Atmos Energy 10Q 2005 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

		For the quarterly period ended March 31, 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)

(972) 934-9227

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Number of shares outstanding of each of the issuer’s classes of common stock, as of April 25, 2005.


Class		Shares Outstanding

No Par Value		79,939,319

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONDENSED CONSOLIDATED BALANCE SHEETS
		CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		CONDENSED CONSOLIDATED STATEMENTS OF INCOME
		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
		NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) March 31, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures about Market Risk
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits
SIGNATURES
EXHIBITS INDEX Item 6(a)
Amended and Restated Articles of Incorporation
Computation of Ratio of Earnings to Fixed Charges
Letter Regarding Unaudited Interim Financial Information
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications

PART 1. FINANCIAL INFORMATION


Item 1.	*Financial Statements*

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


				March 31,			September 30,
				2005			2004

				(Unaudited)
				(In thousands, except
				share data)
ASSETS
Property, plant and equipment				$	4,606,713		$	2,633,651
	Less accumulated depreciation and amortization				1,355,118			911,130

		Net property, plant and equipment			3,251,595			1,722,521
Current assets
	Cash and cash equivalents				247,126			201,932
	Cash held on deposit in margin account				16,990			—
	Accounts receivable, net				527,411			211,810
	Gas stored underground				273,811			200,134
	Other current assets				112,428			63,236

		Total current assets			1,177,766			677,112
Goodwill and intangible assets					722,044			238,272
Deferred charges and other assets			��		261,039			231,978

				$	5,412,444		$	2,869,883

CAPITALIZATION AND LIABILITIES
Shareholders’ equity
	Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding:
		March 31, 2005 — 79,877,473 shares;
		September 30, 2004 — 62,799,710 shares		$	399		$	314
	Additional paid-in capital				1,408,721			1,005,644
	Retained earnings				240,920			142,030
	Accumulated other comprehensive loss				(17,770	)		(14,529	)

		Shareholders’ equity			1,632,270			1,133,459
Long-term debt					2,254,817			861,311

		Total capitalization			3,887,087			1,994,770
Current liabilities
	Accounts payable and accrued liabilities				533,232			185,295
	Other current liabilities				298,802			223,265
	Current maturities of long-term debt				5,887			5,908

		Total current liabilities			837,921			414,468
Deferred income taxes					245,836			213,930
Regulatory cost of removal obligation					246,285			103,579
Deferred credits and other liabilities					195,315			143,136

				$	5,412,444		$	2,869,883

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


			Three Months Ended
			March 31

			2005			2004

			(Unaudited)
			(In thousands, except per
			share data)
Operating revenues
	Utility segment		$	1,235,377		$	708,282
	Natural gas marketing segment			512,891			517,218
	Pipeline and storage segment			45,546			9,967
	Other nonutility segment			1,278			687
	Intersegment eliminations			(110,007	)		(118,669	)

				1,685,085			1,117,485
Purchased gas cost
	Utility segment			912,309			518,820
	Natural gas marketing segment			501,731			505,356
	Pipeline and storage segment			1,718			5,681
	Other nonutility segment			—			—
	Intersegment eliminations			(109,256	)		(118,498	)

				1,306,502			911,359

	Gross profit			378,583			206,126
Operating expenses
	Operation and maintenance			106,109			59,093
	Depreciation and amortization			45,326			23,138
	Taxes, other than income			54,967			18,481

		Total operating expenses		206,402			100,712

Operating income				172,181			105,414
Miscellaneous income				958			4,456
Interest charges				33,073			16,160

Income before income taxes				140,066			93,710
Income tax expense				51,564			35,405

		Net income	$	88,502		$	58,305

Basic net income per share			$	1.12		$	1.12

Diluted net income per share			$	1.11		$	1.12

Cash dividends per share			$	0.310		$	0.305

Weighted average shares outstanding:
	Basic			79,270			51,850

	Diluted			79,760			52,240

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


			Six Months Ended
			March 31

			2005			2004

			(Unaudited)
			(In thousands, except per
			share data)
Operating revenues
	Utility segment		$	2,149,058		$	1,168,770
	Natural gas marketing segment			1,006,692			891,047
	Pipeline and storage segment			89,236			12,886
	Other nonutility segment			2,637			1,396
	Intersegment eliminations			(193,914	)		(192,998	)

				3,053,709			1,881,101
Purchased gas cost
	Utility segment			1,568,679			840,884
	Natural gas marketing segment			968,688			861,687
	Pipeline and storage segment			5,590			6,008
	Other nonutility segment			—			—
	Intersegment eliminations			(192,283	)		(192,657	)

				2,350,674			1,515,922

	Gross profit			703,035			365,179
Operating expenses
	Operation and maintenance			219,235			116,009
	Depreciation and amortization			89,323			46,611
	Taxes, other than income			93,622			33,604

		Total operating expenses		402,180			196,224

Operating income				300,855			168,955
Miscellaneous income				1,343			5,663
Interest charges				65,615			33,495

Income before income taxes				236,583			141,123
Income tax expense				88,482			53,277

		Net income	$	148,101		$	87,846

Basic net income per share			$	1.92		$	1.70

Diluted net income per share			$	1.90		$	1.69

Cash dividends per share			$	0.62		$	0.61

Weighted average shares outstanding:
	Basic			77,290			51,666

	Diluted			77,769			52,057

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


				Six Months Ended
				March 31

				2005			2004

				(Unaudited)
				(In thousands)
Cash Flows From Operating Activities
	Net income			$	148,101		$	87,846
	Adjustments to reconcile net income to net cash provided by operating activities:
		Gain on the sale of assets			—			(4,898	)
		Depreciation and amortization:
			Charged to depreciation and amortization		89,323			46,611
			Charged to other accounts		477			601
		Deferred income taxes			42,605			10,081
		Other			3,315			(944	)
		Net assets/ liabilities from risk management activities			20,247			924
		Net change in operating assets and liabilities			96,025			150,382

			Net cash provided by operating activities		400,093			290,603
Cash Flows From Investing Activities
	Capital expenditures				(137,466	)		(83,729	)
	Acquisitions				(1,912,532	)		(1,950	)
	Proceeds from the sale of assets				—			24,661
	Other				(1,957	)		2,878

			Net cash used in investing activities		(2,051,955	)		(58,140	)
Cash Flows From Financing Activities
	Net decrease in short-term debt				—			(118,595	)
	Net proceeds from issuance of long-term debt				1,385,847			5,000
	Repayment of long-term debt				(3,849	)		(5,546	)
	Settlement of Treasury lock agreements				(43,770	)		—
	Cash dividends paid				(49,211	)		(31,616	)
	Issuance of common stock				26,025			17,594
	Net proceeds from equity offering				382,014			—

			Net cash provided by (used in) financing activities		1,697,056			(133,163	)

Net increase in cash and cash equivalents					45,194			99,300
Cash and cash equivalents at beginning of period					201,932			15,683

Cash and cash equivalents at end of period				$	247,126		$	114,983

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2005


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 Mississippi Division⁽¹⁾		Mississippi
Atmos Energy Mid-Tex Division⁽²⁾		Texas, including the Dallas/Fort Worth metropolitan area
Atmos Energy West Texas Division		West Texas


⁽¹⁾	The name of this division was changed from the Mississippi Valley Gas Company Division in April 2005.

⁽²⁾	Acquired in October 2004.

⁽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 (TXU Gas). 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. On October 1, 2004, we created the Atmos Energy Mid-Tex Division, which provides gas distribution services to the approximately 1.5 million residential and business customers in Texas, including the Dallas/ Fort Worth metropolitan area as a result of the TXU Gas acquisition. We also created the Atmos Pipeline — Texas Division to manage 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 assumed the operations of a Waco, Texas call center, and all call center services provided by TXU Gas under a transitional services agreement were terminated. We intend to close the purchase of the related assets on October 1, 2005.

Our nonutility businesses include our natural gas marketing operations, our pipeline and storage operations and our other nonutility operations which are provided in 18 states. These operations are either organized under or managed by Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by Atmos Energy Corporation.

Our natural gas marketing operations are managed by Atmos Energy Marketing, LLC (AEM), 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 Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services consist primarily

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 hedging through the use of derivative instruments.

Our pipeline and storage operations consist of the operations of the Atmos Pipeline — Texas Division, a division of Atmos Energy Corporation, and of Atmos Pipeline and Storage, LLC (APS), which is wholly-owned by AEH. The Atmos Pipeline — Texas Division was purchased from TXU Gas and supplies 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 (AES) and Atmos Power Systems, Inc., which are wholly-owned by AEH. Through AES, we provide natural gas management services to our utility operations. 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. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.


2.	Unaudited Interim Financial Information

In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements and notes are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation (“Atmos” or “the Company”) in its Annual Report on Form 10-K for the fiscal year ended September 30, 2004. Because of seasonal and other factors, the results of operations for the three and six-month periods ended March 31, 2005 are not indicative of expected results of operations for the fiscal year ending September 30, 2005. Further, the impact of the TXU Gas acquisition on the statement of cash flows is reflected in the acquisitions line item; therefore, the net changes in operating assets and liabilities will not reflect balance sheet changes attributable to the acquisition.


	*Significant accounting policies*

Our accounting policies are described in Note 2 to our Annual Report on Form 10-K for the year ended September 30, 2004. There were no significant changes to our accounting policies during the six months ended March 31, 2005.


	*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 restricted stock units 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.

As permitted by Statement of Financial Accounting Standards (SFAS) 123,Accounting for Stock-Based Compensation,we account for these plans under the intrinsic-value method described in Accounting

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Principles Board (APB) Opinion 25,Accounting for Stock Issued to Employees. 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 three and six-months ended March 31, 2005 and 2004 would have been impacted as shown in the following table:


		Three Months Ended						Six Months Ended
		March 31						March 31

		2005			2004			2005			2004

		(In thousands, except per share amounts)
Net income — as reported		$	88,502		$	58,305		$	148,101		$	87,846
Restricted stock compensation expense included in income, net of tax			469			98			962			196
Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of taxes			(684	)		(385	)		(1,427	)		(778	)

Net income — pro forma		$	88,287		$	58,018		$	147,636		$	87,264

Earnings per share:
	Basic earnings per share — as reported	$	1.12		$	1.12		$	1.92		$	1.70

	Basic earnings per share — pro forma	$	1.11		$	1.12		$	1.91		$	1.69

	Diluted earnings per share — as reported	$	1.11		$	1.12		$	1.90		$	1.69

	Diluted earnings per share — pro forma	$	1.11		$	1.11		$	1.90		$	1.67

At March 31, 2005, there were 300 options outstanding under the Long-Term Stock Plan for the Mid-States Division, all of which were fully vested. Because of the limited activities of this plan, the pro forma effects of applying SFAS 123 would have less than a $0.01 per diluted share effect on earnings per share.


	*Regulatory assets and liabilities*

We record certain costs as regulatory assets in accordance with SFAS 71,Accounting for the Effects of Certain Types of Regulation,when 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. Substantially all of our regulatory assets are recorded as a component of deferred charges and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and the regulatory cost of removal obligation is separately reported. Significant regulatory assets and liabilities as of March 31, 2005 and September 30, 2004 included the following:


		March 31,		September 30,
		2005		2004

		(In thousands)
Regulatory assets:
	Deferred gas costs	$	31,688	$	—
	UCG merger and integration costs, net⁽¹⁾		—		1,992
	Other merger and integration costs, net		13,966		14,644
	Deferred MVG operating expenses		—		751
	Environmental costs		2,924		4,057
	Rate case costs		20,990		—
	Other		6,545		3,289

		$	76,113	$	24,733

Regulatory liabilities:
	Deferred gas costs	$	—	$	39,097
	Regulatory cost of removal obligation		257,850		111,232
	Deferred income taxes, net		1,962		1,962
	Other		3,796		—

		$	263,608	$	152,291


⁽¹⁾	Fully amortized as of December 2004.

Currently authorized rates do not include a return on our merger and integration costs; however, we recover the amortization of these costs through our rates. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years. Certain environmental costs have been deferred to future rate filings in accordance with rulings received from various regulatory commissions.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Comprehensive income*

The following table presents the components of comprehensive income, net of related tax, for the three and six-month periods ended March 31, 2005 and 2004:


	Three Months Ended				Six Months Ended
	March 31				March 31

	2005		2004		2005			2004

	(In thousands)
Net income	$	88,502	$	58,305	$	148,101		$	87,846
Unrealized holding gains on investments, net of tax expense of $80 and $542 for the three months ended March 31, 2005 and 2004 and of $729 and $924 for the six months ended March 31, 2005 and 2004		132		883		1,189			1,508
Net unrealized gains on commodity hedging transactions, net of tax expense of $7,915 for the three months ended March 31, 2005 and $3 for the six months ended March 31, 2005		12,913		—		5			—
Net unrealized gains (losses) and reclassification of unrealized losses into earnings on interest rate hedging transactions, net of tax expense (benefit) of $527 for the three months ended March 31, 2005 and $(2,718) for the six months ended March 31, 2005		861		—		(4,435	)		—

Comprehensive income	$	102,408	$	59,188	$	144,860		$	89,354

Accumulated other comprehensive loss, net of tax, as of March 31, 2005 and September 30, 2004 consisted of the following unrealized gains (losses):


		March 31,			September 30,
		2005			2004

		(In thousands)
Accumulated other comprehensive income (loss):
	Unrealized holding gains (losses) on investments	$	345		$	(844	)
	Treasury lock agreements		(25,703	)		(21,268	)
	Cash flow hedges		7,588			7,583

		$	(17,770	)	$	(14,529	)


	*Recent Accounting Pronouncements*

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123 (revised),Share-Based Payment(SFAS 123(R)). This standard revises SFAS 123,Accounting for Stock-Based Compensationand 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 (SEC) 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


3.	TXU Gas Acquisition

On October 1, 2004, we completed our acquisition of the natural gas distribution and pipeline operations of TXU Gas Company (TXU Gas). 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.

The purchase price for the TXU Gas acquisition was approximately $1.9 billion (after preliminary closing adjustments and before transaction costs and expenses), which we paid in cash. We acquired approximately $121 million of working capital of TXU Gas 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. The purchase price is subject to adjustment for the actual amount of working capital we acquired and other specified matters. We anticipate that the working capital settlement will be finalized during the third quarter of fiscal 2005.

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 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 $382.0 million.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Cash purchase price			$	1,904,877
Transaction costs and expenses				7,655

	Total purchase price		$	1,912,532

Net property, plant and equipment			$	1,472,295
Accounts receivable				61,519
Gas stored underground				141,664
Other current assets				20,293
Goodwill				484,133
Deferred charges and other assets				41,634
Accounts payable and accrued liabilities				(43,216	)
Other current liabilities				(88,060	)
Regulatory cost of removal obligation				(138,991	)
Deferred income taxes				8,713
Deferred credits and other liabilities				(47,452	)

		Total	$	1,912,532

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.

Our allocation of the purchase price is preliminary and is subject to change due to the pending completion of the working capital settlement and our continuing review of the acquired assets and liabilities. The amount currently allocated to property, plant and equipment represents our estimate of the fair value of the assets acquired. We have based that estimate on the amount we believe will ultimately be approved as rate base for rate setting purposes.

The table below reflects the unaudited pro forma results of the Company and TXU Gas for the three and six-month periods ended March 31, 2004 as if the acquisition and related financing had taken place at the beginning of fiscal 2004 (in thousands, except per share data):


	Three Months Ended		Six Months Ended
	March 31, 2004		March 31, 2004

Operating revenue	$	1,623,068	$	2,734,578
Net income		91,765		135,149
Net income per diluted share	$	1.17	$	1.73

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Goodwill and Intangible Assets

Goodwill and intangible assets are comprised of the following as of March 31, 2005 and September 30, 2004.


	March 31,		September 30,
	2005		2004

	(In thousands)
Goodwill	$	718,245	$	234,112
Intangible assets		3,799		4,160

Total	$	722,044	$	238,272

The following presents our goodwill balance allocated by segment and changes in our balance for the six months ended March 31, 2005:


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

	(In thousands)
Balance as of September 30, 2004	$	199,400	$	24,282	$	—	$	10,430		$	234,112
Intersegment transfer of assets⁽¹⁾		—		—		10,430		(10,430	)		—
TXU Gas acquisition (Note 3)		346,102		—		138,031		—			484,133

Balance as of March 31, 2005	$	545,502	$	24,282	$	148,461	$	—		$	718,245

⁽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.

During the second quarter of fiscal 2005, we completed our annual goodwill impairment assessment. Based upon the assessment performed, our goodwill was considered to be not impaired.


5.	Derivative Instruments and Hedging Activities

We conduct risk management activities through both our utility and natural gas marketing segments. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent other assets or liabilities 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table shows the fair values of our risk management assets and liabilities by segment at March 31, 2005 and September 30, 2004:


				Natural Gas
	Utility			Marketing			Total

	(In thousands)
March 31, 2005:
Assets from risk management activities, current	$	24,367		$	5,408		$	29,775
Assets from risk management activities, noncurrent		—			267			267
Liabilities from risk management activities, current		—			(10,475	)		(10,475	)
Liabilities from risk management activities, noncurrent		—			(1,096	)		(1,096	)

Net assets (liabilities)	$	24,367		$	(5,896	)	$	18,471

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. Because the gains or losses of financial derivatives used in our utility segment ultimately will 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,Accounting for the Effects of Certain Types of Regulation. Accordingly, there is no earnings impact to our utility segment as a result of the use of financial derivatives. 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. Our utility hedging activities also include the cost of our Treasury lock agreements which are described in further detail below.


	*Nonutility Hedging Activities*

AEM manages its 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. Our financial derivative activities include fair value hedges to offset changes in the fair value of our natural gas inventory and cash flow hedges to offset anticipated purchases and sales of gas in the future.

Effective April 1, 2004, we elected to treat our fixed-price forward contracts as normal purchases and sales and ceased marking these contracts to market. As a result, unrealized gains and losses on open derivative contracts which are used to hedge price risk associated with these fixed-price forward 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.

For the three and six-month periods ended March 31, 2005, the change in the deferred hedging position in accumulated other comprehensive income was attributable to decreases in future commodity prices relative to the commodity prices stipulated in the derivative contracts, and the recognition for the six months ended March 31, 2005 of $4.2 million in net deferred hedging gains ($8.5 million during the three months ended March 31, 2005) in net income when the derivative contracts matured according to their terms. The net

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

deferred hedging gain associated with open cash flow hedges remains 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 balance as of March 31, 2005 is expected to be recognized in net income during fiscal 2005.

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. On March 31, 2005, AEH had no net open positions (including existing storage).


	*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 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. These Treasury lock agreements were settled in October 2004 with a net $43.8 million payment to the counterparties. This amount will remain in accumulated other comprehensive income and will be recognized as a component of interest expense over the next ten years. During the three and six-month periods ended March 31, 2005, we recognized approximately $1.4 million and $2.3 million of this obligation as a component of interest expense.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Debt


	*Long-Term Debt*

Long-term debt at March 31, 2005 and September 30, 2004 consisted of the following:


			March 31,			September 30,
			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			17,000
	Series P, 10.43% due 2013			10,000			11,250
	Series Q, 9.75% due 2020			16,000			16,000
	Series T, 9.32% due 2021			18,000			18,000
	Series U, 8.77% due 2022			20,000			20,000
	Series V, 7.50% due 2007			2,500			4,167
Other term notes due in installments through 2013				8,898			9,830

		Total long-term debt		2,264,701			868,550
Less:
	Original issue discount on unsecured senior notes and debentures			(3,997	)		(1,331	)
	Current maturities			(5,887	)		(5,908	)

			$	2,254,817		$	861,311

Our unsecured floating rate debt bears interest at a rate equal to the three-month LIBOR rate plus 0.375 percent per year. At March 31, 2005, the interest rate on our floating rate debt was 3.035 percent.


	*Short-Term Debt*

At March 31, 2005 and September 30, 2004, there were no short-term amounts outstanding under our commercial paper program or bank credit facilities.


	*Credit Facilities*

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


	Committed Credit Facilities

As of March 31, 2005, we had two short-term committed credit facilities totaling $618.0 million, one of which is an unsecured facility for $600.0 million that bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our $600.0 million commercial paper program. At March 31, 2005, no commercial paper was outstanding. 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.

We have a second unsecured working capital 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 with no material changes to its terms and pricing.

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 our $600.0 million credit facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At March 31, 2005, our total-debt-to-total-capitalization ratio, as defined, was 60 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under our $600.0 million credit facility are subject to adjustment depending upon our credit ratings.


	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 a maximum cumulative loss from March 30, 2005 ranging from $4 million to $10 million, depending on the total amount of borrowing elected from time to time by AEM. At March 31, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.95.

At March 31, 2005, no amounts were outstanding under this credit facility. However, at March 31, 2005, AEM letters of credit totaling $103.1 million had been issued under the facility and reduce the amount available. 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 $46.9 million at March 31, 2005. Finally, this line of credit is collateralized by a blocked

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

account maintained at AEM whereby collections from customers are deposited into the account, and AEM withdraws funds from the account through an established approval process.

Atmos Energy Corporation also has 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 March 31, 2005, but Atmos Energy Corporation (AEC) letters of credit reduced the amount available by $4.3 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.

In addition, AEM has a $100.0 million intercompany credit facility with AEC through AEH for its nonutility business which bears interest at the LIBOR rate plus 2.75 percent. 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 and has been approved by our state regulators through December 31, 2005. At March 31, 2005, $15.0 million was outstanding under this facility and is eliminated in consolidation.


	*Debt Covenants*

We have other covenants in addition to those described above. Most of our First Mortgage Bonds contain provisions that allow us to prepay the outstanding balance in whole at any time, 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, 1988 may not exceed the sum of accumulated net income for periods after December 31, 1988 plus $15.0 million. At March 31, 2005 approximately $202.4 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 March 31, 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 $600.0 million revolving credit agreement, 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 is 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.


7.	Equity

On February 9, 2005, 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 $382.0 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 pay off the $1.7 billion in outstanding

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

commercial paper described in Note 3 and fund the remainder of the purchase price for the TXU Gas acquisition.


8.	Earnings Per Share

Basic and diluted earnings per share at March 31 are calculated as follows:


		For the Three Months				For the Six Months
		Ended March 31				Ended March 31

		2005		2004		2005		2004

		(In thousands, except per share amounts)
Net income		$	88,502	$	58,305	$	148,101	$	87,846

Denominator for basic income per share — weighted average common shares			79,270		51,850		77,290		51,666
Effect of dilutive securities:
	Restricted and other shares		335		132		330		132
	Stock options		155		258		149		259

Denominator for diluted income per share — weighted average common shares			79,760		52,240		77,769		52,057

Income per share — basic		$	1.12	$	1.12	$	1.92	$	1.70

Income per share — diluted		$	1.11	$	1.12	$	1.90	$	1.69

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended March 31, 2005. There were 3,000 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended March 31, 2004 as their exercise price was greater than the average market price of the common stock during that period.

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the six months ended March 31, 2005. There were 3,000 out-of-the-money options excluded from the computation of diluted earnings per share for the six months ended March 31, 2004 as their exercise price was greater than the average market price of the common stock during that period.


9.	Interim Pension and Other Post Retirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the three months ended March 31, 2005 and 2004 are presented below. All of these costs are recoverable

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense.


			Three Months Ended March 31

			Pension Benefits						Other Benefits

			2005			2004			2005			2004

			(In thousands)
Components of net periodic pension cost:
	Service cost		$	3,136		$	2,433		$	2,478		$	1,405
	Interest cost			6,017			6,004			2,366			1,751
	Expected return on assets			(6,885	)		(7,524	)		(518	)		(396	)
	Amortization of transition asset			1			24			378			378
	Amortization of prior service cost			(2	)		(2	)		96			96
	Amortization of actuarial loss			1,891			2,018			151			—

		Net periodic pension cost	$	4,158		$	2,953		$	4,951		$	3,234

The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the six months ended March 31, 2005 and 2004 are as follows:


			Six Months Ended March 31

			Pension Benefits						Other Benefits

			2005			2004			2005			2004

			(In thousands)
Components of net periodic pension cost:
	Service cost		$	6,272		$	4,866		$	4,956		$	3,130
	Interest cost			12,034			12,008			4,732			3,854
	Expected return on assets			(13,770	)		(15,048	)		(1,036	)		(731	)
	Amortization of transition asset			2			48			756			756
	Amortization of prior service cost			(4	)		(4	)		192			192
	Amortization of actuarial loss			3,782			4,036			302			635

		Net periodic pension cost	$	8,316		$	5,906		$	9,902		$	7,836

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2005 and 2004 are as follows:


	Pension Benefits						Other Benefits

	2005			2004			2005			2004

Discount rate		6.25	%		6.00	%		6.25	%		6.00	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected return on plan assets		8.75	%		9.00	%		5.30	%		5.30	%

We did not contribute to our pension plans during the six months ended March 31, 2005. We are not required to make a minimum funding contribution during fiscal 2005 nor do we anticipate making any voluntary contributions during the remainder of fiscal 2005. During the six months ended March 31, 2005, we contributed $4.5 million to our other post-retirement plans and we expect to contribute a total of $11.7 million to these plans during fiscal 2005.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	Commitments and Contingencies


	*Litigation and Environmental Matters*

We are involved in litigation and environmental matters and claims that arise out of our ordinary course of business. While the ultimate results of such litigation and response actions to such environmental matters and claims cannot be predicted with certainty, we believe the final outcome of such litigation and response actions will not have a material adverse effect on our financial condition, results of operations or net cash flows.

As discussed in our Form 10-Q for the three months ended December 31, 2004, we were the plaintiff in a case styledEnergas 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 72nd 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.

During the six months ended March 31, 2005, there were no other material changes in the status of the litigation and environmental matters that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2004. However, with the acquisition of the natural gas distribution and pipeline operations of TXU Gas Company on October 1, 2004, we assumed responsibility for certain litigation and claims that arose in the ordinary course of the business of TXU Gas Company. 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.


	*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 March 31, 2005, AEM is committed to purchase 61.3 Bcf within one year, 6.6 Bcf within one to three years and 1.5 Bcf after three years under indexed contracts. AEM is committed to purchase 0.4 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $5.24 to $7.77. Purchases under these contracts totaled $345.3 million and $401.3 million for the three months ended March 31, 2005 and 2004 and $705.4 million and $698.0 million for the six months ended March 31, 2005 and 2004.

Our historical utility operations 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 this service area which obligate it to purchase specified volumes at market prices. The estimated commitments under these contracts as of March 31, 2005 are as follows (in thousands):


2005	$	206,029
2006		135,701
2007		22,931
2008		12,114
2009		9,596
Thereafter		36,094

	$	422,465

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Other*

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 will contribute up to $42.5 million within two years of signing of a definitive agreement. The pipeline is currently expected to be placed into service in fiscal 2006.


11.	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.

This 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 a provision 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 provisions for credit losses, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any counterparty.

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 Inc. and/or Standard & Poor’s. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrial and commercial customers is non-investment grade. The table below shows the percentages related to the investment ratings as of March 31, 2005 and September 30, 2004.


		March 31,			September 30,
		2005			2004

Investment grade			50	%		55	%
Non-investment grade			50	%		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 March 31, 2005. Investment grade counterparties have minimum credit ratings of BBB-, assigned by Standard & Poor’s; 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-

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

term nature of the contracts associated with that counterparty. This category is composed of numerous smaller counterparties, none of which is individually significant.


	At March 31, 2005

			Natural Gas
	Utility		Marketing
	Segment⁽¹⁾		Segment		Consolidated

	(In thousands)
Investment grade counterparties	$	24,367	$	5,299	$	29,666
Non-investment grade counterparties		—		376		376

	$	24,367	$	5,675	$	30,042


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


12.	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 cover 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 18 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.

Our operations are divided into four segments:


	•	the utility segment, which includes our regulated natural gas distribution and 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 nonutility operations.

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. Segment information for all prior year periods has been restated to reflect our new organizational structure.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 found in our annual report on Form 10-K for the fiscal year ended September 30, 2004. We evaluate performance based on net income or loss of the respective operating units. Summarized income statements by segment are shown in the following tables.


			For the Three Months Ended March 31, 2005

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	1,235,092	$	429,598	$	19,827	$	568	$	—		$	1,685,085
Intersegment revenues				285		83,293		25,719		710		(110,007	)		—

				1,235,377		512,891		45,546		1,278		(110,007	)		1,685,085
Purchased gas cost				912,309		501,731		1,718		—		(109,256	)		1,306,502

	Gross profit			323,068		11,160		43,828		1,278		(751	)		378,583
Operating expenses
	Operation and maintenance			86,469		4,016		15,532		893		(801	)		106,109
	Depreciation and amortization			41,181		474		3,642		29		—			45,326
	Taxes, other than income			52,220		261		2,398		88		—			54,967

Total operating expenses				179,870		4,751		21,572		1,010		(801	)		206,402

Operating income				143,198		6,409		22,256		268		50			172,181
Miscellaneous income				1,974		201		292		616		(2,125	)		958
Interest charges				28,062		679		6,228		179		(2,075	)		33,073

Income before income taxes				117,110		5,931		16,320		705		—			140,066
Income tax expense				43,459		2,140		5,682		283		—			51,564

		Net income	$	73,651	$	3,791	$	10,638	$	422	$	—		$	88,502

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			For the Three Months Ended March 31, 2004

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	707,985	$	406,112	$	2,788	$	600	$	—		$	1,117,485
Intersegment revenues				297		111,106		7,179		87		(118,669	)		—

				708,282		517,218		9,967		687		(118,669	)		1,117,485
Purchased gas cost				518,820		505,356		5,681		—		(118,498	)		911,359

	Gross profit			189,462		11,862		4,286		687		(171	)		206,126
Operating expenses
	Operation and maintenance			54,001		4,357		626		280		(171	)		59,093
	Depreciation and amortization			22,145		536		429		28		—			23,138
Taxes, other than income				17,845		297		243		96		—			18,481

Total operating expenses				93,991		5,190		1,298		404		(171	)		100,712

Operating income				95,471		6,672		2,988		283		—			105,414
Miscellaneous income				1,266		229		17		4,922		(1,978	)		4,456
Interest charges				16,106		1,081		340		611		(1,978	)		16,160

Income before income taxes				80,631		5,820		2,665		4,594		—			93,710
Income tax expense				30,073		2,398		1,078		1,856		—			35,405

		Net income	$	50,558	$	3,422	$	1,587	$	2,738	$	—		$	58,305

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			For the Six Months Ended March 31, 2005

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	2,148,498	$	862,508	$	41,579	$	1,124	$	—		$	3,053,709
Intersegment revenues				560		144,184		47,657		1,513		(193,914	)		—

				2,149,058		1,006,692		89,236		2,637		(193,914	)		3,053,709
Purchased gas cost				1,568,679		968,688		5,590		—		(192,283	)		2,350,674

	Gross profit			580,379		38,004		83,646		2,637		(1,631	)		703,035
Operating expenses
	Operation and maintenance			183,022		7,462		28,542		1,940		(1,731	)		219,235
	Depreciation and amortization			80,232		978		8,055		58		—			89,323
	Taxes, other than income			88,840		170		4,446		166		—			93,622

Total operating expenses				352,094		8,610		41,043		2,164		(1,731	)		402,180

Operating income				228,285		29,394		42,603		473		100			300,855
Miscellaneous income				2,946		447		607		1,209		(3,866	)		1,343
Interest charges				55,321		1,080		12,399		581		(3,766	)		65,615

Income before income taxes				175,910		28,761		30,811		1,101		—			236,583
Income tax expense				65,236		11,708		11,089		449		—			88,482

		Net income	$	110,674	$	17,053	$	19,722	$	652	$	—		$	148,101

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			For the Six Months Ended March 31, 2004

					Natural Gas		Pipeline		Other
			Utility		Marketing		and Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
Operating revenues from external parties			$	1,168,194	$	707,536	$	4,157	$	1,214	$	—		$	1,881,101
Intersegment revenues				576		183,511		8,729		182		(192,998	)		—

				1,168,770		891,047		12,886		1,396		(192,998	)		1,881,101
Purchased gas cost				840,884		861,687		6,008		—		(192,657	)		1,515,922

	Gross profit			327,886		29,360		6,878		1,396		(341	)		365,179
Operating expenses
	Operation and maintenance			106,115		7,984		1,276		975		(341	)		116,009
	Depreciation and amortization			44,637		1,066		848		60		—			46,611
	Taxes, other than income			32,285		428		704		187		—			33,604

Total operating expenses				183,037		9,478		2,828		1,222		(341	)		196,224

Operating income				144,849		19,882		4,050		174		—			168,955
Miscellaneous income				2,333		352		23		6,111		(3,156	)		5,663
Interest charges				33,166		1,873		551		1,061		(3,156	)		33,495

Income before income taxes				114,016		18,361		3,522		5,224		—			141,123
Income tax expense				42,347		7,403		1,420		2,107		—			53,277

		Net income	$	71,669	$	10,958	$	2,102	$	3,117	$	—		$	87,846

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at March 31, 2005 and September 30, 2004 by segment is presented in the following tables:


			At March 31, 2005

					Natural			Pipeline
					Gas			and		Other
			Utility		Marketing			Storage		Nonutility		Eliminations			Consolidated

			(In thousands)
ASSETS
Property, plant and equipment, net			$	2,817,614	$	7,558		$	425,004	$	1,419	$	—		$	3,251,595
Investment in subsidiaries				201,732		(1,741	)		—		—		(199,991	)		—
Current assets Cash and cash equivalents				224,231		22,749			7		139		—			247,126
	Cash held on deposit in margin account			—		16,990			—		—		—			16,990
	Assets from risk management activities			24,367		7,980			—		—		(2,572	)		29,775
	Other current assets			608,617		272,297			41,458		18,811		(57,308	)		883,875
	Intercompany receivables			482,978		—			—		31,662		(514,640	)		—

		Total current assets		1,340,193		320,016			41,465		50,612		(574,520	)		1,177,766
Intangible assets				—		3,799			—		—		—			3,799
Goodwill				545,502		24,282			148,461		—		—			718,245
Noncurrent assets from risk management activities				—		613			—		—		(346	)		267
Deferred charges and other assets				231,951		1,379			6,037		21,405		—			260,772

			$	5,136,992	$	355,906		$	620,967	$	73,436	$	(774,857	)	$	5,412,444


CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	1,632,270	$	116,862		$	51,792	$	33,078	$	(201,732	)	$	1,632,270
Long-term debt				2,247,890		—			—		6,927		—			2,254,817

		Total capitalization		3,880,160		116,862			51,792		40,005		(201,732	)		3,887,087
Current liabilities
	Current maturities of long-term debt			3,917		—			—		1,970		—			5,887
	Short-term debt			—		—			—		15,000		(15,000	)		—
	Liabilities from risk management activities			—		17,609			—		—		(7,134	)		10,475
	Other current liabilities			583,861		179,089			87,121		7,520		(36,032	)		821,559
	Intercompany payables			—		44,238			470,402		—		(514,640	)		—

		Total current liabilities		587,778		240,936			557,523		24,490		(572,806	)		837,921
Deferred income taxes				240,348		(3,356	)		6,840		1,977		27			245,836
Noncurrent liabilities from risk management activities				—		1,442			—		—		(346	)		1,096
Regulatory cost of removal obligation				246,285		—			—		—		—			246,285
Deferred credits and other liabilities				182,421		22			4,812		6,964		—			194,219

			$	5,136,992	$	355,906		$	620,967	$	73,436	$	(774,857	)	$	5,412,444

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			At 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			253,829		170,363			13,473		18,815		(25,740	)		430,740
	Intercompany receivables			1,995		—			—		16,079		(18,074	)		—

		Total current assets		464,362		213,509			13,473		35,246		(49,478	)		677,112
Intangible assets				—		4,160			—		—		—			4,160
Goodwill				199,400		24,282			10,430		—		—			234,112
Noncurrent assets from risk management activities				—		734			—		—		(172	)		562
Deferred charges and other assets				207,019		1,661			25		22,711		—			231,416

			$	2,704,385	$	250,737		$	67,712	$	59,515	$	(212,466	)	$	2,869,883


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			236,257		124,577			24,014		7,558		(23,304	)		369,102
	Intercompany payables			—		9,906			8,168		—		(18,074	)		—

		Total current liabilities		274,478		145,890			32,182		9,549		(47,631	)		414,468
Deferred income taxes				208,325		(3,360	)		6,961		1,977		27			213,930
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

			$	2,704,385	$	250,737		$	67,712	$	59,515	$	(212,466	)	$	2,869,883

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Atmos Energy Corporation

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, 2005, and the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2005 and 2004, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2005 and 2004. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated interim financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2004, and the related consolidated statements of income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 9, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2004, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


	Ernst & Young LLP

Dallas, Texas

May 6, 2005


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

Introduction

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2004.


	*Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995*

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of 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 and the successful integration of the TXU Gas operations; and other uncertainties, which may be discussed herein, all of which are difficult to predict and many of which are beyond the control of the Company. A more detailed discussion of these risks and uncertainties may be found in the Company’s Form 10-K for the year ended September 30, 2004. 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.

Overview

Atmos Energy Corporation and its subsidiaries are engaged primarily in the natural gas utility business as well as certain other natural gas 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 cover 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, transportation, storage and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. Additionally, we provide natural gas transportation and storage services to certain of our utility operations and to third parties.

Our operations are divided into four segments:


	•	the utility segment, which includes our regulated natural gas distribution and 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 nonutility operations.

Fiscal 2005 has been highlighted by our acquisition 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 in Texas. On April 1, 2005, we assumed the operations of a Waco, Texas call center and all call center services provided by TXU Gas under a transitional services agreement were terminated. We intend to close the purchase of the related assets on October 1, 2005.

The purchase price for 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 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 $1.4 billion and the sale of 16.1 million shares of common stock on October 27, 2004, which generated net proceeds of approximately $382.0 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. The following table presents selected financial information for the Mid-Tex Division and Atmos Pipeline — Texas Division operations for the three and six-month periods ended March 31, 2005:


		Three Months Ended						Six Months Ended
		March 31, 2005						March 31, 2005

		Mid-Tex			Atmos Pipeline —			Mid-Tex			Atmos Pipeline —
		Division			Texas Division			Division			Texas Division

		(In thousands, unless otherwise noted)
Operating revenues		$	522,410		$	41,862		$	924,658		$	80,376
Gross profit			131,155			41,358			245,114			76,225
Operation and maintenance			39,368			14,931			79,439			27,449
Depreciation and amortization			17,349			3,317			33,082			7,404
Taxes, other than income			33,416			2,223			53,023			4,095
Operating income			41,022			20,887			79,570			37,277
Miscellaneous income (expense)			586			(105	)		996			9
Interest charges			12,001			5,979			23,441			11,746
Income tax expense			9,964			5,109			20,049			8,943
Net income		$	19,643		$	9,694		$	37,076		$	16,597

Utility sales volumes — MMcf			56,484			NA			96,634			NA
Utility transportation volumes — MMcf			13,669			NA			25,468			NA

	Total utility throughput — MMcf		70,153			NA			122,102			NA

Pipeline transportation volumes — MMcf			NA			84,208			NA			156,961

Heating Degree Days — Percent of Normal			82	%		NA			80	%		NA

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 six-months ended March 31, 2005:


	•	Our utility segment net income increased $39.0 million. The increase reflects the impact of the acquisition of the Mid-Tex operations ($37.1 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 historical operations that was five percent warmer than normal and two percent warmer than the prior year.

	•	Our natural gas marketing segment net income increased $6.1 million during the six months ended March 31, 2005 compared with the six months ended March 31, 2004. The increase in natural gas marketing net income primarily reflects favorable results from the management of our storage portfolio partially offset with an unfavorable movement in the forward indices used to value our storage financial instruments.

	•	Our pipeline and storage segment contributed $19.7 million in net income for the six months ended March 31, 2005 compared with $2.1 million for the six-month period ended March 31, 2004, primarily reflecting the acquisition of the Atmos Pipeline — Texas Division ($16.6 million).

	•	Our total debt to capitalization ratio at March 31, 2005 was 58.1 percent compared with 43.3 percent at September 30, 2004 reflecting the impact of the financing for the TXU Gas acquisition.


	•	Operating cash flow provided $400.1 million compared with $290.6 million, reflecting increased net income, more effective net working capital management partially offset by lower than expected utility sales volumes due to the effect of warmer weather and seasonably unfavorable purchased gas cost recoveries.

	•	Capital expenditures increased to $137.5 million from $83.7 million primarily reflecting spending for the Mid-Tex Division ($45.8 million) and the Atmos Pipeline — Texas Division ($7.9 million).

Critical Accounting Estimates

Our condensed 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 estimates are reviewed by the Audit Committee on a quarterly basis. Actual results may differ from estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the year ended September 30, 2004 and includes the following:


	•	Regulation

	•	Revenue Recognition

	•	Allowance for Doubtful Accounts

	•	Derivatives and Hedging Activities

	•	Impairment Assessments

	•	Pension and Other Postretirement Plans

There have been no significant changes to these critical accounting policies during the six months ended March 31, 2005.

Results of Operations

The following table presents our financial highlights for the three and six-month periods ended March 31, 2005 and 2004:


		Three Months Ended						Six Months Ended
		March 31						March 31

		2005			2004			2005			2004

		(In thousands, unless otherwise noted)
Operating revenues		$	1,685,085		$	1,117,485		$	3,053,709		$	1,881,101
Gross profit			378,583			206,126			703,035			365,179
Operating expenses			206,402			100,712			402,180			196,224
Operating income			172,181			105,414			300,855			168,955
Miscellaneous income			958			4,456			1,343			5,663
Interest charges			33,073			16,160			65,615			33,495
Income before income taxes			140,066			93,710			236,583			141,123
Income tax expense			51,564			35,405			88,482			53,277
Net income		$	88,502		$	58,305		$	148,101		$	87,846

Utility sales volumes — MMcf			128,195			77,184			219,152			127,865
Utility transportation volumes — MMcf			31,904			20,647			59,882			38,145

	Total utility throughput — MMcf		160,099			97,831			279,034			166,010

Natural gas marketing sales volumes — MMcf			66,644			67,172			126,940			126,089

Pipeline transportation volumes — MMcf			84,208			—			156,961			—

Heating degree days⁽¹⁾
	Actual (weighted average)		1,422			1,772			2,415			3,012
	Percent of normal		90	%		97	%		89	%		96	%
Consolidated utility average transportation revenue per Mcf		$	0.53		$	0.42		$	0.55		$	0.43
Consolidated utility average cost of gas per Mcf sold		$	7.12		$	6.72		$	7.16		$	6.58


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

The following tables show our operating income by segment for the three-month and six-month periods ended March 31, 2005 and 2004. The presentation of our utility operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


		For the Three Months Ended March 31

		2005					2004

		Operating		Heating Degree Days			Operating		Heating Degree Days
		Income		Percent of Normal⁽⁴⁾			Income		Percent of Normal⁽⁴⁾

		(In thousands, except degree day information)
Colorado-Kansas		$	16,248		97	%	$	11,119		100	%
Kentucky			10,758		100	%		11,242		100	%
Louisiana			16,250		74	%		21,445		93	%
Mid-States			24,705		95	%		23,513		98	%
Mid-Tex⁽¹⁾			41,022		82	%		—		—
Mississippi⁽²⁾			18,509		100	%		17,131		100	%
West Texas			15,302		99	%		9,501		94	%
Other			404		—			1,520		—

Utility segment			143,198		90	%		95,471		97	%
Natural gas marketing segment			6,409		—			6,672		—
Pipeline and storage segment⁽³⁾			22,256		—			2,988		—
Other nonutility segment			318		—			283		—

	Consolidated operating income	$	172,181		90	%	$	105,414		97	%


		For the Six Months Ended March 31

		2005					2004

		Operating		Heating Degree Days			Operating		Heating Degree Days
		Income		Percent of Normal⁽⁴⁾			Income		Percent of Normal⁽⁴⁾

		(In thousands, except degree day information)
Colorado-Kansas		$	24,483		98	%	$	19,357		100	%
Kentucky			16,603		98	%		17,806		99	%
Louisiana			22,583		78	%		29,701		92	%
Mid-States			35,843		93	%		37,384		96	%
Mid-Tex⁽¹⁾			79,570		80	%		—		—
Mississippi⁽²⁾			27,116		95	%		25,364		100	%
West Texas			21,088		100	%		14,167		91	%
Other			999		—			1,070		—

Utility segment			228,285		89	%		144,849		96	%
Natural gas marketing segment			29,394		—			19,882		—
Pipeline and storage segment⁽³⁾			42,603		—			4,050		—
Other nonutility segment			573		—			174		—

	Consolidated operating income	$	300,855		89	%	$	168,955		96	%

Notes to preceding tables:


⁽¹⁾	Operating income for the Mid-Tex Division reflects operating income since October 1, 2004.

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

⁽³⁾	Operating income for the pipeline and storage segment reflects operating income for the Atmos Pipeline — Texas Division since October 1, 2004.

⁽⁴⁾	Adjusted for service areas that have weather normalized operations.

Three Months Ended March 31, 2005 compared with Three Months Ended March 31, 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 68 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.

The effects of weather that is above or below normal are partially offset through weather normalization adjustments, or WNA, 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. As of March 31, 2005, we had, or received regulatory approvals for, WNA in the following service areas for the following periods, which covered approximately 1.1 million meters:


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


⁽¹⁾	Effective beginning in July 2005.

The Atmos Energy 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 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.


	Operating Income

Utility gross profit increased to $323.1 million for the three months ended March 31, 2005 from $189.5 million for the three months ended March 31, 2004. Total throughput for our utility business was 160.1 billion cubic feet (Bcf) during the current year compared to 97.8 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 $131.2 million and 70.2 Bcf. Gross profit margin in our historical operations increased by $2.4 million compared with the prior year quarter. Increases in gross profit attributable to rate increases in our Mississippi and West Texas jurisdictions and the recognition of a $1.9 million refund to our customers in our Colorado service area in the prior year quarter were partially offset by lower gross profit margins, primarily in our Louisiana service area, due to weather (as adjusted for jurisdictions with weather-normalized operations) that was three percent warmer than the prior year quarter. 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.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $179.9 million for the three months ended March 31, 2005 from $94.0 million for the three months ended March 31, 2004. Operation and maintenance expense increased by $32.5 million primarily due to the addition of $39.4 million in operation and maintenance expenses associated with the Mid-Tex Division, partially offset by the impact of cost control efforts in our historical utility operations and a lower provision for doubtful accounts due to exceptional customer accounts receivable collection efforts. Taxes other than income taxes increased $34.4 million, primarily due to additional franchise, payroll and property taxes associated with the Mid-Tex assets acquired in October 2004. Franchise and state gross receipts taxes 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. Depreciation and amortization expense increased $19.0 million, which primarily reflects the inclusion of depreciation associated with the Mid-Tex assets ($17.3 million).

As a result of the aforementioned factors, our utility segment operating income for the three months ended March 31, 2005 increased to $143.2 million from $95.5 million for the three months ended March 31, 2004.


	Interest Charges

Interest charges allocated to the utility segment for the three months ended March 31, 2005 increased to $28.1 million from $16.1 million for the three months ended March 31, 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.


	*Natural Gas Marketing Segment*

Our natural gas marketing segment aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers the 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 the most advantageous price to lock in a gross profit margin. 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 three months ended March 31, 2005 and 2004:


		March 31

		2005			2004

		(In thousands, except
		storage balances)
Storage Activities
	Realized margin	$	14,669		$	2,358
	Unrealized margin		(20,545	)		(6,678	)

Total Storage Activities			(5,876	)		(4,320	)
Marketing Activities
	Realized margin		17,236			16,662
	Unrealized margin		(200	)		(480	)

Total Marketing Activities			17,036			16,182

Gross profit		$	11,160		$	11,862

Ending storage balance (Bcf)			11.0			5.8

Our natural gas marketing segment’s gross profit margin was $11.2 million for the three months ended March 31, 2005 compared to gross profit of $11.9 million for the three months ended March 31, 2004. Natural gas marketing sales volumes were 74.8 Bcf during the three months ended March 31, 2005 compared with 81.2 Bcf for the prior year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 66.6 Bcf during the current year period compared with 67.2 Bcf in the prior year period. The decrease in consolidated natural gas marketing sales volumes primarily was due to warmer-than-normal weather across our market areas partially offset by focusing our marketing efforts on higher margin customers. Gross profit margin from our natural gas marketing segment for the three months ended March 31, 2005 included an unrealized loss of $20.7 million compared with an unrealized loss of $7.2 million in the prior-year period.

The contribution to gross profit from our storage activities was a loss of $5.9 million for the three months ended March 31, 2005 compared to a loss of $4.3 million for the three months ended March 31, 2004. The $1.6 million decrease primarily was attributable to a $13.9 million decrease in the unrealized storage contribution as a result of an unfavorable movement during the three months ended March 31, 2005 in the forward indices used to value the storage financial instruments combined with greater physical natural gas storage quantities at March 31, 2005 compared to the prior year period. This decrease was partially offset by a $12.3 million improvement in the realized storage contribution for the three months ended March 31, 2005 compared to the prior year period due to higher physical storage volumes and more favorable arbitrage spreads from increased market volatility.

In April 2005, we contracted for an additional 8.5 Bcf of storage capacity and may further increase the amount of our storage capacity during the remainder of fiscal 2005; therefore, the impact of price volatility on our unrealized storage contribution could become more significant in future periods.

Our marketing activities contributed $17.0 million to our gross profit for the three months ended March 31, 2005 compared to $16.2 million for the three months ended March 31, 2004. The increase in the

marketing contribution primarily was attributable to focusing our marketing efforts on higher margin customers.

The decrease in gross profit margin, partially offset by lower operating expenses resulted in a decrease in our natural gas marketing segment operating income to $6.4 million for the three months ended March 31, 2005 compared with operating income of $6.7 million for the three months ended March 31, 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 supplies natural gas to the Atmos Energy Mid-Tex Division and transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking arrangements, 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.

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

Similar to our utility segment, our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Natural gas transportation requirements are affected by the winter heating season requirements of our customers. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either lower net income or net losses during the period from April through September of each year. Further, as the Atmos Pipeline — Texas Division operations 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 $43.8 million for the three months ended March 31, 2005 from $4.3 million for the three months ended March 31, 2004. Total pipeline transportation volumes were 158.9 Bcf during the three months ended March 31, 2005 compared with 2.8 Bcf for the prior year period. Excluding intersegment transportation volumes, total pipeline transportation volumes were 84.2 Bcf during the current year period.

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 $41.4 million and 84.2 Bcf. The $1.9 million decrease in the gross profit generated by Atmos Pipeline and Storage, LLC primarily reflects an unrealized loss of $1.5 million compared with an unrealized gain in the prior year quarter of $0.4 million.

Operating expenses increased to $21.6 million for the three months ended March 31, 2005 from $1.3 million for the three months ended March 31, 2004 due to the addition of $20.5 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 effect on net income. Included in operating expense was $2.4 million associated with taxes other than income taxes, of which $2.2 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 three months ended March 31, 2005 increased to $22.3 million from $3.0 million for the three months ended March 31, 2004.


	Interest Charges

Interest charges allocated to this segment for the three months ended March 31, 2005 increased to $6.2 million from $0.3 million for the three months ended March 31, 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 (AES), and Atmos Power Systems, Inc. Through AES, we provide natural gas management services to our utility operations. 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. AES’ revenues represent charges to our utility divisions equal to the costs incurred to provide those services. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities and may enter into agreements to either lease or sell these plants.

Operating income for this segment primarily reflects the leasing income associated with two sales-type lease transactions completed in 2001 and 2002. Operating income during the three months ended March 31, 2005 was flat compared with the prior year quarter.

Miscellaneous income for the three months ended March 31, 2005 was $0.6 million compared with $4.9 million for the three months ended March 31, 2004. The $4.3 million decrease was primarily attributable to the recognition of a $4.9 million pretax gain associated with the sale by U.S. Propane L.P. (USP) of its general and limited partnership interests in Heritage Propane Partners, L.P. during the second quarter of fiscal 2004.

Six Months Ended March 31, 2005 Compared with Six Months Ended March 31, 2004


	*Utility Segment*


	Operating Income

Utility gross profit increased to $580.4 million for the six months ended March 31, 2005 from $327.9 million for the six months ended March 31, 2004. Total throughput for our utility business was 279.0 billion cubic feet (Bcf) during the current year compared to 166.0 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 $245.1 million and 122.1 Bcf. The $7.4 million increase in the gross profit generated from our historical operations primarily reflects rate increases in our Mississippi and West Texas jurisdictions that were absent in the prior year period coupled with the recognition of a $1.9 million refund to our customers in our Colorado service area in the prior year period. These increases were partially offset by lower gross profit margins, primarily in our Louisiana service area, due to weather (as adjusted for jurisdictions with weather-normalized operations) that was five percent warmer than normal and two 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.

Operating expenses increased to $352.1 million for the six months ended March 31, 2005 from $183.0 million for the six months ended March 31, 2004. Operation and maintenance expense increased by $76.9 million primarily due to the addition of $79.4 million in operation and maintenance expenses associated with the Mid-Tex Division offset by cost control efforts in our historical utility operations and a lower provision for doubtful accounts due to exceptional customer accounts receivable collection efforts. Taxes other than income taxes increased $56.6 million, primarily due to additional franchise, payroll and property taxes associated with the Mid-Tex assets acquired in October 2004. Franchise and state gross receipts taxes 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. Depreciation and amortization expense increased $35.6 million, which primarily reflects the inclusion of depreciation associated with the Mid-Tex assets ($33.1 million).

As a result of the aforementioned factors, our utility segment operating income for the six months ended March 31, 2005 increased to $228.3 million from $144.8 million for the six months ended March 31, 2004.


	Interest Charges

Interest charges allocated to the utility segment for the six months ended March 31, 2005 increased to $55.3 million from $33.2 million for the six months ended March 31, 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.


	*Natural Gas Marketing Segment*


	Operating Income

Our natural gas marketing segment’s gross profit margin was comprised of the following for the six months ended March 31, 2005 and 2004:


		March 31

		2005			2004

		(In thousands, except
		storage balances)
Storage Activities
	Realized margin	$	17,259		$	4,145
	Unrealized margin		(8,027	)		(2,606	)

Total Storage Activities			9,232			1,539
Marketing Activities
	Realized margin		30,835			27,269
	Unrealized margin		(2,063	)		552

Total Marketing Activities			28,772			27,821

Gross profit		$	38,004		$	29,360

Ending storage balance (Bcf)			11.0			5.8

Our natural gas marketing segment’s gross profit margin was $38.0 million for the six months ended March 31, 2005 compared to gross profit of $29.4 million for the six months ended March 31, 2004. Natural gas marketing sales volumes were 141.0 Bcf during the six months ended March 31, 2005 compared with 151.4 Bcf for the prior year period. Excluding intersegment sales volumes, natural gas marketing sales volumes were 126.9 Bcf during the current year period compared with 126.1 Bcf in the prior year period. The slight increase in consolidated natural gas marketing sales volumes was primarily due to focusing our marketing

efforts on higher margin opportunities partially offset by warmer-than-normal weather across our market areas. Gross profit margin from our natural gas marketing segment for the six months ended March 31, 2005 included an unrealized loss of $10.1 million compared with an unrealized loss of $2.1 million in the prior-year period.

The contribution to gross profit from our storage activities was a gain of $9.2 million for the six months ended March 31, 2005 compared to a gain of $1.5 million for the six months ended March 31, 2004. The $7.7 million improvement primarily was attributable to a $13.1 million improvement in the realized storage contribution, partially offset by a $5.4 million decrease in the unrealized storage contribution for the six months ended March 31, 2005 compared to the prior year period. The improvement in the realized storage contribution for the six months ended March 31, 2005 primarily was due to higher physical storage volumes and more favorable arbitrage spreads from increased market activity. The decrease in unrealized income in the current period was primarily attributable to an unfavorable movement during the six months ended March 31, 2005 in the forward indices used to value the storage financial instruments combined with greater physical natural gas storage quantities at March 31, 2005 compared to the prior year period.

Our marketing activities contributed $28.8 million to our gross profit for the six months ended March 31, 2005 compared to $27.8 million for the six months ended March 31, 2004. The increase in the marketing contribution primarily was attributable to improved realized margins resulting from focusing our marketing efforts on higher margin customers, partially offset by the recognition of previously unrealized losses related to the open fixed-price forward contracts that were designated as cash flow hedges on April 1, 2004.

Operating expenses decreased to $8.6 million for the six months ended March 31, 2005 from $9.5 million for the six months ended March 31, 2004. The decrease in operating expense was attributable primarily to a decrease in contract labor costs due to systems and process improvements in the natural gas marketing segment.

The improved gross profit margin and lower operating expenses resulted in an increase in our natural gas marketing segment operating income to $29.4 million for the six months ended March 31, 2005 compared with operating income of $19.9 million for the six months ended March 31, 2004.


	*Pipeline and Storage Segment*


	Operating Income

Pipeline and storage gross profit increased to $83.6 million for the six months ended March 31, 2005 from $6.9 million for the six months ended March 31, 2004. Total pipeline transportation volumes were 288.9 Bcf during the six months ended March 31, 2005 compared with 5.2 Bcf for the prior year period. Excluding intersegment transportation volumes, total pipeline transportation volumes were 157.0 Bcf during the current year period.

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 $76.2 million and 157.0 Bcf. The $0.5 million increase in the gross profit generated by Atmos Pipeline and Storage, LLC primarily reflects an unrealized gain of $0.2 million compared with and unrealized loss in the prior year period of $0.4 million.

Operating expenses increased to $41.0 million for the six months ended March 31, 2005 from $2.8 million for the six months ended March 31, 2004 due to the addition of $38.9 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 effect on net income. Included in operating expense was $4.4 million associated with taxes other than income taxes, of which $4.1 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 six months ended March 31, 2005 increased to $42.6 million from $4.1 million for the six months ended March 31, 2004.


	Interest charges

Interest charges allocated to this segment for the six months ended March 31, 2005 increased to $12.4 million from $0.6 million for the six months ended March 31, 2004. The increase was attributable to the interest expense associated with the issuance of long-term debt to finance the acquisition of the Atmos Pipeline — Texas Division in October 2004.


	Other Nonutility Segment

Operating income during the six months ended March 31, 2005 was flat compared with the prior year quarter and reflects the absence of a one time charge of $0.4 million associated with the wind-down of a noncore business.

Miscellaneous income for the six months ended March 31, 2005 was $1.2 million, compared with income of $6.1 million for the six months ended March 31, 2004. The $4.9 million decrease was attributable primarily to the recognition of a $4.9 million pretax gain associated with the sale by USP of its general and limited partnership interests in Heritage Propane Partners, L.P. during the second quarter of fiscal 2004.

Liquidity and Capital Resources

Our working capital and liquidity for capital expenditures 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 the remainder of fiscal 2005.


	Capitalization

The following presents our capitalization as of March 31, 2005 and September 30, 2004:


	March 31, 2005			September 30, 2004

	(In thousands, except percentages)
Short-term debt	$	—	—	$	—	—
Long-term debt		2,260,704	58.1%		867,219	43.3	%
Shareholders’ equity		1,632,270	41.9%		1,133,459	56.7	%

Total capitalization, including short-term debt	$	3,892,974	100.0%	$	2,000,678	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 58.1 percent at March 31, 2005, and 43.3 percent at September 30, 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 acquisition, we intend to reduce our capitalization ratio to a target range of 53 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, the successful integration of the natural gas distribution and pipeline operations of TXU Gas we acquired and other factors.


	Cash flows from operating activities

Year-over-year changes in our operating cash flows are attributable primarily to changes in net income, 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 six months ended March 31, 2005, we generated operating cash flow of $400.1 million compared with $290.6 million for the six months ended March 31, 2004. Our cash flow from operating activities was affected by the following:


	•	Favorable movements during the six months ended March 31, 2005 in the market indices used to value our risk management assets and liabilities favorably impacted operating cash flow by $19.3 million. However, unfavorable movements in the market indices used to value our natural gas marketing segment risk management assets and liabilities resulted in a net liability for that segment. Accordingly, under the terms of the associated derivative contracts, we were required to deposit $17.0 million into a margin account, which resulted in a $34.9 million unfavorable impact to operating cash flow compared with the prior year period.

	•	The timing of cash collections from our customers unfavorably impacted operating cash flow by $72.0 million.

	•	The timing of payments for accounts payable and other accrued liabilities favorably affected operating cash flow by $147.0 million.

	•	Increases in our natural gas inventories attributable to lower utility sales volumes, a 9 percent higher utility average cost of gas and increased natural gas marketing natural gas inventory levels compared with the prior year period resulted in a $26.5 million decrease in operating cash flows.

	•	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 resulted in a decrease in operating cash flows of $62.4 million.

	•	Other working capital and other changes positively affected operating cash flow by $139.0 million, primarily related to improved net income ($60.3 million) and increases in the amounts added back to net income for depreciation and amortization ($42.7 million) and deferred income taxes ($32.5 million).


	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. Capital expenditures for fiscal 2005 are expected to range from $340 million to $350 million. Of this amount, approximately $185 — $195 million is expected to be incurred by the Mid-Tex Division and Atmos Pipeline — Texas Division.

For the six months ended March 31, 2005, we incurred $137.5 million for capital expenditures compared with $83.7 million for the six months ended March 31, 2004. Capital expenditures for the six months ended March 31, 2005 include approximately $45.8 million for the Atmos Energy Mid-Tex Division and $7.9 million for the Atmos Pipeline — Texas Division.

Our cash used for investing activities for the six months ended March 31, 2005 reflects the $1.9 billion cash paid for the TXU Gas acquisition including related transaction costs and expenses. The final purchase price is subject to adjustment for the actual amount of working capital we acquired and other specified matters. We anticipate that the purchase price will be finalized during the third quarter of fiscal 2005. Cash

flow from investing activities for the six months ended March 31, 2004 reflect the receipt of $24.7 million from the sale of our limited and general partnership interests in USP in January 2004.


	Cash flows from financing activities

For the six months ended March 31, 2005, our financing activities provided $1.7 billion in cash compared with a use of cash of $133.2 million for the prior year period. Our significant financing activities for the six months ended March 31, 2005 and 2004 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 shelf registration statement declared effective in September 2004, generating net proceeds of $382.0 million. Additionally, we issued senior unsecured debt under the shelf 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. 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 pay off 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 six months ended March 31, 2005 we borrowed and repaid all amounts borrowed under our commercial paper program. During the six months ended March 31, 2004, we repaid $118.6 million under our commercial paper program. Strong operating cash flow in each quarter provided sufficient funds to enable us to repay all outstanding amounts under our commercial paper program as of March 31, 2005 and March 31, 2004.

	•	We repaid $3.8 million of long-term debt during the six months ended March 31, 2005 compared with $5.5 million during the six months ended March 31, 2004. The decreased payments during the current quarter reflected the timing of the maturities of our various debt obligations.

	•	During the six months ended March 31, 2005 we paid $49.2 million in cash dividends compared with dividend payments of $31.6 million for the six months ended March 31, 2004. The increase in dividends paid over the prior year period reflects the 27.6 million increase in the number of common shares outstanding and an increase in the dividend rate from $0.61 per share during the six months ended March 31, 2004 to $0.62 per share during the six months ended March 31, 2005.

	•	During the six months ended March 31, 2005 we issued 1.0 million shares of common stock, in addition to the 16.1 million common shares issued in our October 2004 public offering, which generated net proceeds of $26.0 million. The following table summarizes the issuances for the six months ended March 31, 2005 and 2004:


			Six Months Ended
			March 31

			2005		2004

Shares issued:
	Retirement Savings Plan			242,810		164,059
	Direct Stock Purchase Plan			240,910		296,833
	Outside Directors Stock-for-Fee Plan			1,242		1,627
	Long-Term Incentive Plan			492,801		297,676
	Public Offering			16,100,000		—

		Total shares issued		17,077,763		760,195


	*Shelf Registration*

In August 2004, we filed a shelf registration statement with the Securities and Exchange Commission (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 and issued $1.4 billion in unsecured senior notes to partially finance the TXU Gas acquisition. After these issuances, we have approximately $401.5 million of availability remaining under the shelf 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. These facilities are described in further detail in Note 6 to the condensed consolidated financial statements.


	*Credit Rating*

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 risk associated with our utility and nonutility businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Inc. (Fitch). Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Long-term debt

BBB

Baa3

BBB+

Commercial paper

A-2

P-3

F-2

Currently, 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 our $600.0 million credit facility to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At March 31, 2005, our total-debt-to-total-capitalization ratio, as defined, was 60 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 March 31, 2005, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.95.

Our 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, 1988, may not exceed the sum of our accumulated net income for periods after December 31, 1988, plus $15.0 million. At March 31, 2005, approximately $202.4 million of retained earnings was unrestricted with respect to the payment of dividends.


	*Contractual Obligations and Commercial Commitments*

As a result of the issuance of our unsecured senior notes in October 2004 our contractual obligations associated with our long-term debt and interest expense increased since September 30, 2004.

The following table reflects the significant changes in our contractual obligations as of March 31, 2005. There were no other significant changes in our contractual obligations and commercial commitments during the six months ended March 31, 2005.


	Payments Due by Period

			Less than						After
	Total		1 year		1-3 years		3-5 years		5 years

	(In thousands)
Contractual Obligations
Long-term debt⁽¹⁾	$	2,264,701	$	5,887	$	312,874	$	411,678	$	1,534,262
Interest charges		1,268,716		118,242		234,249		210,648		705,577
Gas purchase commitments⁽²⁾		422,465		206,029		158,632		21,710		36,094


⁽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 March 31, 2005.

Additionally, 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 will contribute up to $42.5 million within two years of signing a definitive agreement.


	*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 protect us and our customers against unusually large winter-period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock-in our gross profit margin through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could recognize significant ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting resulting in the derivatives being treated as mark to market instruments through earnings.

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 tables show the components of the change in the fair value of our utility and natural gas marketing commodity derivative contracts for the three and six months ended March 31, 2005 and 2004:


		Three Months Ended						Three Months Ended
		March 31, 2005						March 31, 2004

					Natural Gas						Natural Gas
		Utility			Marketing			Utility			Marketing

		(In thousands)
Fair value of contracts at beginning of period		$	(9,412	)	$	5,214		$	5,699		$	1,270
	Contracts realized/settled		(6,276	)		(4,907	)		(842	)		(529	)
	Fair value of new contracts		(173	)		—			20			26
	Other changes in value		40,228			(6,203	)		(4,583	)		420

Fair value of contracts at end of period		$	24,367		$	(5,896	)	$	294		$	1,187


		Six Months Ended						Six Months Ended
		March 31, 2005						March 31, 2004

					Natural Gas						Natural Gas
		Utility			Marketing			Utility			Marketing

		(In thousands)
Fair value of contracts at beginning of period		$	(8,612	)	$	13,018		$	(7,739	)	$	10,144
	Contracts realized/settled		(45,397	)		(16,534	)		(4,145	)		(5,194	)
	Fair value of new contracts		(2,854	)		—			322			(797	)
	Other changes in value		81,230			(2,380	)		11,856			(2,966	)

Fair value of contracts at end of period		$	24,367		$	(5,896	)	$	294		$	1,187

The fair value of our utility and natural gas marketing derivative contracts at March 31, 2005, is segregated below by time period and fair value source:


	Fair Value of Contracts at March 31, 2005

	Maturity in Years

									Greater		Total Fair
Source of Fair Value	Less than 1			1-3			4-5		Than 5		Value

	(In thousands)
Prices actively quoted	$	19,214		$	(279	)	$	—	$	—	$	18,935
Prices provided by other external sources		100			8			—		—		108
Prices based on models and other valuation methods		(14	)		(558	)		—		—		(572	)

Total Fair Value	$	19,300		$	(829	)	$	—	$	—	$	18,471


	*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 the most advantageous price to lock in a gross profit margin. AEM is able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

Natural gas inventory is marked to market monthly using the Inside FERC (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 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; 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 the optimization efforts are fully successful.

As of March 31, 2005, based upon AEM’s derivatives position and inventory withdrawal schedule, the forecasted gross profit margin was approximately $8.0 million. Approximately $9.0 million of net unrealized losses were recorded in the financial statements as of March 31, 2005. Therefore, the projected increase in future gross profit margin is approximately $17.0 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 March 31, 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*

For the six months ended March 31, 2005 and 2004 our total net periodic pension and other benefits cost was $18.2 million and $13.7 million. All of these costs are recoverable through our gas utility rates; however, a portion of these costs is capitalized into our utility rate base. The remaining costs are recorded as a component of operation and maintenance expense.

The increase in total net periodic pension and other benefits cost during the current year period compared with the prior year period primarily reflects an increase in our service cost associated with an increase in the number of employees due to the TXU Gas acquisition, which increased our service cost. Additionally, we increased our discount rate and reduced our assumed rate of return on our pension plan assets for fiscal 2005, which increased our service and interest cost and reduced our expected return on plan assets, which partially offsets our net periodic pension and other benefits cost.

We did not contribute to our pension plans during the six months ended March 31, 2005. We are not required to make a minimum funding contribution nor do we anticipate making any voluntary contributions during fiscal 2005. During the six months ended March 31, 2005, we contributed $4.5 million to our other post-retirement plans and we expect to contribute a total of $11.7 million to these plans during fiscal 2005.

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. For purposes of our post-retirement 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.

Operating Statistics and Other Information

The following tables present certain operating statistics for our utility, natural gas marketing, pipeline and storage and other nonutility segments for the three and six-month periods ended March 31, 2005 and 2004.


	*Utility Sales and Statistical Data*


			Three Months Ended						Six Months Ended
			March 31						March 31

			2005⁽¹⁾			2004			2005⁽¹⁾			2004

METERS IN SERVICE, end of period
	Residential			2,884,807			1,507,992			2,884,807			1,507,992
	Commercial			279,194			152,763			279,194			152,763
	Industrial			2,789			2,482			2,789			2,482
	Agricultural			10,070			8,987			10,070			8,987
	Public-authority and other			8,752			10,177			8,752			10,177

		Total meters		3,185,612			1,682,401			3,185,612			1,682,401

HEATING DEGREE DAYS⁽²⁾
	Actual (weighted average)			1,422			1,772			2,415			3,012
	Percent of normal			90	%		97	%		89	%		96	%
UTILITY SALES VOLUMES — MMcf⁽³⁾
Gas sales volumes
	Residential			78,477			46,874			129,246			74,381
	Commercial			37,048			19,112			64,911			32,468
	Industrial			9,648			6,543			17,891			12,792
	Agricultural			60			310			126			805
	Public authority and other			2,962			4,345			6,978			7,419

		Total gas sales volumes		128,195			77,184			219,152			127,865
Utility transportation volumes				33,845			26,112			63,586			46,792

Total utility throughput				162,040			103,296			282,738			174,657

UTILITY OPERATING REVENUES (000’s)⁽³⁾
Gas sales revenues
	Residential		$	780,890		$	437,719		$	1,304,033		$	701,268
	Commercial			325,305			172,407			590,297			287,971
	Industrial			69,422			45,806			135,922			90,352
	Agricultural			587			2,097			1,262			5,131
	Public-authority and other			29,742			35,037			62,172			56,946

		Total utility gas sales revenues		1,205,946			693,066			2,093,686			1,141,668
Transportation revenues				17,312			8,970			33,744			17,071
Other gas revenues				12,119			6,246			21,628			10,031

		Total utility operating revenues	$	1,235,377		$	708,282		$	2,149,058		$	1,168,770

Utility average transportation revenue per Mcf			$	0.51		$	0.34		$	0.53		$	0.36
Utility average cost of gas per Mcf sold			$	7.12		$	6.72		$	7.16		$	6.58

See footnotes following these tables.


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


			Three Months Ended				Six Months Ended
			March 31				March 31

			2005		2004		2005		2004

CUSTOMERS, end of period
	Industrial			632		620		632		620
	Municipal			78		77		78		77
	Other			474		210		474		210

		Total		1,184		907		1,184		907

NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽³⁾				74,834		81,152		140,972		151,356
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽³⁾				158,923		2,801		288,917		5,231
OPERATING REVENUES (000’s)⁽³⁾
	Natural gas marketing		$	512,891	$	517,218	$	1,006,692	$	891,047
	Pipeline and storage			45,546		9,967		89,236		12,886
	Other nonutility			1,278		687		2,637		1,396

		Total operating revenues	$	559,715	$	527,872	$	1,098,565	$	905,329

Notes to preceding tables:


⁽¹⁾	The operational and statistical information includes the operations of the Mid-Tex Division and Atmos Pipeline — Texas Division 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 for the three and six month periods ended March 31, 2005 and 2004 is adjusted for the Kentucky Division, the Mississippi Division and certain service areas included within the Colorado-Kansas Division, the Mid-States Division and the West Texas Division, which have weather normalized operations.

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


	*Recent Ratemaking Activity*

The following discusses our recent ratemaking activities during fiscal 2005. The amounts described below represent the gross revenues that were requested or received in the rate filing, which may not necessarily reflect the increase in operating income obtained, as certain operating costs may have increased as a result of a commission’s final ruling.

Mississippi. The Mississippi Public Service Commission (MPSC) typically requires that we file for rate adjustments every six months. Beginning with the November 2004 filing, rate filings have been made in May and November of each year and the rate adjustments typically become 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 improve our rate design and the ratemaking process.

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 also disallowed certain deferred costs totaling $2.8 million. We withdrew our appeal regarding the MPSC’s decision regarding this disallowance.

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 into our rates effective January 1, 2005. In February 2005, we entered into a stipulation agreement with the Mississippi Public Utilities Staff that provides for an additional $1.3 million in annualized revenue that is retroactive to January 2005, which was approved by the MPSC during the second quarter of fiscal 2005.

Mid-Tex. In December 2004, we made a filing under the Gas Reliability Infrastructure Program (GRIP) to include approximately $32.0 million of distribution and pipeline capital expenditures made by TXU Gas during calendar year 2003, which will result in additional revenues of approximately $6.8 million. In March 2005, the Railroad Commission of Texas (the Commission) approved the environs (outside of the city limits) portion of the filing. The Mid-Tex Division is continuing to work to obtain approval for the filing from the cities in its service area. We expect these capital costs will be recovered through a monthly customer charge beginning in the second half of fiscal 2005. The allowed rate of return is 8.258 percent.

In September 2004, the Mid-Tex Division filed its 36-Month Gas Contract Review with the Railroad Commission of Texas (the Commission). 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. The proceeding has involved informal discussions in preparation for potential settlement discussions. A formal procedural schedule has been adopted providing for formal discovery and a formal hearing has been established for June 2005 in the event that settlement can not be reached.

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 the last rate case. Additionally, the Mid-Tex Division is seeking the right to surcharge for gas cost underrecoveries. The case has been assigned to a judge and a briefing schedule has been established.

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 Commission issued an order authorizing the recovery of the $10.2 million of expenses over a 3-year period with interest.

Atmos Pipeline-Texas. Concurrent with our Mid-Tex Division GRIP filing in December 2004, we also made a GRIP filing for our regulated pipeline to include approximately $12.0 million of distribution and pipeline capital expenditures made by TXU Gas during calendar year 2003, which will result in additional revenues of approximately $1.8 million. The Commission approved this filing in March 2005. These capital

costs will be recovered through a monthly customer charge beginning in April 2005. The allowed rate of return is 8.258 percent.

Louisiana. 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 for the three and six months ended March 31, 2005.


	*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 condensed consolidated financial statements.


Item 3.	*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.

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

Commodity Price Risk


	*Utility segment*

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

For our utility segment, we use a sensitivity analysis to estimate commodity price risk. For purposes of this analysis, we estimate commodity price risk by applying a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on projected non-regulated gas sales for the remainder of fiscal 2005, a hypothetical 10 percent increase in fixed prices, based upon the March 31, 2005 three month market strip, would increase our purchased gas cost by approximately $5.1 million for the remainder of fiscal 2005.


	*Natural gas marketing segment*

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) at the end of each period. Because AEH had no net open positions (including existing storage) at March 31, 2005 there would be no impact on our consolidated net income due to fluctuations in the forward NYMEX price.

Interest Rate Risk

Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short term borrowings. Had interest rates associated with our short term borrowings increased by an average of one percent, our interest expense would have increased by approximately $0.4 million during the six months ended March 31, 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 would have increased by approximately $171.4 million.

As of March 31, 2005 we were not engaged in other activities that would cause exposure to the risk of material earnings or cash flow loss due to changes in interest rates or market commodity prices.


Item 4.	*Controls and Procedures*

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including the Chairman, President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) and 15d-15(b). Based upon that evaluation, the Chairman, President and Chief Executive Officer, and the Senior Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures continue to be effective. Such disclosure controls and procedures are controls and procedures designed to ensure that all information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods set forth in applicable Securities and Exchange Commission rules and forms.

In addition, our management, including the Chairman, President and Chief Executive Officer, and the Senior Vice President and Chief Financial Officer, evaluated our internal control over financial reporting pursuant to Exchange Act Rules 13a-15(d) and 15d-15(d). Based upon that evaluation, management has concluded that there has been no change in such internal control during the second quarter of fiscal 2005 that has materially affected or is reasonably likely to materially affect the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.	*Legal Proceedings*

During the six months ended March 31, 2005 there were no material changes in the status of the litigation and environmental matters that were disclosed in Note 13 to our annual report on Form 10-K for the year ended September 30, 2004 except as disclosed in Note 10 to the condensed consolidated financial statements for the three months and six months ended March 31, 2005. With the acquisition of the natural gas distribution and pipeline operations of TXU Gas Company on October 1, 2004, we assumed responsibility for certain litigation and claims that arose in the ordinary course of the business of TXU Gas Company. 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.


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

At the Annual Meeting of Shareholders of Atmos Energy Corporation on February 9, 2005, 69,682,922 votes were cast as follows:


			Votes		Votes		Non
	Votes FOR		Withheld		Abstaining		Votes

Class I Directors:
Travis W. Bain II		68,784,090		898,832		—		—
Dan Busbee		67,527,549		2,155,373		—		—
Richard K. Gordon		67,311,614		2,371,308		—		—
Gene C. Koonce		69,001,916		681,006		—		—

Class II Director:
Nancy K. Quinn		68,787,916		895,006		—		—

Approval of amendment to the Articles of Incorporation to increase the number of authorized shares from 100,000,000 to 200,000,000:		64,288,928		5,016,823		377,162		9

The other directors will continue to serve until the expiration of their terms. The term of the Class I directors, Travis W. Bain II, Dan Busbee, Richard K. Gordon and Gene C. Koonce, will expire in 2008. The term of the Class II directors, Richard W. Cardin, Thomas C. Meredith, Nancy K. Quinn and Richard Ware II will expire in 2006. The term of the Class III directors, Robert W. Best, Thomas J. Garland, Phillip E. Nichol and Charles K. Vaughan, will expire in 2007.


Item 6.	*Exhibits*

A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.

SIGNATURES

Pursuant to the requirements 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
	(Duly authorized signatory)

Date: May 10, 2005

EXHIBITS INDEX

Item 6(a)


Exhibit			Page
Number		Description	Number

	3(I)	Amended and Restated Articles of Incorporation of Atmos Energy Corporation (as of February 9, 2005)
	12	Computation of ratio of earnings to fixed charges
	15	Letter regarding unaudited interim financial information
	31	Rule 13a-14(a)/15d-14(a) Certifications
	32	Section 1350 Certifications*

These certifications, which were made 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 Quarterly Report on Form 10-Q, will not be deemed to be filed with the 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.

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Atmos Energy (ATO) 10-Q2005 Q2 Quarterly report

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