount available for borrowing was increased to $120.0 million. Any outstanding amounts under this facility are subordinated to AEM’s $250.0 million uncommitted demand credit facility described above. This facility is used to supplement AEM’s $250.0 million credit facility. At September 30, 2005, there was $60.0 million outstanding under this facility.


	*Debt Covenants*

We have other covenants in addition to those described above. Our Series P First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, after November 2007, subject to a prepayment premium. The First Mortgage Bonds provide for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. Under the most restrictive of such covenants, cumulative cash dividends paid after December 31, 1985 may not exceed the sum of accumulated net income for periods after December 31, 1985 plus $9.0 million. At September 30, 2005 approximately $157.9 million of retained earnings was unrestricted with respect to the payment of dividends.

As of September 30, 2005, a portion of the Mid-States Division utility plant assets, totaling $376.8 million, was subject to a lien under the Indenture of Mortgage of the Series P First Mortgage Bonds.

We were in compliance with all of our debt covenants as of September 30, 2005. 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.

Based on the borrowing rates currently available to us for debt with similar terms and remaining average maturities, the fair value of long-term debt at September 30, 2005 and 2004 is estimated, using discounted cash flow analysis, to be $2,078.3 million and $936.6 million.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Maturities of long-term debt at September 30, 2005 were as follows (in thousands):


2006	$	3,264
2007		3,186
2008		303,831
2009		2,034
2010		401,381
Thereafter		1,476,446

	$	2,190,142


7.	Shareholders’ Equity


	*Stock Issuances*

During the years ended September 30, 2005, 2004 and 2003 we issued 17,739,691, 11,323,925, and 9,799,853 shares of common stock.

On February 9, 2005, our shareholders approved an amendment to our Articles of Incorporation to increase the number of authorized shares from 100 million to 200 million.

On October 27, 2004, we completed the public offering of 16.1 million shares of our common stock including the underwriters’ exercise of their overallotment option of 2.1 million shares. The offering was priced at $24.75 and generated net proceeds of approximately $381.6 million. We used the net proceeds from this offering, together with net proceeds of $235.7 million from a public offering we conducted in July 2004 and $1.39 billion received from the issuance of senior unsecured notes to repay the $1.7 billion in outstanding commercial paper described in Note 3 and fund the remainder of the purchase price for the TXU Gas acquisition.

On June 23, 2003, we completed a public offering of 4.0 million shares of our common stock, and we sold an additional 100,000 shares of our common stock in July 2003 when our underwriters exercised their overallotment option (the 2003 Offering). The 2003 Offering was priced at $25.31 per share and generated net proceeds of approximately $99.2 million. The proceeds were used to partially fund our pension plan, to repay short-term debt and for other general corporate purposes including the purchase of natural gas for storage.


	*Shareholder Rights Plan*

On November 12, 1997, our Board of Directors declared a dividend distribution of one right for each outstanding share of our common stock to shareholders of record at the close of business on May 10, 1998. Each right entitles the registered holder to purchase from us a one-tenth share of our common stock at a purchase price of $8.00 per share, subject to adjustment. The description and terms of the rights are set forth in a rights agreement between us and the rights agent.

Subject to exceptions specified in the rights agreement, the rights will separate from our common stock and a distribution date will occur upon the earlier of:


	•	ten business days following a public announcement that a person or group of affiliated or associated persons has acquired, or obtained the right to acquire, beneficial ownership of 15 percent or more of the outstanding shares of our common stock, other than as a result of repurchases of stock by us or specified inadvertent actions by institutional or other shareholders;

	•	ten business days, or such later date as our Board of Directors shall determine, following the commencement of a tender offer or exchange offer that would result in a person or group having

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		acquired, or obtained the right to acquire, beneficial ownership of 15 percent or more of the outstanding shares of our common stock; or

	•	ten business days after our Board of Directors shall declare any person to be an adverse person within the meaning of the rights plan.

The rights expire on May 10, 2008, unless extended prior thereto by our board or earlier if redeemed by us. The rights will not have any voting rights. The exercise price payable and the number of shares of our common stock or other securities or property issuable upon exercise of the rights are subject to adjustment from time to time to prevent dilution. We issue rights when we issue our common stock until the rights have separated from the common stock. After the rights have separated from the common stock, we may issue additional rights if the board of directors deems such issuance to be necessary or appropriate. The rights have “anti-takeover” effects and may cause substantial dilution to a person or entity that attempts to acquire us on terms not approved by our board of directors except pursuant to an offer conditioned upon a substantial number of rights being acquired. The rights should not interfere with any merger or other business combination approved by our board of directors because, prior to the time that the rights become exercisable or transferable, we can redeem the rights at $.01 per right.


	*Registration Rights and Other Agreements*

As part of the consideration for our Mississippi Valley Gas Company acquisition in December 2002, we issued shares of common stock under an exemption from registration under the Securities Act of 1933, as amended. In the transaction, we entered into a registration rights agreement with the former stockholders of Mississippi Valley Gas Company that requires us, on no more than two occasions, and with some limitations, to file a registration statement under the Securities Act within 60 days of their request for an offering designed to achieve a wide distribution of shares through underwriters selected by us. We also granted rights to these shareholders, subject to some limitations, to participate in future registered offerings of our securities until December 3, 2005. As of September 30, 2005, 1,193,143 shares were covered by the registration rights agreement. Each of these shareholders has also agreed, for up to five years from the closing of the acquisition, and with some exceptions, not to sell or transfer shares representing more than 1 percent of our total outstanding voting securities to any person or group or any shares to a person or group who would hold more than 9.9 percent of our total outstanding voting securities after the sale or transfer. This restriction, and other agreed restrictions on the ability of these shareholders to acquire additional shares, participate in proxy solicitations or act to seek control, may be deemed to have an “anti-takeover” effect.

In addition, in connection with our funding of the Atmos Energy Corporation Pension Account Plan, we issued, in June 2003, to the Atmos Energy Corporation Master Retirement Trust, for the benefit of the Pension Account Plan, 1,169,700 shares of common stock under an exemption from registration under the Securities Act. In the transaction, we entered into a registration rights agreement with the asset manager of the Pension Account Plan that requires us, on no more than three occasions, and with some limitations, to file a registration statement under the Securities Act within 60 days of its request for an offering designed to achieve a wide distribution of shares through underwriters selected by us. We also granted rights to the asset manager, subject to some limitations, to participate in future registered offerings of our securities. The registration rights agreement expired on June 30, 2005.


8.	Stock and Other Compensation Plans


	*Stock-Based Compensation Plans*

We have two stock-based compensation plans that provide for the granting of incentive stock options, nonqualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to officers and key employees: the 1998 Long-Term Incentive Plan and the Long-Term Stock Plan for

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Mid-States Division. Nonemployee directors are also eligible to receive such stock-based compensation under the 1998 Long-Term Incentive Plan. The objectives of these plans include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.


	1998 Long-Term Incentive Plan

On August 12, 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan, which became effective October 1, 1998 after approval by our shareholders. The Long-Term Incentive Plan is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, restricted stock and performance-based stock to help attract, retain and reward certain employees and non-employee directors of Atmos and its subsidiaries. We are authorized to grant awards for up to a maximum of 4.0 million shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2005, non-qualified stock options, bonus stock and restricted stock have been issued under this plan, and 1,290,292 shares were available for issuance. The option price of the stock options issued under this plan is equal to the market price of our stock at the date of grant. These stock options expire 10 years from the date of the grant and vest annually over a service period ranging from one to three years.

A summary of activity for grants of stock options under the 1998 Long-Term Incentive Plan follows:


		2005					2004					2003

					Weighted					Weighted					Weighted
					Average					Average					Average
		Number of			Exercise		Number of			Exercise		Number of			Exercise
		Options			Price		Options			Price		Options			Price

Outstanding at beginning of year			1,492,177		$	22.10		1,827,310		$	21.91		1,557,606		$	21.87
	Granted		23,432			25.95		8,118			24.44		411,860			21.37
	Exercised		(547,907	)		22.08		(342,252	)		20.91		(92,989	)		17.79
	Forfeited		(2,998	)		22.81		(999	)		22.49		(49,167	)		23.89

Outstanding at end of year			964,704		$	22.20		1,492,177		$	22.10		1,827,310		$	21.91

Exercisable at end of year			798,574		$	22.22		1,006,859		$	22.23		868,199		$	21.69

Information about outstanding and exercisable options under the Long-Term Incentive Plan, as of September 30, 2005, follows:


	Options Outstanding

			Weighted				Options Exercisable
			Average
			Remaining		Weighted				Weighted
			Contractual		Average				Average
	Number of		Life		Exercise		Number of		Exercise
Range of Exercise Prices	Options		(in Years)		Price		Options		Price

$15.65 to $20.24		65,499		4.4	$	15.66		65,499	$	15.66
$20.25 to $22.99		580,422		6.8	$	21.87		444,536	$	22.03
$23.00 to $25.95		318,783		4.9	$	24.15		288,539	$	24.00

$15.65 to $25.95		964,704		6.0	$	22.20		798,574	$	22.22

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The stock options had a weighted average fair value per share on the date of grant of $3.69 in 2005, $3.82 in 2004 and $3.32 in 2003. We used the Black-Scholes pricing model to estimate the fair value of each option granted with the following weighted average assumptions for 2005, 2004 and 2003:


	Year Ended
	September 30

	2005			2004			2003

Expected Life (years)		7			7			7
Interest rate		4.2	%		4.3	%		4.0	%
Volatility		21.3	%		22.8	%		23.3	%
Dividend yield		4.8	%		4.8	%		4.8	%


	Long-Term Stock Plan for the Mid-States Division

Prior to the merger with Atmos, certain United Cities Gas Company officers and key employees participated in the United Cities Long-Term Stock Plan implemented in 1989. At the time of the merger on July 31, 1997, we adopted this plan by registering a total of 250,000 shares of Atmos stock to be issued under the Long-Term Stock Plan for the Mid-States Division. Under this plan, incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock or any combination thereof may be granted to officers and key employees of the Mid-States Division. Options granted under the plan become exercisable at a rate of 20 percent per year and expire 10 years after the date of grant. No awards have been granted under this plan since 1996. During 2005, no options were exercised under the plan. At September 30, 2005, there were 300 options outstanding, all of which were fully vested.


	*Restricted Stock Plans*

As noted above, the 1998 Long-Term Incentive Plan provides for discretionary awards of restricted stock to help attract, retain and reward employees and non-employee directors of Atmos and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The associated expense is recognized ratably over the vesting period. The following summarizes information regarding the restricted stock plan:


	Year Ended September 30

	2005		2004		2003

Shares granted during the year		294,834		240,686		82,933
Weighted average intrinsic value	$	26.78	$	24.78	$	21.34
Compensation expense recognized, net of tax (in thousands)	$	2,431	$	978	$	370
Unexpired shares with unmet restrictions at September 30		592,490		345,519		101,486


	*Other Plans*


	Direct Stock Purchase Plan

We maintain a Direct Stock Purchase Plan which allows participants to have all or part of their cash dividends paid quarterly in additional shares of our common stock. Through March 31, 2004, participants were permitted to reinvest their cash dividends at a three percent discount from market prices. Effective April 1, 2004, the three percent discount on reinvested dividends was eliminated and the minimum initial investment required to join the plan was increased to $1,250. Direct Stock Purchase Plan participants may purchase additional shares of Atmos common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Outside Directors Stock-For-Fee Plan

In November 1994, the Board adopted the Outside Directors Stock-for-Fee Plan which was approved by the shareholders of Atmos in February 1995 and was amended and restated in November 1997. The plan permits non-employee directors to receive all or part of their annual retainer and meeting fees in stock rather than in cash.


	Equity Incentive and Deferred Compensation Plan for Non-Employee Directors

In November 1998, the Board of Directors adopted the Equity Incentive and Deferred Compensation Plan for Non-Employee Directors which was approved by the shareholders of Atmos in February 1999. This plan amended the Atmos Energy Corporation Deferred Compensation Plan for Outside Directors adopted by the Company on May 10, 1990 and replaced the pension payable under the Company’s Retirement Plan for Non-Employee Directors. The plan provides non-employee directors of Atmos with the opportunity to defer receipt, until retirement, of compensation for services rendered to the Company, invest deferred compensation into either a cash account or a stock account and to receive an annual grant of share units for each year of service on the Board.


	Variable Pay Plan

The Variable Pay Plan was created in fiscal 1999 to give each employee an opportunity to share in the success of Atmos based on the achievement of key performance measures considered critical to achieving business objectives for a given year. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded.


9.	Retirement and Post-Retirement Employee Benefit Plans

We have both funded and unfunded noncontributory defined benefit plans that together cover substantially all of our employees. We also maintain post-retirement plans that provide health care benefits to retired employees. Finally, we sponsor defined contribution plans which cover substantially all employees. These plans are discussed in further detail below.


	*Defined Benefit Plans*


	Employee Pension Plans

As of September 30, 2005, we maintained two defined benefit plans: the Atmos Energy Corporation Pension Account Plan and the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees. Both plans are held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust).

The Atmos Energy Corporation Pension Account Plan (the Plan) was established effective January 1, 1999 and covers substantially all employees of Atmos. Opening account balances were established for participants as of January 1, 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula based on the participant’s age, service and total pay (excluding incentive pay). Although we did not assume the existing employee benefit liabilities or plans of TXU Gas, we agreed to give certain transitioned employees credit for years of TXU Gas service under our pension plan.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Plan also provides for an additional annual allocation based upon a participant’s age as of January 1, 1999 for those participants who were participants in the prior pension plans. The Plan will credit this additional allocation each year through December 31, 2008. In addition, at the end of each year, a participant’s account will be credited with interest on the employee’s prior year account balance. A special grandfather benefit also applies through December 31, 2008, for participants who were at least age 50 as of January 1, 1999, and who were participants in one of the prior plans on December 31, 1998. Participants fully vest in their account balances after five years of service and may choose to receive their account balances as a lump sum or an annuity.

MVG maintained a defined benefit plan that covered substantially all full-time employees (the MVG Plan). On June 30, 2003, all retirees and the active non-union employees became eligible to participate in the Plan. Active union employees remained in the MVG Plan, which was renamed the Atmos Energy Corporation Retirement Plan for Mississippi Valley Gas Union Employees on July 1, 2003. Under this plan, benefits are based upon years of benefit service and average final earnings. Participants vest in the plan after five years and will receive their benefit in an annuity.

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 did not contribute to our pension plans during fiscal 2004. We are not required to make a minimum funding contribution during fiscal 2006 nor do we anticipate making any voluntary contributions during fiscal 2006.

We manage the Master Trust’s assets with the objective of achieving a real rate of return of approximately four percent per year. We make investment decisions and evaluate performance on a medium term horizon of at least three to five years. We also consider our current financial status when making recommendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long term asset allocation policy.

To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities, interests in commingled pension trust funds and cash and cash equivalents. Investments in equity securities are diversified among the market’s various subsectors to diversify risk and maximize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents asset allocation information for the Master Trust as of September 30, 2005 and 2004.


			Actual Allocation
			September 30
	Targeted
Security Class	Allocation Range		2005		2004

Domestic equities		35% - 55%		45.0%		40.8%
International equities		10% - 20%		17.9%		17.1%
Fixed income		10% - 30%		18.1%		21.1%
Company stock		0% - 10%		9.1%		9.0%
Other assets		5% - 15%		9.6%		11.0%
Cash and equivalents		N/A		0.3%		1.0%

At September 30, 2005 and 2004, the Plan held 1,169,700 shares of Atmos common stock, which represented 9.1 percent and 9.0 percent of total Master Trust assets. These shares generated dividend income of approximately $1.5 million and $1.4 million during fiscal 2005 and 2004.

Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions underlying our employee pension plans annually based upon a June 30 measurement date. The development of our assumptions is more fully described in our significant accounting policies in Note 2. The actuarial assumptions used to determine the pension liability for the Master Trust were determined as of June 30, 2005 and 2004 and the actuarial assumptions used to determine the net periodic pension cost for the Master Trust were determined as of June 30, 2004, 2003 and 2002. These assumptions are presented in the following table:


	Pension Liability				Pension Cost

	2005		2004		2005		2004		2003

Discount rate		5.00%		6.25%		6.25%		6.00%		7.25%
Rate of compensation increase		4.00%		4.00%		4.00%		4.00%		4.00%
Expected return on plan assets		8.50%		8.75%		8.75%		9.00%		9.25%

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the Master Trust’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2005 and 2004.


		2005			2004

		(In thousands)
Accumulated benefit obligation		$	348,383		$	305,081

Change in projected benefit obligation:
	Benefit obligation at beginning of year	$	312,997		$	330,344
	Service cost		10,401			7,696
	Interest cost		19,412			19,691
	Actuarial loss (gain)		43,313			(16,803	)
	Benefits paid		(26,199	)		(27,931	)

	Benefit obligation at end of year		359,924			312,997
Change in plan assets:
	Fair value of plan assets at beginning of year		346,162			322,703
	Actual return on plan assets		32,976			51,390
	Employer contributions		3,000			—
	Benefits paid		(26,199	)		(27,931	)

	Fair value of plan assets at end of year		355,939			346,162

Reconciliation:
Funded status			(3,985	)		33,165
Unrecognized prior service cost			(5,939	)		(6,967	)
Unrecognized net loss			119,270			87,668

Net amount recognized		$	109,346		$	113,866

Net periodic pension cost for the Master Trust for 2005, 2004 and 2003 is recorded as a component of operating expense and included the following components:


			Year Ended September 30

			2005			2004			2003

			(In thousands)
Components of net periodic pension cost:
	Service cost		$	10,401		$	7,696		$	6,693
	Interest cost			19,412			19,691			19,044
	Expected return on assets			(27,541	)		(30,097	)		(23,950	)
	Amortization of prior service cost			(1,028	)		(1,028	)		(883	)
	Recognized actuarial loss			6,276			6,555			1,756

		Net periodic pension cost	$	7,520		$	2,817		$	2,660


	Supplemental Executive Benefits Plans

We have a nonqualified Supplemental Executive Benefits Plan which provides additional pension, disability and death benefits to the officers and certain other employees of Atmos. The Supplemental Plan was amended and restated in August 1998. In addition, in August 1998, we adopted the Performance-Based

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Supplemental Executive Benefits Plan which covers all employees who become officers or division presidents after August 12, 1998 or any other employees selected by our Board of Directors in its discretion.

Similar to our employee pension plans, we review the estimates and assumptions underlying our supplemental executive benefit plans annually based upon a June 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of June 30, 2005 and 2004 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of June 30, 2004, 2003 and 2002. These assumptions are presented in the following table:


	Pension Liability				Pension Cost

	2005		2004		2005		2004		2003

Discount rate		5.00%		6.25%		6.25%		6.00%		7.25%
Rate of compensation increase		4.00%		4.00%		4.00%		4.00%		4.00%

The following table presents the supplemental plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2005 and 2004.


		2005			2004

		(In thousands)
Accumulated benefit obligation		$	86,661		$	64,754

Change in projected benefit obligation:
	Benefit obligation at beginning of year	$	73,998		$	71,659
	Service cost		2,144			2,037
	Interest cost		4,658			4,324
	Actuarial loss (gain)		20,637			(682	)
	Benefits paid		(3,496	)		(3,340	)

	Benefit obligation at end of year		97,941			73,998
Change in plan assets:
	Fair value of plan assets at beginning of year		—			—
	Employer contribution		3,496			3,340
	Benefits paid		(3,496	)		(3,340	)

	Fair value of plan assets at end of year		—			—

Reconciliation:
	Funded status		(97,941	)		(73,998	)
	Unrecognized transition obligation		—			4
	Unrecognized prior service cost		2,706			3,728
	Unrecognized net loss		40,334			20,987

	Accrued pension cost	$	(54,901	)	$	(49,279	)

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assets for the supplemental plans are held in separate rabbi trusts and comprise the following:


				Unrealized
				Holding			Market
		Cost		Gain (Loss)			Value

		(In thousands)
As of September 30, 2005:
	Domestic equity mutual funds	$	28,902	$	897		$	29,799
	Foreign equity mutual funds		5,133		328			5,461

		$	34,035	$	1,225		$	35,260

As of September 30, 2004:
	Domestic equity mutual funds	$	29,894	$	(1,537	)	$	28,357
	Foreign equity mutual funds		3,279		298			3,577

		$	33,173	$	(1,239	)	$	31,934

At September 30, 2005, we maintained investments in one domestic equity mutual fund that was in an unrealized loss position as of September 30, 2005. Information concerning unrealized losses for our supplemental plan assets follows:


	Less Than 12 Months				12 Months or More

			Unrealized				Unrealized
	Fair Value		Loss		Fair Value		Loss

	(In thousands)
Domestic equity mutual funds	$	—	$	—	$	6,124	$	(528	)
Foreign equity mutual funds		—		—		—		—

	$	—	$	—	$	6,124	$	(528	)

Because this fund is only used to fund the supplemental plans, we evaluate investment performance over a long-term horizon. Based upon our intent and ability to hold this investment and to direct the source of the payments in order to maximize the life of the portfolio, the improved investment returns in the last year and the fact that the fund continues to receive good ratings from mutual fund rating companies, we do not consider this impairment to be other-than-temporary.

Net periodic pension cost for the supplemental plans for 2005, 2004 and 2003 is recorded as a component of operating expense and included the following components:


			Year Ended September 30

			2005		2004		2003

			(In thousands)
Components of net periodic pension cost:
	Service cost		$	2,144	$	2,037	$	1,548
	Interest cost			4,658		4,324		4,294
	Amortization of transition asset			4		96		96
	Amortization of prior service cost			1,022		1,022		1,022
	Recognized actuarial loss			1,290		1,516		772

		Net periodic pension cost	$	9,118	$	8,995	$	7,732

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Supplemental Disclosures For Defined Benefit Plans with Accumulated Benefit Obligations in Excess of Plan Assets

The following summarizes key information for our defined benefit plans with accumulated benefit obligations in excess of plan assets. For fiscal 2005 and 2004 the accumulated benefit obligation for the MVG plan and our supplemental plans exceeded the fair value of plan assets.


	Employee
	Pension Plans				Supplemental Plans

	2005		2004		2005		2004

			(In thousands)
Projected Benefit Obligation	$	13,550	$	8,840	$	97,941	$	73,998
Accumulated Benefit Obligation		10,738		6,555		86,661		64,754
Fair Value of Plan Assets		6,465		4,482		—		—


	Estimated Future Benefit Payments

The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following years:


	Pension		Supplemental
	Plans		Plans

	(In thousands)
2006	$	29,877	$	3,856
2007		27,991		4,008
2008		27,725		4,136
2009		28,747		4,400
2010		29,440		5,026
2011-2015		145,506		27,368


	*Postretirement Benefits*

At September 30, 2005, we sponsored the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation (the Atmos Retiree Medical Plan). Effective December 31, 2004, the Atmos Energy Corporation Retiree Welfare Benefits Plan for Certain MVG Non-Union Employees and the Atmos Energy Corporation Retiree Welfare Benefits Plan for MVG Union Employees merged into the Atmos Retiree Medical Plan.

This plan provides medical and prescription drug protection to all qualified participants based on their date of retirement. The Plan provides different levels of benefits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however, we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remaining 20 percent of this cost.

On October 1, 2004, in connection with the acquisition of TXU Gas, we transitioned certain employees from TXU Gas to Atmos Energy Corporation. Although we did not assume the existing employee benefit liabilities or plans of TXU Gas, 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 the Atmos 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 transitioned employees on the acquisition date.

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 annually as considered necessary. Contributions are intended to provide not only for benefits attributed

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

to service to date but also for those expected to be earned in the future. We expect to contribute $11.9 million to our postretirement benefits plans during fiscal 2006.

We maintain a formal investment policy with respect to the assets in our postretirement benefits plans in order to ensure the assets funding the postretirement benefit plans are appropriately invested to maintain an acceptable level of risk. We also consider our current financial status when making recommendations and decisions regarding the postretirement benefits plans.

We currently invest the assets funding our postretirement benefit plans in money market funds, equity mutual funds, fixed income funds and a balanced fund. The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2005 and 2004.


	Actual
	Allocation
	September 30

Security Class	2005			2004

Diversified investment fund⁽¹⁾		97.2	%		82.0%
Equity mutual funds		—			9.9%
Fixed income mutual funds		—			4.3%
Cash and cash equivalents		2.8	%		3.8%


⁽¹⁾	This fund invests in a diversified portfolio of common stocks, preferred stocks and fixed income securities. It may invest up to 75 percent of assets in common stocks and convertible securities.

Similar to our employee pension and supplemental plans, we review the estimates and assumptions underlying our supplemental executive benefit plans annually based upon a June 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of June 30, 2005 and 2004 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of June 30, 2004, 2003 and 2002. The assumptions are presented in the following table:


	Postretirement
	Liability						Postretirement Cost

	2005			2004			2005			2004			2003

Discount rate		5.00	%		6.25	%		6.25	%		6.19	%		7.25	%
Expected return on plan assets		5.30	%		5.30	%		5.30	%		5.30	%		5.30	%
Initial trend rate		9.00	%		10.00	%		10.00	%		9.00	%		10.00	%
Ultimate trend rate		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Ultimate trend reached in		2010			2010			2010			2008			2008

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2005 and 2004.


		2005			2004

		(In thousands)
Change in benefit obligation:
	Benefit obligation at beginning of year	$	125,189		$	137,285
	Service cost		9,968			5,941
	Interest cost		9,369			7,355
	Plan participants’ contributions		2,131			1,900
	Actuarial loss (gain)		16,449			(17,038	)
	Acquisition		18,878			—
	Benefits paid		(11,054	)		(10,254	)

	Benefit obligation at end of year		170,930			125,189
Change in plan assets:
	Fair value of plan assets at beginning of year		36,408			26,310
	Actual return on plan assets		2,365			4,695
	Employer contributions		9,993			13,757
	Plan participants’ contributions		2,131			1,900
	Benefits paid		(11,054	)		(10,254	)

	Fair value of plan assets at end of year		39,843			36,408

Reconciliation:
Funded status			(131,087	)		(88,781	)
Unrecognized transition obligation			12,665			14,176
Unrecognized prior service cost			394			780
Unrecognized net loss			28,513			12,981

Accrued postretirement cost		$	(89,515	)	$	(60,844	)

Net periodic postretirement cost for 2005, 2004 and 2003 is recorded as a component of operating expense and included the components presented below. The 2005 and 2004 amounts reflect the impact of adopting the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) beginning in the second quarter of fiscal 2004 as the plan is considered “actuarially equivalent” to Medicare Part D.


			Year Ended September 30

			2005			2004			2003

			(In thousands)
Components of net periodic postretirement cost:
	Service cost		$	9,968		$	5,941		$	5,902
	Interest cost			9,369			7,355			9,078
	Expected return on assets			(2,070	)		(1,523	)		(1,012	)
	Amortization of transition obligation			1,511			1,511			1,511
	Amortization of prior service cost			386			386			368
	Recognized actuarial loss			622			635			1,778

		Net periodic postretirement cost	$	19,786		$	14,305		$	17,625

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assumed health care cost trend rates have a significant effect on the amounts reported for the plan. A one-percentage point change in assumed health care cost trend rates would have the following effects on the latest actuarial calculations:


	1-Percentage		1-Percentage
	Point Increase		Point Decrease

	(In thousands)
Effect on total service and interest cost components	$	3,034	$	(2,405	)
Effect on postretirement benefit obligation	$	21,512	$	(17,879	)

We are currently recovering other postretirement benefits costs through our regulated rates under SFAS 106 accrual accounting in substantially all of our service areas. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by our Mid-States Division and our Mississippi Division or have been included in a rate case and not disallowed. Management believes that accrual accounting in accordance with SFAS 106 is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.


	Estimated Future Benefit Payments

The following benefit payments paid by us and retirees for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following years:


					Total
	Company		Retiree		Postretirement
	Payments		Payments		Benefits

	(In thousands)
2006	$	11,870	$	3,026	$	14,896
2007		8,489		3,224		11,713
2008		9,201		3,563		12,764
2009		9,996		3,955		13,951
2010		10,934		4,277		15,211
2011-2015		69,829		26,091		95,920


	*Defined Contribution Plans*

As of September 30, 2005, we maintained two contribution benefit plans: the Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) and the Atmos Energy Corporation Savings Plan for MVG Union Employees (the Union 401K Plan).

The Retirement Savings Plan covers substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Participants may elect a salary reduction ranging from a minimum of one percent up to a maximum of 65 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. We match 100 percent of a participant’s contributions, limited to four percent of the participant’s salary, in Atmos common stock. Participants are eligible to receive matching contributions after completing one year of service. However, participants have the option to immediately transfer this matching contribution into other funds held within the plan. Participants are also permitted to take out loans against their accounts subject to certain restrictions.

The Union 401K Plan covers substantially all Mississippi Division employees who are members of the International Chemical Workers Union Council, United Food and Commercial Workers Union International and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Employees of the Union automatically become participants of the Union 401K plan on the date of union employment. We match

100

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

50 percent of a participant’s contribution, limited to six percent of the participant’s eligible contribution. Participants are also permitted to take out loans against their accounts subject to certain restrictions.

Matching contributions to our defined contribution plans are expensed as incurred and amounted to $5.7 million, $4.6 million, and $4.1 million for 2005, 2004 and 2003. The Board of Directors may also approve discretionary contributions, subject to the provisions of the Internal Revenue Code of 1986 and applicable regulations of the Internal Revenue Service. No discretionary contributions were made for 2005, 2004 or 2003. At September 30, 2005 and 2004, the Retirement Savings Plan held 3.1 percent and 3.7 percent of our outstanding common stock.


10.	Details of Selected Consolidated Balance Sheet Captions

The following tables provide additional information regarding the composition of certain of our balance sheet captions.


	*Accounts receivable*

Accounts receivable was comprised of the following at September 30, 2005 and 2004:


	September 30

	2005			2004

	(In thousands)
Billed accounts receivable	$	381,469		$	187,306
Unbilled revenue		62,337			15,991
Other accounts receivable		26,120			15,727

Total accounts receivable		469,926			219,024
Less: allowance for doubtful accounts		(15,613	)		(7,214	)

Net accounts receivable	$	454,313		$	211,810


	*Other current assets*

Other current assets as of September 30, 2005 and 2004 were comprised of the following accounts.


	September 30

	2005		2004

	(In thousands)
Assets from risk management activities	$	107,913	$	44,440
Deferred gas cost		38,173		8,756
Current deferred tax asset		67,365		27,327
Prepaid expenses		13,334		9,194
Current portion of leased assets receivable		2,973		2,973
Materials and supplies		7,502		2,626
Other		978		4,003

Total	$	238,238	$	99,319

101

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Property, plant and equipment*

Property, plant and equipment was comprised of the following as of September 30, 2005 and 2004:


		September 30

		2005			2004

		(In thousands)
Production plant		$	19,401		$	4,288
Storage plant			116,708			58,075
Transmission plant			753,499			134,174
Distribution plant			3,164,316			1,971,124
General plant			502,189			382,220
Intangible plant			75,571			45,493

			4,631,684			2,595,374
Construction in progress			133,926			38,277

			4,765,610			2,633,651
Less: accumulated depreciation and amortization			(1,391,243	)		(911,130	)

	Net property, plant and equipment	$	3,374,367		$	1,722,521


	*Deferred charges and other assets*

Deferred charges and other assets as of September 30, 2005 and 2004 were comprised of the following accounts.


	September 30

	2005		2004

	(In thousands)
Pension plan assets in excess of plan obligations	$	109,346	$	113,866
Marketable securities		35,260		31,934
Long-term receivable on leased assets		19,413		22,511
Regulatory assets		37,844		27,229
Rights of way		11,746		11,746
Deferred financing costs		47,792		14,588
Assets from risk management activities		735		562
Other		14,807		8,947

Total	$	276,943	$	231,383

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ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Other current liabilities*

Other current liabilities as of September 30, 2005 and 2004 were comprised of the following accounts.


	September 30

	2005		2004

	(In thousands)
Customer deposits	$	89,918	$	44,474
Accrued employee costs		26,409		15,729
Deferred gas costs		134,048		54,514
Accrued interest		53,675		21,893
Liabilities from risk management activities		61,920		39,458
Taxes payable		66,083		22,930
Post-retirement obligations		5,300		5,300
Regulatory cost of removal accrual		11,565		7,653
Other		54,450		26,731

Total	$	503,368	$	238,682


	*Deferred credits and other liabilities*

Deferred credits and other liabilities as of September 30, 2005 and 2004 were comprised of the following accounts.


	September 30

	2005		2004

	(In thousands)
Post-retirement obligations	$	84,215	$	55,544
Nonqualified retirement plan obligation		54,901		49,279
Customer advances for construction		18,872		14,120
Liabilities from risk management activities		15,316		1,138
Deferred revenue		5,488		7,021
Regulatory liabilities		8,084		5,479
Other		12,739		10,555

Total	$	199,615	$	143,136

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


11.	Earnings Per Share

Basic and diluted earnings per share at September 30 are calculated as follows:


		2005		2004		2003

		(In thousands, except per share data)
Income before cumulative effect of accounting change		$	135,785	$	86,227	$	79,461
Cumulative effect of accounting change, net of income tax benefit			—		—		(7,773	)

Net income		$	135,785	$	86,227	$	71,688

Denominator for basic income per share — weighted average common shares			78,508		54,021		46,319
Effect of dilutive securities:
	Restricted and other shares		360		281		109
	Stock options		144		114		68

Denominator for diluted income per share — weighted average common shares			79,012		54,416		46,496

Income per share — basic:
	Before cumulative effect of accounting change	$	1.73	$	1.60	$	1.72
	Cumulative effect of accounting change, net of income tax benefit		—		—		(.17	)

	Net income per share	$	1.73	$	1.60	$	1.55

Income per share — diluted:
	Before cumulative effect of accounting change	$	1.72	$	1.58	$	1.71
	Cumulative effect of accounting change, net of income tax benefit		—		—		(.17	)

	Net income per share	$	1.72	$	1.58	$	1.54

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the year ended September 30, 2005. There were approximately 3,000 and 601,500 out-of-the-money options excluded from the computation of diluted earnings per share for the years ended September 30, 2004 and 2003 as their exercise price was greater than the average market price of the common stock during that period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


12.	Income Taxes

The components of income tax expense from continuing operations for 2005, 2004 and 2003 were as follows:


		2005			2004			2003

		(In thousands)
Current
	Federal	$	61,508		$	9,003		$	(13,446	)
	State		8,569			2,021			(441	)
Deferred
	Federal		11,453			35,970			54,656
	State		1,217			5,079			6,690
Investment tax credits			(514	)		(535	)		(549	)

		$	82,233		$	51,538		$	46,910

The provision (benefit) for income taxes is included in the consolidated financial statements as follows:


	2005		2004		2003

	(In thousands)
Income tax before cumulative effect of accounting change	$	82,233	$	51,538	$	46,910
Cumulative effect of accounting change		—		—		(5,117	)

Income tax expense	$	82,233	$	51,538	$	41,793

During 2003, we recorded a cumulative effect of accounting change to reflect the adoption of EITF 02-03, as described in Note 5. The $5.1 million benefit on the cumulative charge reflects a federal and state tax benefit of 39.7 percent.

Reconciliations of the provision for income taxes before the cumulative effect of accounting change computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2005, 2004 and 2003 are set forth below:


	2005			2004			2003

	(In thousands)
Tax at statutory rate of 35%	$	76,306		$	48,218		$	44,230
Common stock dividends deductible for tax reporting		(1,088	)		(985	)		(993	)
State taxes (net of federal benefit)		6,361			4,615			4,062
Other, net		654			(310	)		(389	)

Income tax expense	$	82,233		$	51,538		$	46,910

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that give rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2005 and 2004 are presented below:


			2005			2004

			(In thousands)
Deferred tax assets:
	Costs expensed for book purposes and capitalized for tax purposes		$	1,299		$	1,029
	Accruals not currently deductible for tax purposes			13,319			8,563
	Customer advances			8,455			5,579
	Nonqualified benefit plans			24,869			21,171
	Postretirement benefits			33,176			21,665
	Treasury lock agreement			14,698			13,035
	Unamortized investment tax credit			864			1,000
	Regulatory liabilities			9,836			1,192
	Tax net operating loss and credit carryforwards			855			15,761
	Gas cost adjustments			36,432			14,858
	Other, net			3,186			4,373

		Total deferred tax assets		146,989			108,226
Deferred tax liabilities:
	Difference in net book value and net tax value of assets			(299,188	)		(264,239	)
	Pension funding			(42,597	)		(43,798	)
	Regulatory assets			(13,021	)		(3,154	)
	Cost capitalized for book purposes and expensed for tax purposes			(2,739	)		(7,288	)
	Other, net			(14,286	)		(3,677	)

		Total deferred tax liabilities		(371,831	)		(322,156	)

Net deferred tax liabilities			$	(224,842	)	$	(213,930	)

SFAS No. 109 deferred credits for rate regulated entities			$	2,833		$	2,457

We have tax carryforwards amounting to $0.9 million. The tax carryforwards include capital losses for federal purposes amounting to $0.5 million and state net operating losses amounting to $0.4 million. The federal capital loss carryforwards will expire in 2007. Depending on the jurisdiction in which the net operating loss was generated, the state net operating losses will begin to expire between 2016 and 2021.

During fiscal 2003, the Internal Revenue Service initiated a routine examination of our fiscal 1999, 2000 and 2001 tax returns. The examination was successfully completed with no material impact to our financial position or results of operations.


13.	Commitments and Contingencies


	*Litigation*


	Colorado-Kansas Division

We are a defendant in a lawsuit filed by Quinque Operating Company, Tom Boles and Robert Ditto on September 23, 1999 in the District Court of Stevens County, Kansas against more than 200 companies in the natural gas industry as well as in another similar lawsuit entitled In Re Natural Gas Royalties Qui Tam

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Litigation, which was remanded to the same court in January 2001. The plaintiffs in these two lawsuits that have now been consolidated, who purport to represent a class of royalty owners, allege that the defendants have underpaid royalties on gas taken from wells situated on non-federal and non-Indian lands in Kansas, Colorado, and Wyoming, predicated upon allegations that the defendants’ gas measurements are inaccurate. The plaintiffs have not specifically alleged an amount of damages. The District Court denied an earlier motion in these proceedings to certify a class but gave plaintiffs permission to try to seek certification of a revised class, which we intend to oppose. We believe that the plaintiffs’ claims are lacking in merit, and we intend to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations, or net cash flows.


	West Texas Division

We were the plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc. and ONEOK Energy Marketing and Trading Company II, filed in December 2001, in the 72^nd Judicial District in the District Court of Lubbock County, Texas. This case was filed to recover damages resulting from various claims involving the sale, measurement, transportation and balancing of natural gas. This case and all related claims have been settled. The settlement did not have a material effect on our financial condition, results of operations or net cash flows.


	United Cities Propane Gas, Inc.

United Cities Propane Gas, Inc., one of our wholly-owned subsidiaries, is a party to an action filed in June 2000 that is pending in the Circuit Court of Sevier County, Tennessee. The plaintiffs’ claims arise out of injuries alleged to have been caused by a low-level propane explosion. The plaintiffs seek to recover damages of $13.0 million. Discovery activities continue in this case. We have denied any liability, and we intend to vigorously defend against the plaintiffs’ claims. This case has been set for trial in December 2005. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

We are a party to other litigation and claims that arose in the ordinary course of our business, including certain litigation and claims that arose in the ordinary course of the business of TXU Gas Company, the natural gas distribution and pipeline operations we acquired on October 1, 2004. While the results of such litigation and claims cannot be predicted with certainty, we believe the final outcome of such litigation and claims will not have a material adverse effect on our financial condition, results of operations or net cash flows.


	*Environmental Matters*


	Manufactured Gas Plant Sites

We are the owner or previous owner of manufactured gas plant sites in Johnson City and Bristol, Tennessee, and Hannibal, Missouri, which were used to supply gas prior to the availability of natural gas. The gas manufacturing process resulted in certain byproducts and residual materials, including coal tar. The manufacturing process used by our predecessors was an acceptable and satisfactory process at the time such operations were being conducted. Under current environmental protection laws and regulations, we may be responsible for response actions with respect to such materials if response actions are necessary.

United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of fiscal 1997,

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which will continue for the foreseeable future. The investigative phase of the work at the site has been completed, and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We completed a risk assessment report that has been approved by the TDEC as well as a feasibility study for this site, which was submitted to the TDEC in October 2003. The feasibility study recommends a remedial action that will limit the use of and access to the impacted soil, cap the site with the addition of a clay fill and geosynthetic liner, and groundwater monitoring for a period of up to 30 years. The feasibility study was approved by the TDEC in February 2005 and we are awaiting a Record of Decision from the TDEC. The estimated cost of the proposed remedial action is $1.5 million, which is comprised primarily of operating and maintenance costs that would be associated with a groundwater monitoring project. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements.

In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site, which we completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site, and we have proposed performing a focused removal action to remove any such residuals. The TDEC requested that the focused removal action be conducted pursuant to a voluntary agreement. On April 13, 2004, we entered into a voluntary consent agreement with the TDEC for the performance of the removal action and the removal action was completed in November 2004. In September 2005, we filed site use limitations on the property in the local property records, including restrictions on the use of the site to commercial and industrial purposes and a prohibition of the use of ground water for use as drinking water were filed.

On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources to address the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action and a subsequent site evaluation and to reimburse the response costs incurred by the state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site-evaluation field work was conducted in August 1999. A risk assessment for the site has been approved by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site-use limitations, including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water. In addition, we have installed a geosynthetic liner over the surface of the site.

In 1995, United Cities Gas Company entered into an agreement with a third party to resolve its share of the costs of additional investigations and environmental-response actions for soil contamination at a former manufactured gas plant in Keokuk, Iowa. However, the extent of groundwater contamination at the site, if any, which is not covered by the agreement, has yet to be determined.

As of September 30, 2005, we had incurred costs of approximately $2.2 million for the investigations of the Johnson City and Bristol, Tennessee, and Hannibal, Missouri sites.

We are a party to other environmental matters and claims that have arisen in the ordinary course of our business. While the ultimate results of response actions to these environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows because we believe that the expenditures related to such response actions will either be recovered through rates, shared with other parties or are adequately covered by insurance.

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	*Purchase Commitments*

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, 2005, AEM was committed to purchase 32.3 Bcf within one year, 29.2 Bcf within one to three years and 9.9 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year and 0.4 Bcf within one to three years under fixed price contracts with prices ranging from $5.24 to $17.50. Purchases under these contracts totaled $1,421.2 million, $1,252.2 million and $1,454.8 million for 2005, 2004 and 2003.

Our utility divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market prices. The estimated commitments under these contracts as of September 30, 2005 are as follows (in thousands):


2006	$	890,856
2007		196,501
2008		122,640
2009		13,532
2010		11,959
Thereafter		39,939

	$	1,275,427


	*Other*

During the third quarter of 2005, we entered into two agreements with third parties to transport natural gas through our Texas intrastate pipeline system beginning in fiscal 2006. To handle the increased volumes for these projects, we will install compression equipment and other pipeline infrastructure. We expect to spend approximately $32.0 million in 2006 for these projects.

On August 29, 2005, Hurricane Katrina struck the Gulf Coast, inflicting significant damage in our eastern Louisiana operations. The hardest hit areas in our service area were in Jefferson, St. Tammany, St. Bernard and Plaquemines parishes. In total, approximately 230,000 of our natural gas customers were affected in these areas. A significant number of these customers will not require gas service for some time because of sustained damages. We cannot predict with certainty how many of these customers will return to these service areas and over what time period. Additionally, we cannot accurately determine what regulatory actions, if any, may be taken by the regulators with respect to these areas. Finally, although we believe our insurance will cover all losses in excess of our deductible, it is possible that certain of these losses may not be fully recoverable.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


14.	Leases


	*Leasing Operations*

Atmos Power Systems, Inc. constructs electric peaking power generating plants and associated facilities and enters into agreements to either lease or sell these plants. We completed a sales-type lease transaction for one distributed electric generation plant in 2001 and a second sales-type lease transaction in 2003. In 2001, we recognized a gain of $0.8 million and deferred $4.7 million of income, which will be recognized using the interest method through August 2011. In 2003, we recognized a gain of $3.9 million and deferred $8.6 million in income, which will be recognized using the interest method through September 2012. As of September 30, 2005 and 2004, we recorded receivables of $22.4 million and $25.5 million and recorded income of $1.6 million, $1.9 million and $2.0 million for fiscal years 2005, 2004 and 2003. The future minimum lease payments to be received for each of the five succeeding years are as follows:


	Minimum
	Lease
	Receipts

	(In thousands)
2006	$	2,973
2007		2,973
2008		2,973
2009		2,973
2010		2,973
Thereafter		7,521

Total minimum lease receipts	$	22,386


	*Capital and Operating Leases*

We have entered into non-cancelable operating leases for office and warehouse space used in our operations. The remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. We have also entered into capital leases for division offices and operating facilities. Property, plant and equipment included amounts for capital leases of $5.8 million at both September 30, 2005 and 2004. Accumulated depreciation for these capital leases totaled $3.8 million and $2.4 million at September 30, 2005 and 2004. Depreciation expense for these assets is included in consolidated depreciation expense on the consolidated statement of income.

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The related future minimum lease payments at September 30, 2005 were as follows:


	Capital			Operating
	Leases			Leases

	(In thousands)
2006	$	631		$	15,327
2007		433			15,029
2008		362			14,432
2009		311			13,574
2010		291			12,619
Thereafter		1,376			92,453

Total minimum lease payments		3,404		$	163,434

Less amount representing interest		(1,449	)

Present value of net minimum lease payments	$	1,955

Consolidated lease and rental expense amounted to $9.5 million, $8.1 million and $8.9 million for fiscal 2005, 2004 and 2003.


15.	Concentration of Credit Risk

Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the utility segment is mitigated by the large number of individual customers and diversity in customer base. Due to minimal receivables, the credit risk for our other nonutility segment is not significant.

The diversification in AEM’s customers helps mitigate its credit exposure. AEM maintains credit policies with respect to its counterparties that it believes minimizes overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty’s financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. AEM also monitors the financial condition of existing counterparties on an ongoing basis. Customers not meeting minimum standards are required to provide adequate assurance of financial performance.

AEM maintains an allowance for credit losses based upon factors surrounding the credit risk of customers, historical trends and other information. We believe, based on our credit policies and our allowance for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of counterparty nonperformance.

AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable, (2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by the credit department, but are primarily based on external ratings provided by Moody’s Investor Service and/or Standard & Poor’s Rating Service. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

guaranteed industrials and commercials is non-investment grade. The table below shows the percentages related to the investment ratings as of September 30, 2005 and 2004.


		September 30,			September 30,
		2005			2004

Investment grade			49	%		55	%
Non-investment grade			51	%		45	%

	Total		100	%		100	%

The following table presents our derivative counterparty credit exposure by operating segment based upon the unrealized fair value of our derivative contracts that represent assets as of September 30, 2005. Investment grade counterparties have minimum credit ratings of BBB-, assigned by Standard & Poor’s Rating Group; or Baa3, assigned by Moody’s Investor Service. Non-investment grade counterparties are composed of counterparties that are below investment grade or that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is composed of numerous smaller counterparties, none of which is individually significant.


	At September 30, 2005

			Natural Gas
	Utility		Marketing
	Segment⁽¹⁾		Segment		Consolidated

	(In thousands)
Investment grade counterparties	$	93,310	$	12,291	$	105,601
Non-investment grade counterparties		—		3,047		3,047

	$	93,310	$	15,338	$	108,648


⁽¹⁾	Counterparty risk for our utility segment is minimized because hedging gains and losses are passed through to our customers.


16.	Supplemental Cash Flow Disclosures

Supplemental disclosures of cash flow information for 2005, 2004 and 2003 are presented below.


	2005		2004		2003

	(In thousands)
Cash paid for interest	$	103,418	$	65,700	$	62,088
Cash paid for income taxes	$	51,490	$	1,677	$	408

There were no significant noncash transactions during fiscal 2005 and 2004. In June 2003, we contributed to the Atmos Energy Corporation Master Retirement Trust for the benefit of the Atmos Pension Account Plan 1,169,700 shares of Atmos restricted common stock with a value of $28.8 million.


17.	Segment Information

Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain nonutility businesses. We distribute 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 located in 12 states. In addition, we transport natural gas for others through our distribution system.

Through our nonutility businesses, we provide natural gas management and marketing services to industrial customers, municipalities and other local distribution companies located in 22 states.

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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 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.

Effective October 1, 2004, we created the pipeline and storage segment which includes the regulated pipeline and storage operations of Atmos Pipeline — Texas Division and the nonregulated pipeline and storage operations of Atmos Pipeline and Storage, LLC, which was previously included in our other nonutility segment. Segment information for all prior year periods has been restated to reflect our new organizational structure.

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our utility segment operations are geographically dispersed, they are reported as a single segment as each utility division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate performance based on net income or loss of the respective operating units. Interest expense is allocated pro rata to each segment based upon our net investment in each segment. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.

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


			Year Ended September 30, 2005

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	3,102,041	$	1,783,926	$	85,333	$	2,026	$	—		$	4,973,326
Intersegment revenues				1,099		322,352		79,409		3,276		(406,136	)		—

				3,103,140		2,106,278		164,742		5,302		(406,136	)		4,973,326
Purchased gas cost				2,195,774		2,044,305		6,811		—		(402,654	)		3,844,236

	Gross profit			907,366		61,973		157,931		5,302		(3,482	)		1,129,090
Operating expenses
	Operation and maintenance			346,594		18,444		62,226		4,153		(3,683	)		427,734
	Depreciation and amortization			159,497		1,896		16,504		108		—			178,005
	Taxes, other than income			164,910		648		8,915		223		—			174,696

Total operating expenses				671,001		20,988		87,645		4,484		(3,683	)		780,435

Operating income				236,365		40,985		70,286		818		201			348,655
Miscellaneous income				6,776		771		2,030		2,575		(10,131	)		2,021
Interest charges				112,382		3,405		24,579		2,222		(9,930	)		132,658

Income before income taxes				130,759		38,351		47,737		1,171		—			218,018
Income tax expense				49,642		14,947		17,138		506		—			82,233

		Net income	$	81,117	$	23,404	$	30,599	$	665	$	—		$	135,785

Capital expenditures			$	300,574	$	649	$	31,960	$	—	$	—		$	333,183

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Year Ended September 30, 2004

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	1,636,636	$	1,279,424	$	1,617	$	2,360	$	—		$	2,920,037
Intersegment revenues				1,092		339,178		18,141		1,033		(359,444	)		—

				1,637,728		1,618,602		19,758		3,393		(359,444	)		2,920,037
Purchased gas cost				1,134,594		1,571,971		9,383		—		(358,102	)		2,357,846

	Gross profit			503,134		46,631		10,375		3,393		(1,342	)		562,191
Operating expenses
	Operation and maintenance			195,471		15,692		2,533		2,150		(1,376	)		214,470
	Depreciation and amortization			92,954		2,089		1,488		116		—			96,647
	Taxes, other than income			54,819		1,124		1,061		375		—			57,379

Total operating expenses				343,244		18,905		5,082		2,641		(1,376	)		368,496

Operating income				159,890		27,726		5,293		752		34			193,695
Miscellaneous income				5,847		843		289		8,290		(5,762	)		9,507
Interest charges				65,399		2,711		1,053		2,002		(5,728	)		65,437

Income before income taxes				100,338		25,858		4,529		7,040		—			137,765
Income tax expense				37,242		9,225		1,762		3,309		—			51,538

		Net income	$	63,096	$	16,633	$	2,767	$	3,731	$	—		$	86,227

Capital expenditures			$	189,291	$	520	$	474	$	—	$	—		$	190,285

115

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Year Ended September 30, 2003

						Natural Gas			Pipeline		Other
			Utility			Marketing			and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	1,552,857		$	1,234,447		$	11,280	$	1,332	$	—		$	2,799,916
Intersegment revenues				1,225			434,046			9,018		1,521		(445,810	)		—

				1,554,082			1,668,493			20,298		2,853		(445,810	)		2,799,916
Purchased gas cost				1,062,679			1,644,328			3,061		—		(445,128	)		2,264,940

	Gross profit			491,403			24,165			17,237		2,853		(682	)		534,976
Operating expenses
	Operation and maintenance			193,108			8,608			2,780		1,276		(682	)		205,090
	Depreciation and amortization			83,849			1,261			1,742		149		—			87,001
	Taxes, other than income			53,312			727			901		105		—			55,045

Total operating expenses				330,269			10,596			5,423		1,530		(682	)		347,136

Operating income				161,134			13,569			11,814		1,323		—			187,840
Miscellaneous income (expense)				(218	)		1,855			52		6,468		(5,966	)		2,191
Interest charges				63,226			2,864			1,175		2,361		(5,966	)		63,660

Income before income taxes and cumulative effect of accounting change				97,690			12,560			10,691		5,430		—			126,371
Income tax expense				35,553			5,757			4,229		1,371		—			46,910

Income before cumulative effect of accounting change				62,137			6,803			6,462		4,059		—			79,461
Cumulative effect of accounting change, net of income tax benefit				—			(7,773	)		—		—		—			(7,773	)

		Net income (loss)	$	62,137		$	(970	)	$	6,462	$	4,059	$	—		$	71,688

Capital expenditures			$	154,777		$	1,884		$	2,450	$	328	$	—		$	159,439

116

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


				2005		2004		2003

				(In thousands)
Utility revenues:
	Gas sales revenues:
		Residential		$	1,791,172	$	923,773	$	873,375
		Commercial			869,722		400,704		367,961
		Industrial			229,649		155,336		151,969
		Agricultural			27,889		31,851		48,625
		Public authority and other			86,853		77,178		65,921

			Total gas sales revenues		3,005,285		1,588,842		1,507,851
	Transportation revenues				58,897		30,622		29,236
	Other gas revenues				37,859		17,172		15,770

		Total utility revenues			3,102,041		1,636,636		1,552,857
Natural gas marketing revenues					1,783,926		1,279,424		1,234,447
Pipeline and storage revenues					85,333		1,617		11,280
Other nonutility revenues					2,026		2,360		1,332

		Total operating revenues		$	4,973,326	$	2,920,037	$	2,799,916

117

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at September 30, 2005 and 2004 by segment is presented in the following tables:


			September 30, 2005

					Natural			Pipeline
					Gas			and		Other
			Utility		Marketing			Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
ASSETS

Property, plant and equipment, net			$	2,926,096	$	7,278		$	439,574	$	1,419	$	—		$	3,374,367
Investment in subsidiaries				231,342		(1,896	)		—		—		(229,446	)		—
Current assets
	Cash and cash equivalents			10,663		28,949			—		504		—			40,116
	Cash held on deposit in margin account			4,170		76,786			—		—		—			80,956
	Assets from risk management activities			93,310		39,528			1,739		—		(26,664	)		107,913
	Other current assets			666,081		421,777			36,208		63,820		(152,441	)		1,035,445
	Intercompany receivables			505,728		—			—		20,133		(525,861	)		—

		Total current assets		1,279,952		567,040			37,947		84,457		(704,966	)		1,264,430
Intangible assets				—		3,507			—		—		—			3,507
Goodwill				566,800		24,282			143,198		—		—			734,280
Noncurrent assets from risk management activities				—		2,073			1,338		—		(2,676	)		735
Deferred charges and other assets				249,179		1,461			5,737		19,831		—			276,208

			$	5,253,369	$	603,745		$	627,794	$	105,707	$	(937,088	)	$	5,653,527

CAPITALIZATION AND LIABILITIES

Shareholders’ equity			$	1,602,422	$	144,827		$	53,426	$	33,089	$	(231,342	)	$	1,602,422
Long-term debt				2,177,279		—			—		5,825		—			2,183,104

		Total capitalization		3,779,701		144,827			53,426		38,914		(231,342	)		3,785,526
Current liabilities
	Current maturities of long-term debt			1,250		—			—		2,014		—			3,264
	Short-term debt			144,809		60,000			—		51,320		(111,320	)		144,809
	Liabilities from risk management activities			—		63,936			25,038		—		(27,054	)		61,920
	Other current liabilities			623,300		217,777			95,557		4,963		(38,835	)		902,762
	Intercompany payables			—		87,968			437,893		—		(525,861	)		—

		Total current liabilities		769,359		429,681			558,488		58,297		(703,070	)		1,112,755
Deferred income taxes				268,108		12,369			9,563		2,167		—			292,207
Noncurrent liabilities from risk management activities				—		16,654			1,338		—		(2,676	)		15,316
Regulatory cost of removal obligation				263,424		—			—		—		—			263,424
Deferred credits and other liabilities				172,777		214			4,979		6,329		—			184,299

			$	5,253,369	$	603,745		$	627,794	$	105,707	$	(937,088	)	$	5,653,527

118

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			September 30, 2004

					Natural			Pipeline
					Gas			and		Other
			Utility		Marketing			Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
ASSETS

Property, plant and equipment, net			$	1,669,304	$	7,875		$	43,784	$	1,558	$	—		$	1,722,521
Investment in subsidiaries				164,300		(1,484	)		—		—		(162,816	)		—
Current assets
	Cash and cash equivalents			182,846		18,734			—		352		—			201,932
	Assets from risk management activities			25,692		24,412			—		—		(5,664	)		44,440
	Other current assets			284,474		176,623			12,628		18,838		(25,740	)		466,823
	Intercompany receivables			1,995		—			—		16,079		(18,074	)		—

		Total current assets		495,007		219,769			12,628		35,269		(49,478	)		713,195
Intangible assets				—		4,160			—		—		—			4,160
Goodwill				206,656		24,282			10,430		—		—			241,368
Noncurrent assets from risk management activities				—		734			—		—		(172	)		562
Deferred charges and other assets				206,424		1,661			25		22,711		—			230,821

			$	2,741,691	$	256,997		$	66,867	$	59,538	$	(212,466	)	$	2,912,627

CAPITALIZATION AND LIABILITIES

Shareholders’ equity			$	1,133,459	$	103,376		$	28,499	$	32,425	$	(164,300	)	$	1,133,459
Long-term debt				853,472		—			—		7,839		—			861,311

		Total capitalization		1,986,931		103,376			28,499		40,264		(164,300	)		1,994,770
Current liabilities
Current maturities of long-term debt				3,917		—			—		1,991		—			5,908
	Short-term debt			—		—			—		—		—			—
	Liabilities from risk management activities			34,304		11,407			—		—		(6,253	)		39,458
	Other current liabilities			251,674		124,577			24,014		7,558		(23,304	)		384,519
	Intercompany payables			—		9,906			8,168		—		(18,074	)		—

		Total current liabilities		289,895		145,890			32,182		9,549		(47,631	)		429,885
Deferred income taxes				230,214		2,900			6,116		2,000		27			241,257
Noncurrent liabilities from risk management activities				—		1,700			—		—		(562	)		1,138
Regulatory cost of removal obligation				103,579		—			—		—		—			103,579
Deferred credits and other liabilities				131,072		3,131			70		7,725		—			141,998

			$	2,741,691	$	256,997		$	66,867	$	59,538	$	(212,466	)	$	2,912,627

119

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


18.	Related Party Transactions

AEM provides a variety of natural gas management services to our Kentucky, Louisiana and Mid-States divisions including furnishing natural gas supplies at fixed and market-based prices and the management of certain of our underground storage facilities. Additionally, at times, AEM places financial instruments for our various divisions to partially insulate us and our customers from gas price volatility.

Atmos Pipeline and Storage, L.L.C. provides asset management services for certain of our utility storage fields in exchange for a contractually negotiated demand charge. The Atmos Pipeline — Texas Division, a division of Atmos, provides natural gas transportation services to our Atmos Energy Mid-Tex Division.

Atmos Energy Services, L.L.C., provides natural gas management services for our own utility operations, other than the Mid-Tex Division. Prior to the second quarter of fiscal 2004, this entity conducted limited operations. However, beginning April 1, 2004, AES began providing natural gas supply management services to our utility operations in a limited number of states. These services 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 following summarizes our significant affiliate transactions with AEM, APS and AES.


		2005		2004		2003

		(In thousands, unless otherwise indicated)
Gas purchases⁽¹⁾:
	Dollars	$	227,315	$	235,320	$	333,390
	Volumes (Mcf)		31,370		42,518		62,729
	Average sales price per Mcf	$	7.25	$	5.53	$	5.31
Storage contract fees		$	1,753	$	2,765	$	4,236
Natural gas management services		$	2,986	$	682	$	—


⁽¹⁾	Gas purchases are made in a competitive bidding process, reflect market prices and exclude demand and other charges.

JD Woodward became Senior Vice President, Nonutility Operations of the Company on April 1, 2001. Woodward Marketing L.L.C., a wholly-owned subsidiary of the Company through September 30, 2003 and its successor, AEM, leases office space from one corporation owned by Mr. Woodward. The lease originated in April 2002 and expires in March 2007. Base lease payments were $225,000 in the first year of the lease and increase to $336,000 in the final year.

During 2005, 2004 and 2003, our utility division leased office space and vehicles from our natural gas marketing and other nonutility segments. Base lease payments were $1.0 million in 2005 and $1.2 million in 2004 and 2003.

120

ATMOS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


19.	Selected Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section herein.


			Quarter Ended

			December 31			March 31			June 30			September 30

			(In thousands, except per share data)
Fiscal year 2005:
	Operating revenues
		Utility segment	$	913,681		$	1,235,377		$	501,735		$	452,347
		Natural gas marketing segment		493,801			512,891			466,835			632,751
		Pipeline and storage segment		46,039			48,235			36,524			33,944
		Other nonutility segment		1,359			1,278			1,421			1,244
		Intersegment eliminations		(83,907	)		(110,007	)		(96,563	)		(115,659	)

				1,370,973			1,687,774			909,952			1,004,627
	Gross profit			324,452			378,583			224,349			201,706
	Operating income			128,674			172,181			39,468			8,332
	Net income (loss)			59,599			88,502			4,486			(16,802	)
	Net income (loss) per basic share		$	0.79		$	1.12		$	0.06		$	(0.21	)
	Net income (loss) per diluted share		$	0.79		$	1.11		$	0.06		$	(0.21	)
Fiscal year 2004:
	Operating revenues
		Utility segment	$	460,488		$	708,282		$	256,252		$	212,706
		Natural gas marketing segment		373,829			517,218			364,339			363,216
		Pipeline and storage segment		2,919			9,967			5,357			1,515
		Other nonutility segment		709			687			853			1,144
		Intersegment eliminations		(74,329	)		(118,669	)		(80,743	)		(85,703	)

				763,616			1,117,485			546,058			492,878
	Gross profit			159,053			206,126			107,492			89,520
	Operating income			63,541			105,414			21,460			3,280
	Net income (loss)			29,541			58,305			4,765			(6,384	)
	Net income (loss) per basic share		$	0.57		$	1.12		$	0.09		$	(0.11	)
	Net income (loss) per diluted share		$	0.57		$	1.12		$	0.09		$	(0.11	)

121


ITEM 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

None.


ITEM 9A.	*Controls and Procedures*

Management’s Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit to the United States Securities and Exchange Commission under the Securities and Exchange Act of 1934, as amended (the “Act”), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Under the supervision and with the participation of senior management, including our Chairman, President and Chief Executive Officer (“Principal Executive Officer”) and our Senior Vice President and Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2005 to ensure the timely disclosure of required information in our periodic Securities and Exchange Commission filings.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework issued by COSO and applicable Securities and Exchange Commission rules, our management concluded that our internal control over financial reporting was effective as of September 30, 2005.

Ernst & Young LLP has issued its report on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting. That report appears below.


/s/ ROBERT W. BEST ____________________________________________________ Robert W. Best Chairman, President and Chief Executive Officer		/s/ JOHN P. REDDY ____________________________________________________ John P. Reddy Senior Vice President and Chief Financial Officer

November 16, 2005

122

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors

Atmos Energy Corporation

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Atmos Energy Corporation maintained effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Atmos Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Atmos Energy Corporation maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Atmos Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Atmos Energy Corporation as of September 30, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2005 of Atmos Energy Corporation and our report dated November 16, 2005 expressed an unqualified opinion thereon.


	ERNST & YOUNG LLP

Dallas, Texas

November 16, 2005

123

Changes in Internal Control over Financial Reporting

We have not made any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the fourth quarter of the fiscal year ended September 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B.	*Other Information*

Not applicable.

PART III


ITEM 10.	*Directors and Executive Officers of the Registrant*

Information regarding directors and compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006. Information regarding executive officers is included in Part I of this Form 10-K.

Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors’ determination as to whether one or more audit committee financial experts is serving on the Audit Committee of the Board of Directors is incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006.

The Company has adopted a code of ethics for its principal executive officer and senior financial officers. Such code of ethics is represented by the Company’s Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Company’s principal executive officer and senior financial officers. A copy of the Company’s Code of Conduct is posted on the Company’s website at www.atmosenergy.com under “Corporate Governance”. In addition, any amendment to or waiver granted from, a provision of the Company’s Code of Conduct will be posted on the Company’s website under “Corporate Governance”.


ITEM 11.	*Executive Compensation*

Incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006.


ITEM 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*

Security ownership of certain beneficial owners and of management is incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006. Information concerning our equity compensation plan is provided in Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, of this Annual Report on Form 10-K.


ITEM 13.	*Certain Relationships and Related Transactions*

Incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006.

124


ITEM 14.	*Principal Accountant Fees and Services*

Incorporated herein by reference from the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 8, 2006.

PART IV


ITEM 15.	*Exhibits and Financial Statement Schedules*

(a) 1. and 2. Financial statements and financial statement schedules.

The financial statements and financial statement schedule listed in the Index to Financial Statements in Item 8 are filed as part of this Form 10-K.

3. Exhibits

The exhibits listed in the accompanying Exhibits Index are filed as part of this Form 10-K. The exhibits numbered 10.7(a) through 10.16(e) are management contracts or compensatory plans or arrangements.

125

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	ATMOS ENERGY CORPORATION
	(Registrant)


	By:	/s/ JOHN P. REDDY



	John P. Reddy
	Senior Vice President and
	Chief Financial Officer

Date: November 18, 2005

126

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Robert W. Best and John P. Reddy, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:



/s/ ROBERT W. BEST Robert W. Best	Chairman, President and Chief Executive Officer	November 18, 2005

/s/ JOHN P. REDDY John P. Reddy	Senior Vice President and Chief Financial Officer	November 18, 2005

/s/ F.E. MEISENHEIMER F.E. Meisenheimer	Vice President and Controller (Principal Accounting Officer)	November 18, 2005

/s/ TRAVIS W. BAIN, II Travis W. Bain, II	Director	November 18, 2005

/s/ DAN BUSBEE Dan Busbee	Director	November 18, 2005

/s/ RICHARD W. CARDIN Richard W. Cardin	Director	November 18, 2005

/s/ THOMAS J. GARLAND Thomas J. Garland	Director	November 18, 2005

/s/ RICHARD K. GORDON Richard K. Gordon	Director	November 18, 2005

/s/ GENE C. KOONCE Gene C. Koonce	Director	November 18, 2005

/s/ THOMAS C. MEREDITH Thomas C. Meredith	Director	November 18, 2005

127



/s/ PHILLIP E. NICHOL Phillip E. Nichol	Director	November 18, 2005

/s/ NANCY K. QUINN Nancy K. Quinn	Director	November 18, 2005

/s/ STEPHEN R. SPRINGER Stephen R. Springer	Director	November 18, 2005

/s/ CHARLES K. VAUGHAN Charles K. Vaughan	Director	November 18, 2005

/s/ RICHARD WARE II Richard Ware II	Director	November 18, 2005

128

Schedule II

ATMOS ENERGY CORPORATION

Valuation and Qualifying Accounts

Three Years Ended September 30, 2005


				Additions

		Balance at		Charged to		Charged to						Balance
		Beginning		Cost &		Other						at End
		of Period		Expenses		Accounts			Deductions			of Period

		(In thousands)
2005
	Allowance for doubtful accounts	$	7,214	$	20,293	$	4,563	⁽¹⁾	$	16,457	⁽²⁾	$	15,613
2004
	Allowance for doubtful accounts	$	13,051	$	5,379	$	—		$	11,216	⁽²⁾	$	7,214
2003
	Allowance for doubtful accounts	$	10,509	$	13,249	$	—		$	10,707	⁽²⁾	$	13,051


⁽¹⁾	Represents allowance for doubtful accounts recorded in connection with the TXU Gas acquisition.

⁽²⁾	Uncollectible accounts written off.

129

EXHIBITS INDEX

Item 14.(a)(3)


Exhibit				Page Number or
Number			Description	Incorporation by Reference to

			Plan of Reorganization

	2	.1(a)	Agreement and Plan of Merger by and between TXU Gas Company and LSG Acquisition Corporation dated June 17, 2004	Exhibit 2.1 of Form 8-K dated June 17, 2004 (File No. 1-10042)

	2	.1(b)	Amendment No. 1 to Merger Agreement, dated as of September 30, 2004, by and between LSG Acquisition Corporation and TXU Gas Company LP Articles of Incorporation and Bylaws	Exhibit 2.1 of Form 8-K dated September 30, 2004 (File No. 1-10042)

	3	.1	Amended and Restated Articles of Incorporation of Atmos Energy Corporation (as of February 9, 2005)	Exhibit 3(I) of Form 10-Q dated March 31, 2005 (File No. 1-10042)

	3	.2	Amended and Restated Bylaws of Atmos Energy Corporation (as of August 13, 2003)	Exhibit 4.2 of Form S-3 dated August 31, 2004 (File No. 333-118706)

			Instruments Defining Rights of Security Holders

	4	.1	Specimen Common Stock Certificate (Atmos Energy Corporation)	Exhibit (4)(b) of Form 10-K for fiscal year ended September 30, 1988 (File No. 1-10042)

	4	.2	Rights Agreement, dated as of November 12, 1997, between the Company and BankBoston, N.A., as Rights Agent	Exhibit 4.1 of Form 8-K dated November 12, 1997 (File No. 1-10042)

	4	.3	First Amendment to Rights Agreement dated as of August 11, 1999, between the Company and BankBoston, N.A., as Rights Agent	Exhibit 2 of Form 8-A, Amendment No. 1, dated August 12, 1999 (File No. 1-10042)

	4	.4	Second Amendment to Rights Agreement dated as of February 13, 2002, between the Company and EquiServe Trust Company, N.A., fka BankBoston, N.A., as Rights Agent	Exhibit 4 of Form 10-Q for quarter ended December 31, 2001 (File No. 1-10042)

	4	.5	Registration Rights Agreement, dated as of December 3, 2002, by and among Atmos Energy Corporation and the Shareholders of Mississippi Valley Gas Company	Exhibit 99.2 of Form 8-K/A, dated December 3, 2002 (File No. 1-10042)

	4	.6	Standstill Agreement, dated as of December 3, 2002, by and among Atmos Energy Corporation and the Shareholders of Mississippi Valley Gas Company	Exhibit 99.3 of Form 8-K/A, dated December 3, 2002 (File No. 1-10042)

	4	.7	Indenture dated as of July 15, 1998 between Atmos Energy Corporation and U.S. Bank Trust National Association, Trustee	Exhibit 4.8 of Form S-3 dated August 31, 2004 (File No. 333-118706)

	4	.8	Indenture between Atmos Energy Corporation, as Issuer, and SunTrust Bank, Trustee dated as of May 22, 2001	Exhibit 99.3 of Form 8-K dated May 15, 2001 (File No. 1-10042)

130


Exhibit				Page Number or
Number			Description	Incorporation by Reference to


	4	.9(a)	Indenture of Mortgage, dated as of July 15, 1959, from United Cities Gas Company to First Trust of Illinois, National Association, and M.J. Kruger, as Trustees, as amended and supplemented through December 1, 1992 (the Indenture of Mortgage through the 20th Supplemental Indenture)	Exhibit to Registration Statement of United Cities Gas Company on Form S-3 (File No. 33-56983)

	4	.9(b)	Twenty-First Supplemental Indenture dated as of February 5, 1997 by and among United Cities Gas Company and Bank of America Illinois and First Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959	Exhibit 10.7(a) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)

	4	.9(c)	Twenty-Second Supplemental Indenture dated as of July 29, 1997 by and among Atmos Energy Corporation and First Trust National Association and Russell C. Bergman supplementing Indenture of Mortgage dated as of July 15, 1959	Exhibit 4.10(c) of Form S-3 dated August 31, 2004 (File No. 333-118706)

	4	.10(a)	Indenture between United Cities Gas Company and Bank of America Illinois, as Trustee dated as of November 15, 1995	Exhibit 4.11(a) of Form S-3 dated August 31, 2004 (File No. 333-118706)

	4	.10(b)	First Supplemental Indenture between Atmos Energy Corporation and Bank of America Illinois, as Trustee dated as of July 29, 1997	Exhibit 4.11(b) of Form S-3 dated August 31, 2004 (File No. 333-118706)

			Material Contracts

	10	.1(a)	Debenture Certificate for the 6³/4% Debentures due 2028	Exhibit 99.2 of Form 8-K dated July 22, 1998 (File No. 1-10042)

	10	.1(b)	Global Security for the 7³/8% Senior Notes due 2011	Exhibit 99.2 of Form 8-K dated May 15, 2001 (File No. 1-10042)

	10	.1(c)	Global Security for the 5¹/8% Senior Notes due 2013	Exhibit 10(2)(c) of Form 10-K for the year ended September 30, 2004 (File No. 1-10042)

	10	.1(d)	Global Security for the Floating Rate Senior Notes due 2007	Exhibit 10(2)(d) of Form 10-K for the year ended September 30, 2004 (File No. 1-10042)

	10	.1(e)	Global Security for the 4.00% Senior Notes due 2009	Exhibit 10(2)(e) of Form 10-K for the year ended September 30, 2004 (File No. 1-10042)

	10	.1(f)	Global Security for the 4.95% Senior Notes due 2014	Exhibit 10(2)(f) of Form 10-K for the year ended September 30, 2004 (File No. 1-10042)

	10	.1(g)	Global Security for the 5.95% Senior Notes due 2034	Exhibit 10(2)(g) of Form 10-K for the year ended September 30, 2004 (File No. 1-10042)

	10	.2	Revolving Credit Agreement (3 Year Facility), dated as of October 18, 2005, among Atmos Energy Corporation, SunTrust Bank, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent and Bank of America, N.A., Wachovia Bank, National Association and Societe Generale, as Co-Documentation Agents, and the lenders from time to time parties thereto	Exhibit 10.1 of Form 8-K dated October 18, 2005 (File No. 1-10042)

131


Exhibit				Page Number or
Number			Description	Incorporation by Reference to


	10	.3	Revolving Credit Agreement (364 Day Facility), dated as of November 10, 2005, among Atmos Energy Corporation, SunTrust Bank, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent and Bank of America, N.A., Wachovia Bank, National Association and Societe Generale, as Co-Documentation Agents, and the lenders from time to time parties thereto	Exhibit 10.1 of Form 8-K dated November 8, 2005 (File No. 1-10042)

	10	.4	Guaranty of Atmos Energy Corporation dated June 17, 2004	Exhibit 10.2 of Form 8-K dated June 17, 2004 (File No. 1-10042)

	10	.5(a)	Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation and TXU Gas Company LP	Exhibit 10.1 of Form 8-K dated September 30, 2004 (File No. 1-10042)

	10	.5(b)	Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation, Oncor Utility Solutions (Texas) Company and TXU Electric Delivery Company	Exhibit 10.2 of Form 8-K dated September 30, 2004 (File No. 1-10042)

	10	.5(c)	Transitional Services Agreement, dated as of October 1, 2004, by and between Atmos Energy Corporation and TXU Business Services Company (Exhibit A to Schedule 2 containing listing of employee credit and procurement cards is omitted, to be supplementally furnished to the Commission upon request)	Exhibit 10.3 of Form 8-K dated September 30, 2004 (File No. 1-10042)

	10	.5(d)	Transitional Access Agreement, dated as of October 1, 2004, by and among Atmos Energy Corporation and TXU Energy Retail Company LP, TXU Business Services Company, TXU Properties Company and TXU Electric Delivery Company	Exhibit 10.4 of Form 8-K dated September 30, 2004 (File No. 1-10042)

	10	.6	Uncommitted Second Amended and Restated Credit Agreement, dated to be effective March 30, 2005, among Atmos Energy Marketing, LLC, Fortis Capital Corp., BNP Paribas and the other financial institutions which may become parties hereto	Exhibit 10.1 of Form 8-K dated March 30, 2005 (File No. 1-10042)

			Executive Compensation Plans and Arrangements

	10	.7(a)*	Form of Atmos Energy Corporation Change in Control Severance Agreement — Tier I	Exhibit 10.21(b) of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042)

	10	.7(b)*	Form of Atmos Energy Corporation Change in Control Severance Agreement — Tier II	Exhibit 10.21(c) of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042)

	10	.8*	Atmos Energy Corporation Long-Term Stock Plan for the United Cities Gas Company Division	Exhibit 99.1 of Form S-8 filed July 29, 1997 (File No. 333-32343)

	10	.9(a)*	Atmos Energy Corporation Executive Retiree Life Plan	Exhibit 10.31 of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)

132


Exhibit				Page Number or
Number			Description	Incorporation by Reference to


	10	.9(b)*	Amendment No. 1 to the Atmos Energy Corporation Executive Retiree Life Plan	Exhibit 10.31(a) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)

	10	.10(a)*	Description of Financial and Estate Planning Program	Exhibit 10.25(b) of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)

	10	.10(b)*	Description of Sporting Events Program	Exhibit 10.26(c) of Form 10-K for fiscal year ended September 30, 1993 (File No. 1-10042)

	10	.11(a)*	Atmos Energy Corporation Supplemental Executive Benefits Plan, Amended and Restated in its Entirety August 12, 1998	Exhibit 10.26 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042)

	10	.11(b)*	Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan, Effective Date August 12, 1998	Exhibit 10.32 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042)

	10	.11(c)*	Amendment No. One to the Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan, Effective Date January 1, 1999	Exhibit 10.2 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042)

	10	.11(d)*	Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000	Exhibit 10.1 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042)

	10	.11(e)*	Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan	Exhibit 10.3 of Form 10-Q for quarter ended December 31, 2000 (File No. 1-10042)

	10	.12*	Atmos Energy Corporation Executive Nonqualified Deferred Compensation Plan	Exhibit 10.33 of Form 10-K for fiscal year ended September 30, 1998 (File No. 1-10042)

	10	.13(a)*	Mini-Med/ Dental Benefit Extension Agreement dated October 1, 1994	Exhibit 10.28(f) of Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042)

	10	.13(b)*	Amendment No. 1 to Mini-Med/ Dental Benefit Extension Agreement dated August 14, 2001	Exhibit 10.28(g) of Form 10-K for fiscal year ended September 30, 2001 (File No. 1-10042)

	10	.13(c)*	Amendment No. 2 to Mini-Med/ Dental Benefit Extension Agreement dated December 31, 2002	Exhibit 10.1 of Form 10-Q for quarter ended December 31, 2002 (File No. 1-10042)

	10	.14*	Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors	Exhibit C of Definitive Proxy Statement on Schedule 14A filed December 30, 1998 (File No. 1-10042)

	10	.15*	Atmos Energy Corporation Outside Directors Stock-for-Fee Plan (Amended and Restated as of November 12, 1997)	Exhibit 10.28 of Form 10-K for fiscal year ended September 30, 1997 (File No. 1-10042)

	10	.16(a)*	Atmos Energy Corporation 1998 Long-Term Incentive Plan (as amended and restated February 14, 2002)	Exhibit 10.1 of Form 10-Q for quarter ended March 31, 2002 (File No. 1-10042)

	10	.16(b)*	Form of Non-Qualified Stock Option Agreement under the Atmos Energy Corporation 1998 Long-Term Incentive Plan

	10	.16(c)*	Form of Award Agreement of Restricted Stock With Time-Lapse Vesting under the Atmos Energy Corporation 1998 Long-Term Incentive Plan

133


Exhibit				Page Number or
Number			Description	Incorporation by Reference to


	10	.16(d)*	Form of Award Agreement of Performance-Based Restricted Stock Units under the Atmos Energy Corporation 1998 Long-Term Incentive Plan

	10	.16(e)*	Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated February 14, 2002)	Exhibit 10.2 of Form 10-Q for quarter ended March 31, 2002 (File No. 1-10042)

	12		Statement of computation of ratio of earnings to fixed charges

			Other Exhibits, as indicated

	21		Subsidiaries of the registrant

	23		Consent of independent registered public accounting firm, Ernst & Young LLP

	24		Power of Attorney	Signature page of Form 10-K for fiscal year ended September 30, 2005

	31		Rule 13a-14(a)/15d-14(a) Certifications

	32		Section 1350 Certifications **


	*	This exhibit constitutes a “management contract or compensatory plan, contract, or arrangement.”

These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Annual Report on Form 10-K, will not be deemed to be filed with the Securities and Exchange Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

134