ATMOS ENERGY CORP - 10-Q 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, 2004

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

Commission File Number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)


Texas and Virginia		75-1743247
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas (Address of principal executive offices)		75240 (Zip code)

(Registrant’s telephone number, including area code)

(972) 934-9227

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 May 3, 2004.


Class		Shares Outstanding

No Par Value		52,319,505

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION
	Item 1. Financial Statements
	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 and Reports on Form 8-K
SIGNATURES
Amendment & Joinder Agreement to Credit Agreement
Amendment to Credit Agreement
Lease Agreement
Computation of Ratio of Earnings to Fixed Charges
Letter Re: 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,
			2004		2003

			(Unaudited)

			(In thousands)
ASSETS
Property, plant and equipment			$	2,552,376	$	2,480,139
	Less accumulated depreciation and amortization			891,040		855,745

		Net property, plant and equipment		1,661,336		1,624,394
Current assets
	Cash and cash equivalents			114,983		15,683
	Cash held on deposit in margin account			—		17,903
	Accounts receivable, net			396,879		216,783
	Gas stored underground			74,570		168,765
	Other current assets			54,057		38,863

		Total current assets		640,489		457,997
Goodwill and intangible assets				275,873		273,499
Deferred charges and other assets				243,494		271,023

			$	2,821,192	$	2,626,913

CAPITALIZATION AND LIABILITIES
Shareholders’ equity
	Common stock, no par value (stated at $.005 per share); 100,000,000 shares authorized; issued and outstanding: March 31, 2004 — 52,235,980 shares; September 30, 2003 — 51,475,785 shares		$	261	$	257
	Additional paid-in capital			753,770		736,180
	Retained earnings			178,769		122,539
	Accumulated other comprehensive income (loss)			49		(1,459	)

		Shareholders’ equity		932,849		857,517
Long-term debt				864,624		863,918

		Total capitalization		1,797,473		1,721,435
Current liabilities
	Accounts payable and accrued liabilities			365,996		179,852
	Other current liabilities			171,822		133,957
	Short-term debt			—		118,595
	Current maturities of long-term debt			8,093		9,345

		Total current liabilities		545,911		441,749
Deferred income taxes				234,355		223,350
Regulatory cost of removal obligation				104,152		102,371
Deferred credits and other liabilities				139,301		138,008

			$	2,821,192	$	2,626,913

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



				Three Months Ended
				March 31

				2004			2003


				(Unaudited)

				(In thousands, except
				per share data)
Operating revenues
	Utility segment			$	708,282		$	696,561
	Natural gas marketing segment				517,218			620,402
	Other nonutility segment				10,654			9,657
	Intersegment eliminations				(118,669	)		(132,478	)

					1,117,485			1,194,142
Purchased gas cost
	Utility segment				518,820			502,728
	Natural gas marketing segment				505,356			618,752
	Other nonutility segment				5,681			2,134
	Intersegment eliminations				(118,498	)		(132,440	)

					911,359			991,174

	Gross profit				206,126			202,968
Operating expenses
	Operation and maintenance				59,093			55,665
	Depreciation and amortization				23,138			20,887
	Taxes, other than income				18,481			18,538

			Total operating expenses		100,712			95,090

Operating income					105,414			107,878
Miscellaneous income (expense)					4,456			(1,489	)
Interest charges					16,160			16,158

Income before income taxes and cumulative effect of accounting change					93,710			90,231
Income tax expense					35,405			33,926

Income before cumulative effect of accounting change					58,305			56,305
Cumulative effect of accounting change, net of income tax benefit					—			(7,773	)

			Net income	$	58,305		$	48,532

Per share data
	Basic income per share:
		Income before cumulative effect of accounting change		$	1.12		$	1.24
		Cumulative effect of accounting change, net of income tax benefit			—			(.17	)

		Net income		$	1.12		$	1.07

	Diluted income per share:
		Income before cumulative effect of accounting change		$	1.12		$	1.24
		Cumulative effect of accounting change, net of income tax benefit			—			(.17	)

		Net income		$	1.12		$	1.07

Cash dividends per share				$	.305		$	.300

Weighted average shares outstanding:
	Basic				51,850			45,306

	Diluted				52,240			45,493

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



				Six Months Ended
				March 31

				2004			2003


				(Unaudited)

				(In thousands, except
				per share data)
Operating revenues
	Utility segment			$	1,168,770		$	1,096,529
	Natural gas marketing segment				891,047			963,900
	Other nonutility segment				14,282			12,557
	Intersegment eliminations				(192,998	)		(198,412	)

					1,881,101			1,874,574
Purchased gas cost
	Utility segment				840,884			773,223
	Natural gas marketing segment				861,687			958,260
	Other nonutility segment				6,008			1,008
	Intersegment eliminations				(192,657	)		(198,051	)

					1,515,922			1,534,440

	Gross profit				365,179			340,134
Operating expenses
	Operation and maintenance				116,009			106,169
	Depreciation and amortization				46,611			42,081
	Taxes, other than income				33,604			31,382

			Total operating expenses		196,224			179,632

Operating income					168,955			160,502
Miscellaneous income					5,663			2,635
Interest charges					33,495			31,637

Income before income taxes and cumulative effect of accounting change					141,123			131,500
Income tax expense					53,277			49,402

Income before cumulative effect of accounting change					87,846			82,098
Cumulative effect of accounting change, net of income tax benefit					—			(7,773	)

			Net income	$	87,846		$	74,325

Per share data
	Basic income per share:
		Income before cumulative effect of accounting change		$	1.70		$	1.87
		Cumulative effect of accounting change, net of income tax benefit			—			(.18	)

		Net income		$	1.70		$	1.69

	Diluted income per share:
		Income before cumulative effect of accounting change		$	1.69		$	1.86
		Cumulative effect of accounting change, net of income tax benefit			—			(.18	)

		Net income		$	1.69		$	1.68

Cash dividends per share				$	.61		$	.60

Weighted average shares outstanding:
	Basic				51,666			44,007

	Diluted				52,057			44,178

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



				Six Months Ended
				March 31

				2004			2003


				(Unaudited)
				(In thousands)
Cash Flows from Operating Activities
	Net income			$	87,846		$	74,325
	Adjustments to reconcile net income to net cash provided by operating activities:
		Cumulative effect of accounting change, net of income tax benefit			—			7,773
		Gain on the sale of assets			(4,898	)		—
		Depreciation and amortization:
			Charged to depreciation and amortization		46,611			42,081
			Charged to other accounts		601			1,004
		Deferred income taxes			10,081			14,912
		Other			(944	)		(4,911	)
		Net assets/liabilities from risk management activities			924			(7,188	)
		Net change in operating assets and liabilities			150,382			55,792

			Net cash provided by operating activities		290,603			183,788
Cash Flows from Investing Activities
	Capital expenditures				(83,729	)		(72,876	)
	Proceeds from the sale of assets				24,661			—
	Retirements of property, plant and equipment, net				2,878			576
	Acquisitions				(1,950	)		(74,650	)

			Net cash used in investing activities		(58,140	)		(146,950	)
Cash Flows from Financing Activities
	Net decrease in short-term debt				(118,595	)		(116,091	)
	Cash dividends paid				(31,616	)		(26,168	)
	Repayment of long-term debt				(5,546	)		(69,058	)
	Net proceeds from issuance of long-term debt				5,000			249,282
	Issuance of common stock				17,594			12,486
	Repayment of Mississippi Valley Gas debt				—			(70,938	)
	Proceeds from bridge loan				—			147,000
	Repayment of bridge loan				—			(147,000	)

			Net cash used by financing activities		(133,163	)		(20,487	)

Net increase in cash and cash equivalents					99,300			16,351
Cash and cash equivalents at beginning of period					15,683			46,827

Cash and cash equivalents at end of period				$	114,983		$	63,178

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2004


1.	Nature of Business

Atmos Energy Corporation 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 1.7 million residential, commercial, public-authority and industrial customers through our six regulated natural gas utility divisions, which cover the following service areas:


Division		Service Area

Atmos Energy Colorado-Kansas Division		Colorado, Kansas, Missouri⁽²⁾
Atmos Energy Kentucky Division		Kentucky
Atmos Energy Louisiana Division		Louisiana
Atmos Energy Mid-States Division		Georgia⁽²⁾, Illinois⁽²⁾, Iowa ⁽²⁾, Missouri⁽²⁾, Tennessee, Virginia⁽²⁾
Atmos Energy Texas Division		Texas
Mississippi Valley Gas Company Division ⁽¹⁾		Mississippi

⁽¹⁾ Acquired in December 2002.

⁽²⁾ Denotes locations where we have more limited service areas.

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.

Our nonutility businesses are organized under Atmos Energy Holdings, Inc. (AEH), and have operations in 18 states. Through September 30, 2003, Atmos Energy Marketing, LLC, together with its wholly owned subsidiaries Woodward Marketing, L.L.C. and Trans Louisiana Industrial Gas Company, Inc., comprised our natural gas marketing segment. Effective October 1, 2003, our natural gas marketing segment was reorganized. The operations of Atmos Energy Marketing, LLC and Trans Louisiana Industrial Gas Company, Inc. were merged into Woodward Marketing, L.L.C., which was renamed Atmos Energy Marketing, LLC (AEM).

AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas consumers, primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky, Louisiana and Mid-States divisions. These services consist primarily of furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas 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 other nonutility businesses consist primarily of the operations of Atmos Pipeline and Storage, L.L.C., Atmos Power Systems, Inc. and Atmos Energy Services, LLC (AES), which are wholly owned by AEH. Through Atmos Pipeline and Storage, L.L.C., we own or have an interest in underground storage fields in Kansas, Kentucky and Louisiana. Through Atmos Pipeline and Storage, L.L.C. we provide storage services to our customers for a fee, as well as capture pricing arbitrage through the use of derivatives. 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. Through AES, we provide natural gas management services. Prior to the second quarter of 2004, this entity conducted limited operations. However, beginning,

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

April 1, 2004, AES began providing natural gas supply management services to our utility operations in a limited number of states. We expect to expand these services to substantially all of our utility service areas before the end of fiscal 2004.

Prior to January 20, 2004, United Cities Propane Gas, Inc., a wholly owned subsidiary of AEH, owned an approximate 19 percent membership interest in U.S. Propane L.P. (USP), a joint venture formed in February 2000 with three other utility companies. Through our ownership in USP, we owned an approximate 5 percent indirect interest in Heritage Propane Partners, L.P. On January 20, 2004, we and our partners in USP completed the sale of USP’s general and limited partnership interests in Heritage Propane Partners, L.P., for $130.0 million. We received cash proceeds of approximately $24.7 million and recorded a $4.9 million pretax book gain in the second quarter of fiscal 2004.


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, 2003. Because of seasonal and other factors, the results of operations for the three- and six-month periods ended March 31, 2004, are not indicative of expected results of operations for the fiscal year ending September 30, 2004.


	*Significant Accounting Policies*

Our accounting policies are described in Note 2 to our 2003 Annual Report on Form 10-K for the year ended September 30, 2003. As described in our Annual Report on Form 10-K, our utility depreciation rates approved by the various regulatory commissions included a component that allowed us to recover the cost of removing our assets. Historically, we recorded the associated obligation as a component of accumulated depreciation. This classification was consistent with others in the industry. Beginning in the second quarter of fiscal 2004, we are classifying our regulatory cost of removal obligation as a regulatory liability on the balance sheet. Additionally, for purposes of our September 30, 2003 information presented in this report, we reclassified from accumulated depreciation to regulatory liabilities a total of $108.4 million in regulatory cost of removal accruals at September 30, 2003, of which $102.4 million was a long-term regulatory liability. These reclassifications do not impact our financial position, results of operations, cash flows or ability to satisfy our financial covenants contained in our various credit agreements as of March 31, 2004 and September 30, 2003. Revised summary historical information reflecting the reclassification of our regulatory cost of removal obligation for the periods from September 30, 1999 to December 31, 2003 is contained in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	*Stock-based Compensation Plans*

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

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 months and six months ended March 31, 2004 and 2003 would have been impacted as shown in the following table:



		Three Months Ended						Six Months Ended
		March 31						March 31

		2004			2003			2004			2003


		(In thousands, except per share data)
Net income — as reported		$	58,305		$	48,532		$	87,846		$	74,325
Restricted stock compensation expense included in income, net of tax			98			61			196			130
Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of taxes			(385	)		(322	)		(778	)		(570	)

Net income — pro forma		$	58,018		$	48,271		$	87,264		$	73,885

Earnings per share:
	Basic earnings per share — as reported	$	1.12		$	1.07		$	1.70		$	1.69

	Basic earnings per share — pro forma	$	1.12		$	1.07		$	1.69		$	1.68

	Diluted earnings per share — as reported	$	1.12		$	1.07		$	1.69		$	1.68

	Diluted earnings per share — pro forma	$	1.11		$	1.06		$	1.67		$	1.67

No option grants have occurred under the Long-Term Stock Plan for the Mid-States Division since that entity was acquired in 1997. Due to the limited activities of that plan, the pro forma effect of applying SFAS 123 would have had less than a $0.01 per diluted share effect on earnings per share for the three and six months ended March 31, 2004 and 2003, or $381 and $753 for the three months ended March 31, 2004 and 2003 and $762 and $1,506 for the six months ended March 31, 2004 and 2003.


	*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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

customers through the ratemaking process. Significant regulatory assets and liabilities as of March 31, 2004 and September 30, 2003 included the following:


		March 31,		September 30,
		2004		2003


		(In thousands)
Regulatory assets:
	Deferred gas costs	$	30,881	$	308
	Merger and integration costs, net		19,702		23,380
	Deferred MVG operating expenses		6,250		4,645
	Environmental costs		4,057		4,057
	Other		1,608		2,509

		$	62,498	$	34,899

Regulatory liabilities:
	Regulatory cost of removal obligation	$	109,456	$	108,405
	Deferred income taxes, net		1,883		1,883

		$	111,339	$	110,288

Currently authorized rates do not include a return on our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are amortized on a straight-line basis over estimated useful lives ranging from 7 to 20 years. These costs will have been substantially amortized by December 2005. Environmental costs have been deferred to future rate filings in accordance with rulings received from various regulatory commissions.


	*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, 2004 and 2003:



	Three Months Ended					Six Months Ended
	March 31					March 31

	2004		2003			2004		2003


	(In thousands)
Net income	$	58,305	$	48,532		$	87,846	$	74,325
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $542 and $(460) for the three months ended March 31, 2004 and 2003 and net of tax expense (benefit) of $924 and $(489) for the six months ended March 31, 2004 and 2003		883		(750	)		1,508		(799	)

Comprehensive income	$	59,188	$	47,782		$	89,354	$	73,526

The only component of accumulated other comprehensive income (loss) relates to unrealized holding gains and losses associated with certain available-for-sale investments.


	*Recent Accounting Developments*

In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

is achieved through means other than through voting rights (variable interest entities (VIE)) and how to determine when to consolidate and which business enterprises should consolidate the VIE. The adoption of this interpretation did not have a material impact on our financial position, results of operations or net cash flows because we are not currently a beneficiary of a VIE.

During 2003, the Emerging Issues Task Force (the Task Force) added to its agenda Emerging Issues Task Force (EITF) Issue 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments, to address the meaning of “other-than-temporary” impairment and its application to certain investments carried at cost. In November 2003, the Task Force developed new disclosure requirements concerning unrealized losses on available-for-sale debt and equity securities accounted for under SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, which will be applicable to us beginning with our fiscal 2004 Annual Report on Form 10-K.

In December 2003, the FASB issued SFAS 132 (revised), Employers’ Disclosures about Pensions and Other Postretirement Benefits. These revisions require additional disclosures in annual reports concerning the assets, obligations, cash flows and net periodic-benefit cost of defined-benefit pension plans and other defined-benefit postretirement plans. Additionally, the statement now requires interim-period disclosures regarding net periodic pension cost and employer contributions. The annual disclosures will become fully effective for fiscal years ending after June 15, 2004, and the interim-period disclosures were effective for interim periods beginning after December 15, 2003. We have adopted the interim-period disclosures, which are contained in Note 8, and will adopt the annual disclosures beginning with our fiscal 2004 Annual Report on Form 10-K.

In January 2004, the FASB issued FASB Staff Position FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which permits a plan sponsor to defer recognizing the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) in the accounting for its plan under SFAS 106 and in providing disclosures related to the plan required by SFAS 132 (revised) until authoritative guidance on the accounting for the federal subsidy is issued. We have elected to recognize the provisions of the Act, beginning with the second quarter of fiscal 2004, which reduced our accumulated postretirement benefit obligation and our net postretirement benefit obligation costs by $4.1 million during the second quarter. The total income statement impact for fiscal 2004 will approximate $2.3 million, as a portion of this benefit will be capitalized.


3.	Acquisitions


	*Mississippi Valley Gas Company*

On December 3, 2002, we completed the acquisition of Mississippi Valley Gas Company (MVG), Mississippi’s largest natural gas utility. The acquisition of MVG enabled us to expand our service area into Mississippi, which is reflective of our overall strategy to grow through profitable acquisitions. MVG served approximately 261,500 residential, commercial, industrial and other customers located primarily in the northern and central regions of Mississippi. We paid approximately $74.7 million in cash and $74.7 million in Atmos Energy common stock consisting of 3,386,287 unregistered shares. We also repaid approximately $70.9 million of MVG’s outstanding debt. The results of operations of MVG have been consolidated with our results of operations from the acquisition date.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The table below reflects the unaudited pro forma results of the Company and MVG for the six months ended March 31, 2003 as if the acquisition had taken place at the beginning of fiscal 2003.


	Six Months Ended
	March 31, 2003

	(In thousands)
Operating revenue	$	1,910,331
Income before cumulative effect of accounting change		78,930
Net income		71,157
Income before cumulative effect of accounting change per diluted share	$	1.74
Net income per diluted share	$	1.57


	*ComFurT Gas Inc.*

Effective March 1, 2004, we completed the acquisition of the natural gas distribution assets of ComFurT Gas Inc., a privately held natural gas utility and propane distributor based in Buena Vista, Colorado, for approximately $2.0 million in cash. This company served approximately 1,800 natural gas utility customers. The acquisition enabled us to expand our contiguous service area in our Colorado-Kansas division. Unaudited pro forma results of the Company and ComFurT have not been presented as the acquisition has less than a $.01 per diluted share effect on earnings per share.


4.	Goodwill and Intangible Assets

Goodwill and intangible assets are comprised of the following as of March 31, 2004 and September 30, 2003.


	March 31,		September 30,
	2004		2003


	(In thousands)
Goodwill	$	271,278	$	268,469
Intangible assets		4,595		5,030

Total	$	275,873	$	273,499

The following presents our goodwill balance allocated by segment and changes in our balance for the six months ended March 31, 2004:


			Natural Gas		Other
	Utility		Marketing		Nonutility
	Segment		Segment		Segment		Total


	(In thousands)
Balance as of September 30, 2003	$	233,741	$	22,600	$	12,128	$	268,469
Acquisition		1,250		—		—		1,250
First quarter 2004 refinements to purchase price		1,559		—		—		1,559

Balance as of March 31, 2004	$	236,550	$	22,600	$	12,128	$	271,278

During the second quarter of 2004, we completed our annual goodwill impairment assessment. Based upon the assessment performed, our goodwill was not considered to be impaired.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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 based upon the anticipated settlement date of the underlying derivative. Our determination of the fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains and losses on open contracts. In our determination of fair value, we consider various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts.

The following table shows the fair values of our risk management assets and liabilities by segment at March 31, 2004 and September 30, 2003:


				Natural Gas
	Utility			Marketing			Total


	(In thousands)
March 31, 2004:
Assets from risk management activities, current	$	996		$	13,288		$	14,284
Assets from risk management activities, noncurrent		—			19			19
Liabilities from risk management activities, current		(702	)		(11,306	)		(12,008	)
Liabilities from risk management activities, noncurrent		—			(814	)		(814	)

Net assets	$	294		$	1,187		$	1,481

September 30, 2003:
Assets from risk management activities, current	$	202		$	22,057		$	22,259
Assets from risk management activities, noncurrent		—			1,699			1,699
Liabilities from risk management activities, current		(7,941	)		(12,849	)		(20,790	)
Liabilities from risk management activities, noncurrent		—			(763	)		(763	)

Net assets (liabilities)	$	(7,739	)	$	10,144		$	2,405


	*Utility Hedging Activities*

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. For the 2003-2004 heating season, we hedged between 50 and 55 percent of our anticipated winter flowing gas requirements at a weighted average cost of approximately $5.36 per MCF. These derivative financial instruments are marked to market pursuant to SFAS 133, Accounting for Derivative Financial Instruments and Hedging Activities. Because these costs will ultimately be recovered through our rates, current-period changes in the assets and liabilities from risk management activities are recorded as a component of deferred gas costs in accordance with SFAS 71 and recognized in purchased gas cost in the income statement when the related costs are recovered through our rates. Accordingly, there is no earnings impact as a result of the use of these financial instruments in our utility segment.

In June 2001, we purchased a three-year weather-insurance policy with an option to cancel the third year of coverage. The insurance covered our Texas and Louisiana operations to protect against weather that was at least 7 percent warmer than normal for the entire heating season of October through March, beginning with the 2001-2002 heating season. The prepaid cost of the three-year policy was $13.2 million and was amortized over the appropriate heating seasons based on heating degree days. In the third quarter of fiscal 2003, we cancelled this policy, primarily as a result of rate relief in Louisiana and prospects for weather normalization adjustments in Texas. During the three months and six months ended March 31, 2003, we recognized

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

amortization expense of $2.5 million and $4.4 million. However, we did not collect under this policy because weather was not at least 7 percent warmer than normal.


	*Nonutility Hedging Activities*

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

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

Under SFAS 133, natural gas inventory is the hedged item in a fair-value hedge and is marked to market on a monthly basis using the inside FERC (iFERC) price at the end of each month. Changes in fair value are recognized as unrealized gains and losses in the period of change. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenue and the carrying value of the inventory as an associated purchased gas cost in our condensed consolidated statement of income when we sell the gas and deliver it out of the storage facility.

Derivatives associated with our storage gas contracts 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) can result in volatility in our reported net income. Over time, gains and losses on the sale of storage gas inventory will be offset by gains and losses on the fair-value hedges, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

Similar to our inventory position, we attempt to mitigate substantially all of the commodity price risk associated with our fixed-price contracts with minimum volume requirements through the use of various offsetting derivatives. These derivatives are not designated as hedges under SFAS 133 because they naturally lock in the economic gross profit margin at the time we enter into the contract. The fixed-price forward and offsetting derivative contracts are marked to market each month with changes in fair value recognized as unrealized gains and losses in our condensed consolidated statement of income. The unrealized gains and losses are realized in the period in which we fulfill the requirements of the fixed-price contract and the derivatives are settled. To the extent that the unrealized gains and losses of the fixed-price forward contracts and the offsetting derivatives do not offset exactly, our earnings will experience some volatility. Over time, gains and losses on the fixed-price contracts will be offset by gains and losses on the derivatives, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

Effective April 1, 2004, we are changing the way we report the expected gross profit margin associated with our fixed-price contracts by electing to treat our fixed-price forward contracts as normal purchases and

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

sales. As a result, we will cease marking the fixed-price forward contracts to market. We have designated the offsetting derivative contracts as cash-flow hedges of anticipated transactions. As a result of this change, unrealized gains and losses on open contracts will be recorded as a component of accumulated other comprehensive income and will be recognized in earnings when the hedged volumes are sold. This designation is expected to reduce the amount of volatility somewhat in our condensed consolidated income statement and more accurately reflect the economics of the transaction.

Under our risk management policies, we seek to match our financial derivative positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on March 31, 2004, AEH had a net open position (including existing storage) of 0.1 Bcf.

On January 1, 2003, we recorded a cumulative effect of a change in accounting principle to reflect a change in the way we account for our storage and transportation contracts. Previously we accounted for those contracts under EITF 98-10, Accounting for Energy Trading and Risk Management Activities, which required us to record estimated future gains on our storage and transportation contracts at the time we entered into the contracts and to mark those contracts to market value each month. Effective January 1, 2003, we no longer marked those contracts to market. As a result, we expensed $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Debt


	*Long-Term Debt*

Long-term debt at March 31, 2004 and September 30, 2003 consisted of the following:


			March 31,			September 30,
			2004			2003


			(In thousands)
Unsecured 10% Notes, due 2011			$	2,303		$	2,303
Unsecured 7.375% Senior Notes, due 2011				350,000			350,000
Unsecured 5.125% Senior Notes, due 2013				250,000			250,000
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			11,250			13,750
	Series Q, 9.75% due 2020			17,000			17,000
	Series R, 11.32% due 2004			2,160			2,160
	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			4,167			6,733
Rental property, propane and other term notes due in installments through 2013				10,837			6,317

		Total long-term debt		872,717			873,263
Less current maturities				(8,093	)		(9,345	)

			$	864,624		$	863,918

Most of the 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, 2004, approximately $140.3 million of retained earnings were unrestricted with respect to the payment of dividends. We were in compliance with all of our debt covenants as of March 31, 2004.


	*Short-Term Debt*

At March 31, 2004, there were no short-term amounts outstanding under our commercial paper program or bank credit facilities. At September 30, 2003, short-term debt consisted of $118.6 million of commercial paper. No amounts were outstanding under our bank credit facilities at September 30, 2003.


	*Credit Facilities*

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.


	Committed Credit Facilities

We have two short-term committed credit facilities totaling $368.0 million, one of which is an unsecured facility for $350.0 million that bears interest at the Eurodollar rate plus 0.625 percent and serves as a backup liquidity facility for our commercial paper program. We have a second unsecured facility in place for $18.0 million that bears interest at the Fed Funds rate plus 0.5 percent and is used for working-capital purposes. At March 31, 2004, there were no amounts outstanding under this credit facility. These credit facilities are negotiated at least annually. On April 1, 2004, the $18.0 million working-capital credit facility was renewed for an additional 12 months on terms substantially similar to those of the prior facility.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently meet. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our $350.0 million credit facility to maintain a ratio of total debt to total capitalization of no greater than 70 percent. At March 31, 2004, our total-debt-to-total-capitalization ratio, as defined, was 51 percent.


	Uncommitted Credit Facilities

Until March 31, 2004, AEM had a $220.0 million uncommitted-demand working capital credit facility that bore interest at LIBOR plus 2.5 percent. On March 31, 2004, this facility was increased to $250.0 million and extended to March 31, 2005. The interest rate on this facility was not changed. Effective October 1, 2003, with the reorganization of our natural gas marketing segment, AEM became the borrower under the credit facility, and AEH became the sole guarantor of the facility. At March 31, 2004, no amounts were outstanding under this credit facility. AEM letters of credit totaling $118.3 million reduced the amount available in accordance with the terms of the facility. 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 $31.7 million at March 31, 2004.

We also have an unsecured short-term uncommitted credit line for $25.0 million that is used for working-capital and letter-of-credit purposes. There were no borrowings under this uncommitted credit facility at March 31, 2004, but Atmos Energy Corporation (AEC) letters of credit reduced the amount available by $2.9 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 LIBOR 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 back up AEM’s $250.0 million credit facility. This credit facility has been approved by our regulators through December 31, 2004. However, there is no assurance that our regulators will approve our use of this credit facility after that time. At March 31, 2004, $45.0 million was outstanding under this facility.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	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

		2004		2003			2004		2003


		(In thousands, except per share amounts)
Income before cumulative effect of accounting change		$	58,305	$	56,305		$	87,846	$	82,098
Cumulative effect of accounting change, net of income tax benefit			—		(7,773	)		—		(7,773	)

Net income		$	58,305	$	48,532		$	87,846	$	74,325

Denominator for basic income per share — weighted average common shares			51,850		45,306			51,666		44,007
Effect of dilutive securities:
	Restricted stock		132		121			132		121
	Stock options		258		66			259		50

Denominator for diluted income per share — weighted average common shares			52,240		45,493			52,057		44,178

Income per share — basic:
	Before cumulative effect of accounting change	$	1.12	$	1.24		$	1.70	$	1.87
	Cumulative effect of accounting change, net of income tax benefit		—		(.17	)		—		(.18	)

	Net income per share	$	1.12	$	1.07		$	1.70	$	1.69

Income per share — diluted:
	Before cumulative effect of accounting change	$	1.12	$	1.24		$	1.69	$	1.86
	Cumulative effect of accounting change, net of income tax benefit		—		(.17	)		—		(.18	)

	Net income per share	$	1.12	$	1.07		$	1.69	$	1.68

There were 3,000 and 1,065,667 out-of-the-money options excluded from the computation of diluted earnings per share for the three months ended March 31, 2004 and 2003 as their exercise price was greater than the average market price of the common stock during that period.

There were 3,000 and 1,228,027 out-of-the-money options excluded from the computation of diluted earnings per share for the six months ended March 31, 2004 and 2003 as their exercise price was greater than the average market price of the common stock during that period.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


8.	Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended March 31, 2004 and 2003 are presented below. The 2004 amounts reflect the impact of adopting the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) beginning in the second quarter of 2004.



			Pension Benefits						Other Benefits

			2004			2003			2004			2003


			(In thousands)
Components of net periodic pension cost:
	Service cost		$	2,433		$	2,060		$	1,405		$	1,476
	Interest cost			6,004			5,834			1,751			2,269
	Expected return on assets			(7,524	)		(5,988	)		(396	)		(253	)
	Amortization of transition asset			24			24			378			378
	Amortization of prior service cost			(2	)		35			96			92
	Amortization of actuarial loss			2,018			632			—			444

		Net periodic pension cost	$	2,953		$	2,597		$	3,234		$	4,406

The components of our net periodic pension cost for our pension and other post-retirement benefit plans for the six months ended March 31, 2004 and 2003 are as follows:



			Pension Benefits						Other Benefits

			2004			2003			2004			2003


			(In thousands)
Components of net periodic pension cost:
	Service cost		$	4,866		$	4,120		$	3,130		$	2,952
	Interest cost			12,008			11,668			3,854			4,538
	Expected return on assets			(15,048	)		(11,976	)		(731	)		(506	)
	Amortization of transition asset			48			48			756			756
	Amortization of prior service cost			(4	)		70			192			184
	Amortization of actuarial loss			4,036			1,264			635			888

		Net periodic pension cost	$	5,906		$	5,194		$	7,836		$	8,812

A portion of these costs is capitalized into our utility rate base, as these costs are recoverable through our gas utility rates. Costs that are not capitalized are recorded as a component of operating expense.

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2004 and 2003 are as follows:



	Pension Benefits				Other Benefits

	2004		2003		2004		2003

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

100 percent funded on an accumulated benefit obligation (ABO) basis. We did not contribute to our pension plan during the six months ended March 31, 2004. As of March 31, 2004, we were still assessing whether a voluntary contribution would be necessary during fiscal 2004.


9.	Commitments and Contingencies


	*Litigation*


	Colorado-Kansas Division

On September 23, 1999, a suit was filed in the District Court of Stevens County, Kansas, by Quinque Operating Company, Tom Boles and Robert Ditto against more than 200 companies in the natural gas industry, including us and our Colorado-Kansas Division. The plaintiffs, who purport to represent a class consisting of gas producers, royalty owners, overriding royalty owners, working interest owners and state taxing authorities, allege that the defendants have underpaid royalties on gas taken from wells situated on nonfederal and non-Indian lands throughout the United States and offshore waters, predicated upon allegations that the defendants’ gas measurements are simply inaccurate and that the defendants failed to comply with applicable regulations and industry standards over the last 25 years. Although the plaintiffs do not specifically allege an amount of damages, they contend that this suit is brought to recover billions of dollars in revenues that the defendants have allegedly unlawfully diverted from the plaintiffs to themselves. On April 10, 2000, this case was consolidated for pretrial proceedings with other similar pending litigation in federal court in Wyoming in which we are also a defendant, along with more than 200 other defendants, in the case of In Re Natural Gas Royalties Qui Tam Litigation. In January 2001, the federal court elected to remand this case to the Kansas state court. A reconsideration of remand was filed, but it was denied. The state court now has jurisdiction over this proceeding and has issued a preliminary case management order. On April 10, 2003, the court denied the plaintiffs’ motion to certify this proceeding as a class action, which ruling was appealed by the plaintiffs. The court did allow the plaintiffs to file an amended complaint, which is somewhat narrower in scope than the original complaint. There have since been no material developments in this case. We continue to believe that the plaintiffs’ claims are lacking in merit, and we intend to continue to vigorously defend this action. While the results of this litigation cannot be predicted with certainty, we believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.


	Texas Division

On February 13, 2002, a suit was filed in the 287th District Court of Parmer County, Texas, by Anderson Brothers, a Partnership, against Atmos Energy Corporation, et al. The plaintiffs’ claims arise out of an alleged breach of contract by us and by a number of our divisions and subsidiaries concerning the sale of natural gas used in irrigation activities since 1998 and an alleged violation of the Texas Agricultural Gas Users Act of 1985. We have reached a tentative settlement with the plaintiffs’ attorneys in this case. This settlement agreement must be approved by the court and then by the plaintiffs as a class, which is expected during fiscal 2004. We believe the final outcome of such litigation will not have a material adverse effect on our financial condition, results of operations or net cash flows.

We are a plaintiff in a case styled Energas Company, a Division of Atmos Energy Corporation v. ONEOK Energy Marketing and Trading Company, L.P., ONEOK Westex Transmission, Inc., and ONEOK Energy Marketing and Trading Company II, filed in December 2001, pending in the District Court of Lubbock County, Texas, 72nd Judicial District. In this case, we are seeking to collect our receivable related to approximately 5.0 Bcf of natural gas that we believe was not delivered. We have settled a portion of our claims with the parties and will continue to pursue recovery of the remaining claims, which we believe are fully recoverable. We are proceeding with discovery in this case, which has been set for trial in August 2004.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United Cities Propane Gas, Inc.

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

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


	*Environmental Matters*


	Manufactured Gas Plant Sites

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

United Cities Gas Company and the Tennessee Department of Environment and Conservation (TDEC) entered into a consent order effective January 23, 1997, to facilitate the investigation, removal and remediation of the Johnson City site. Prior to our merger with United Cities Gas Company in July 1997, United Cities Gas Company began the implementation of the consent order in the first quarter of 1997, which we continued through March 31, 2004. The investigative phase of the work at the site has been completed, and an interim removal action was completed in June 2001. We installed four groundwater monitoring wells at the site in 2002 and have submitted the analytical results to the TDEC. We have completed a risk assessment report that has been approved by the TDEC. Finally, we have completed a feasibility study for this site, which was submitted to the TDEC in October 2003. The feasibility study recommends a remedial action that will limit the use of and access to the impacted soil, cap the site with the addition of a clay fill and geosynthetic liner, and groundwater monitoring for a period of up to 30 years. The estimated cost of the proposed remedial action is $1.5 million, which is comprised primarily of operating and maintenance costs that would be associated with a groundwater monitoring project. The Tennessee Regulatory Authority granted us permission to defer, until our next rate case in Tennessee, all costs incurred in Tennessee in connection with state and federally mandated environmental control requirements.

In March 2002, the TDEC contacted us about conducting an investigation at a former manufactured gas plant located in Bristol, Tennessee. We agreed to perform a preliminary investigation at the site, which we completed in June 2002. The investigation identified manufactured gas plant residual materials in the soil beneath the site, and we have proposed performing a focused removal action to remove any such residuals. The TDEC has requested that the focused removal action be conducted pursuant to a voluntary agreement. We are continuing the process of negotiating the voluntary agreement with TDEC and hope to conduct the focused removal action later this year.

On July 22, 1998, we entered into an Abatement Order on Consent with the Missouri Department of Natural Resources to address the former manufactured gas plant located in Hannibal, Missouri. We agreed to perform a removal action and a subsequent site evaluation and to reimburse the response costs incurred by the

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

state of Missouri in connection with the property. The removal action was conducted and completed in August 1998, and the site-evaluation field work was conducted in August 1999. A risk assessment for the site has been approved by the Missouri Department of Natural Resources. In preparation for the risk assessment, we executed and recorded certain site-use limitations, including restricting use of the site to commercial and industrial purposes and prohibiting the withdrawal of groundwater for use as drinking water.

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

As of March 31, 2004, we had incurred costs of approximately $1.7 million for the investigations of the Johnson City and Bristol, Tennessee, and Hannibal, Missouri, sites and had a remaining accrual relating to these sites of $0.2 million, which is recorded as a component of other current liabilities.

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


	*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, 2004, AEM is committed to purchase 69.4 Bcf within one year and 1.7 Bcf within one to three years under indexed contracts. AEM is committed to purchase 1.1 Bcf within one year under fixed-price contracts, with prices ranging from $4.08 to $5.79. Purchases under these contracts totaled $401.3 million and $525.2 million for the three months ended March 31, 2004 and 2003 and $698.0 and $798.6 million for the six months ended March 31, 2004 and 2003.

Our utility segment maintains supply contracts with several vendors, generally for 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.


10.	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 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 counterparty nonperformance.

AEM’s estimated credit exposure is monitored in terms of the percentage of its customers that are rated as investment grade versus non-investment grade. Credit exposure is defined as the total of (1) accounts receivable, (2) delivered, but unbilled physical sales and (3) mark-to-market exposure for sales and purchases. Investment grade determinations are set internally by the credit department, but are primarily based on external ratings provided by Moody’s Investor Service Inc. and/or Standard & Poor’s Rating Service, a Division of the McGraw-Hill Companies, Inc. For non-rated entities, the default rating for municipalities is investment grade, while the default rating for non-guaranteed industrials and commercials is non-investment grade. The table below shows the percentages related to the investment ratings as of March 31, 2004 and September 30, 2003. As indicated below, a majority of AEM’s customers are rated as investment grade.


		March 31,		September 30,
		2004		2003

Investment-grade			61%		59%
Noninvestment-grade			39%		41%

	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, 2004. Investment-grade counterparties have minimum credit ratings of BBB-, assigned by Standard & Poor’s Rating Group; or Baa3, assigned by Moody’s Investor Service. Non-investment-grade counterparties are composed of counterparties that are below investment grade or that have not been assigned an internal investment grade rating due to the short-term nature of the contracts associated with that counterparty. This category is composed of numerous smaller counterparties, none of which is individually significant.



	At March 31, 2004

			Natural Gas		Other
	Utility		Marketing		Nonutility
	Segment⁽¹⁾		Segment		Segment		Consolidated


	(In thousands)
Investment-grade counterparties	$	996	$	12,526	$	—	$	13,522
Noninvestment-grade counterparties		—		781		—		781

	$	996	$	13,307	$	—	$	14,303

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


11.	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 1.7 million residential, commercial, public-authority and industrial customers through our six 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. Finally, we

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

construct electric power-generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers.

Our operations are divided into three 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 and

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

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. The accounting policies of the segments are the same as those described in Note 2 to our 2003 Annual Report on Form 10-K for the year ended September 30, 2003. 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, 2004

					Natural Gas		Other
			Utility		Marketing		Nonutility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	707,985	$	406,112	$	3,388	$	—		$	1,117,485
Intersegment revenues				297		111,106		7,266		(118,669	)		—

				708,282		517,218		10,654		(118,669	)		1,117,485
Purchased gas cost				518,820		505,356		5,681		(118,498	)		911,359

	Gross profit			189,462		11,862		4,973		(171	)		206,126
Operating expenses				93,991		5,190		1,702		(171	)		100,712

Operating income				95,471		6,672		3,271		—			105,414
Miscellaneous income (expense)				1,266		229		4,939		(1,978	)		4,456
Interest charges				16,106		1,081		951		(1,978	)		16,160

Income before income taxes				80,631		5,820		7,259		—			93,710
Income tax expense				30,073		2,398		2,934		—			35,405

		Net income	$	50,558	$	3,422	$	4,325	$	—		$	58,305

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



			For the Three Months Ended March 31, 2003

						Natural Gas			Other
			Utility			Marketing			Nonutility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	696,132		$	493,780		$	4,230	$	—		$	1,194,142
Intersegment revenues				429			126,622			5,427		(132,478	)		—

				696,561			620,402			9,657		(132,478	)		1,194,142
Purchased gas cost				502,728			618,752			2,134		(132,440	)		991,174

	Gross profit			193,833			1,650			7,523		(38	)		202,968
Operating expenses				89,853			3,377			1,898		(38	)		95,090

Operating income (loss)				103,980			(1,727	)		5,625		—			107,878
Miscellaneous income (expense)				(1,377	)		344			467		(923	)		(1,489	)
Interest charges				16,161			388			532		(923	)		16,158

Income (loss) before income taxes and cumulative effect of accounting change				86,442			(1,771	)		5,560		—			90,231
Income tax expense (benefit)				32,390			(697	)		2,233		—			33,926

Income (loss) before cumulative effect of accounting change				54,052			(1,074	)		3,327		—			56,305
Cumulative effect of accounting change, net of income tax benefit				—			(7,773	)		—		—			(7,773	)

		Net income (loss)	$	54,052		$	(8,847	)	$	3,327	$	—		$	48,532



			For the Six Months Ended March 31, 2004

					Natural Gas		Other
			Utility		Marketing		Nonutility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	1,168,194	$	707,536	$	5,371	$	—		$	1,881,101
Intersegment revenues				576		183,511		8,911		(192,998	)		—

				1,168,770		891,047		14,282		(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		8,274		(341	)		365,179
Operating expenses				183,037		9,478		4,050		(341	)		196,224

Operating income				144,849		19,882		4,224		—			168,955
Miscellaneous income (expense)				2,333		352		6,134		(3,156	)		5,663
Interest charges				33,166		1,873		1,612		(3,156	)		33,495

Income before income taxes				114,016		18,361		8,746		—			141,123
Income tax expense				42,347		7,403		3,527		—			53,277

		Net income	$	71,669	$	10,958	$	5,219	$	—		$	87,846

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



			For the Six Months Ended March 31, 2003

						Natural Gas			Other
			Utility			Marketing			Nonutility		Eliminations			Consolidated


			(In thousands)
Operating revenues from external parties			$	1,095,817		$	772,666		$	6,091	$	—		$	1,874,574
Intersegment revenues				712			191,234			6,466		(198,412	)		—

				1,096,529			963,900			12,557		(198,412	)		1,874,574
Purchased gas cost				773,223			958,260			1,008		(198,051	)		1,534,440

	Gross profit			323,306			5,640			11,549		(361	)		340,134
Operating expenses				170,179			5,991			3,823		(361	)		179,632

Operating income (loss)				153,127			(351	)		7,726		—			160,502
Miscellaneous income (expense)				(2,219	)		1,273			5,405		(1,824	)		2,635
Interest charges				30,996			1,428			1,037		(1,824	)		31,637

Income (loss) before income taxes and cumulative effect of accounting change				119,912			(506	)		12,094		—			131,500
Income tax expense (benefit)				44,801			(200	)		4,801		—			49,402

Income (loss) before cumulative effect of accounting change				75,111			(306	)		7,293		—			82,098
Cumulative effect of accounting change, net of income tax benefit				—			(7,773	)		—		—			(7,773	)

		Net income (loss)	$	75,111		$	(8,079	)	$	7,293	$	—		$	74,325

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at March 31, 2004 and September 30, 2003, by segment, is presented in the following tables:



			At March 31, 2004

					Natural Gas			Other
			Utility		Marketing			Nonutility		Eliminations			Consolidated


			(In thousands)
ASSETS
Property, plant and equipment, net			$	1,593,439	$	8,079		$	59,818	$	—		$	1,661,336
Investment in subsidiaries				149,763		(2,240	)		—		(147,523	)		—
Current assets
	Cash and cash equivalents			76,959		31,889			6,135		—			114,983
	Assets from risk management activities			996		18,273			—		(4,985	)		14,284
	Other current assets			304,021		211,010			61,115		(64,924	)		511,222
	Intercompany receivables			43,306		—			—		(43,306	)		—

		Total current assets		425,282		261,172			67,250		(113,215	)		640,489
Intangible assets				—		4,595			—		—			4,595
Goodwill				236,550		22,600			12,128		—			271,278
Noncurrent assets from risk management activities				—		194			—		(175	)		19
Deferred charges and other assets				216,540		2,118			24,817		—			243,475

			$	2,621,574	$	296,518		$	164,013	$	(260,913	)	$	2,821,192


CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	932,849	$	85,716		$	64,047	$	(149,763	)	$	932,849
Long-term debt				855,803		—			8,821		—			864,624

		Total capitalization		1,788,652		85,716			72,868		(149,763	)		1,797,473
Current liabilities
	Current maturities of long-term debt			6,077		—			2,016		—			8,093
	Short-term debt			—		—			—		—			—
	Liabilities from risk management activities			702		16,891			—		(5,585	)		12,008
	Other current liabilities			362,610		191,589			33,809		(62,198	)		525,810
	Intercompany payables			—		7,646			35,660		(43,306	)		—

		Total current liabilities		369,389		216,126			71,485		(111,089	)		545,911
Deferred income taxes				232,918		(9,498	)		11,080		(145	)		234,355
Noncurrent liabilities from risk management activities				—		730			—		84			814
Regulatory cost of removal obligation				104,152		—			—		—			104,152
Deferred credits and other liabilities				126,463		3,444			8,580		—			138,487

			$	2,621,574	$	296,518		$	164,013	$	(260,913	)	$	2,821,192

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



			At September 30, 2003

					Natural Gas			Other
			Utility		Marketing			Nonutility		Eliminations			Consolidated


			(In thousands)
ASSETS
Property, plant and equipment, net			$	1,555,381	$	9,288		$	59,725	$	—		$	1,624,394
Investment in subsidiaries				133,586		(2,662	)		—		(130,924	)		—
Current assets
	Cash and cash equivalents			—		14,880			803		—			15,683
	Assets from risk management activities			202		22,941			—		(884	)		22,259
	Other current assets			230,609		197,239			85,119		(92,912	)		420,055
	Intercompany receivables			114,550		—			—		(114,550	)		—

		Total current assets		345,361		235,060			85,922		(208,346	)		457,997
Intangible assets				—		5,030			—		—			5,030
Goodwill				233,741		22,600			12,128		—			268,469
Noncurrent assets from risk management activities				—		1,896			—		(197	)		1,699
Investment in US Propane LLC				—		—			21,071		—			21,071
Deferred charges and other assets				220,258		2,214			25,781		—			248,253

			$	2,488,327	$	273,426		$	204,627	$	(339,467	)	$	2,626,913


CAPITALIZATION AND LIABILITIES
Shareholders’ equity			$	857,517	$	74,759		$	58,827	$	(133,586	)	$	857,517
Long-term debt				858,720		—			5,198		—			863,918

		Total capitalization		1,716,237		74,759			64,025		(133,586	)		1,721,435
Current liabilities
	Current maturities of long-term debt			8,227		—			1,118		—			9,345
	Short-term debt			118,595		—			—		—			118,595
	Liabilities from risk management activities			7,941		13,400			—		(551	)		20,790
	Other current liabilities			190,399		183,082			10,008		(90,470	)		293,019
	Intercompany payables			—		5,549			109,001		(114,550	)		—

		Total current liabilities		325,162		202,031			120,127		(205,571	)		441,749
Deferred income taxes				221,912		(9,498	)		11,081		(145	)		223,350
Noncurrent liabilities from risk management activities				—		928			—		(165	)		763
Regulatory cost of removal obligation				102,371		—			—		—			102,371
Deferred credits and other liabilities				122,645		5,206			9,394		—			137,245

			$	2,488,327	$	273,426		$	204,627	$	(339,467	)	$	2,626,913

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

The Board of Directors

Atmos Energy Corporation

We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, 2004, and the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2004 and 2003, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2004 and 2003. These financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data, and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2003, 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 10, 2003, 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, 2003 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 10, 2004


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, 2003.


	*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, expect, estimate, plans, believes, objective, forecast, goal 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; limited access to financial markets; inflation and increased gas costs, including their effect on commodity prices for natural gas; increased competition; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. A discussion of these risks and uncertainties may be found in the Company’s Annual Report on Form 10-K for the year ended September 30, 2003. 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

Through our nonutility businesses, we provide natural gas supply management and marketing services to industrial customers, municipalities and other local distribution companies located in 18 states. We also construct electric power-generating plants and associated facilities to meet peak load demands and lease or sell them to municipalities and industrial customers. Beginning April 1, 2004, Atmos Energy Services, LLC, a wholly owned subsidiary of Atmos Energy Holdings, Inc., began providing natural gas supply management services to our utility operations in a limited number of states. We expect to expand these services to substantially all of our utility service areas before the end of fiscal 2004.

Our operations are divided into three segments:

Critical Accounting Policies and 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 policies 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, 2003 and include 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 in these critical accounting policies during the six months ended March 31, 2004.

Results of Operations

The following table presents our financial highlights for the three and six months ended March 31, 2004 and 2003:



		Three Months Ended						Six Months Ended
		March 31						March 31

		2004			2003			2004			2003


		(In thousands, unless otherwise noted)
Operating revenues		$	1,117,485		$	1,194,142		$	1,881,101		$	1,874,574
Gross profit			206,126			202,968			365,179			340,134
Operating expenses			100,712			95,090			196,224			179,632
Operating income			105,414			107,878			168,955			160,502
Miscellaneous income (expense)			4,456			(1,489	)		5,663			2,635
Interest charges			16,160			16,158			33,495			31,637
Income before income taxes and cumulative effect of accounting change			93,710			90,231			141,123			131,500
Income tax expense			35,405			33,926			53,277			49,402
Cumulative effect of accounting change, net of income tax benefit			—			(7,773	)		—			(7,773	)
Net income		$	58,305		$	48,532		$	87,846		$	74,325

Utility sales volumes — MMcf			77,184			82,013			127,865			135,750
Utility transportation volumes — MMcf			20,647			18,145			38,145			35,337

	Total utility throughput — MMcf		97,831			100,158			166,010			171,087

Natural gas marketing sales volumes — MMcf			67,172			73,371			126,089			132,697

Heating degree days
	Actual (weighted average)		1,772			1,812			3,012			3,219
	Percent of normal		97	%		100	%		96	%		102	%

Consolidated utility average transportation revenue per Mcf		$	0.42		$	0.44		$	0.43		$	0.49
Consolidated utility average cost of gas per Mcf sold		$	6.72		$	6.13		$	6.58		$	5.70

The following table shows our operating income (loss) by segment for the three-month and six-month periods ended March 31, 2004 and 2003. 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


		2004					2003

		Operating		Heating Degree Days			Operating			Heating Degree Days
		Income		Percent of Normal			Income			Percent of Normal


		(In thousands, except degree day information)
Colorado-Kansas		$	11,119		100	%	$	15,851			100	%
Kentucky			11,242		100	%		11,596			100	%
Louisiana			21,445		93	%		22,482			109	%
Mid-States			23,513		98	%		23,611			103	%
Mississippi Valley Gas Company			17,131		100	%		20,690			100	%
Texas			9,501		94	%		10,538			94	%
Other			1,520		—			(788	)		—

Utility segment			95,471		97	%		103,980			100	%
Natural gas marketing segment			6,672		—			(1,727	)		—
Other nonutility segment			3,271		—			5,625			—

	Consolidated operating income	$	105,414		97	%	$	107,878			100	%



		For the Six Months Ended March 31


		2004					2003

		Operating		Heating Degree Days			Operating			Heating Degree Days
		Income		Percent of Normal			Income			Percent of Normal


		(In thousands, except degree day information)
Colorado-Kansas		$	19,357		100	%	$	25,237			102	%
Kentucky			17,806		99	%		17,916			101	%
Louisiana			29,701		92	%		30,742			107	%
Mid-States			37,384		96	%		39,064			102	%
Mississippi Valley Gas Company⁽¹⁾			25,364		100	%		26,245			100	%
Texas			14,167		91	%		15,648			100	%
Other			1,070		—			(1,725	)		—

Utility segment			144,849		96	%		153,127			102	%
Natural gas marketing segment			19,882		—			(351	)		—
Other nonutility segment			4,224		—			7,726			—

	Consolidated operating income	$	168,955		96	%	$	160,502			102	%

⁽¹⁾ Operating income for Mississippi Valley Gas Company reflects operating income since our acquisition of MVG on December 3, 2002.


	*Three Months Ended March 31, 2004 Compared with Three Months Ended March 31, 2003*


	Utility segment

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 68 percent of our net income having been earned in the second quarter during the three most recently completed fiscal years. 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 effect on our utility operations of weather that is above or below normal are partially offset by weather normalization adjustments (WNA) in certain 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, 2004, we had WNA in the following service areas for the following periods, which cover approximately 854,000, or 51 percent, of our meters in service:


Tennessee		November – April
Georgia		October – May
Mississippi		November – May
Kentucky		November – April
Kansas		October – May
Amarillo, Texas		October – May
West Texas⁽¹⁾		October – May
Lubbock, Texas⁽²⁾		October – May

⁽¹⁾ Effective beginning in the 2004-2005 winter heating season.

⁽²⁾ Effective beginning in April 2004.


	Operating Income

Utility gross profit margin decreased to $189.5 million for the three months ended March 31, 2004 from $193.8 million for the three months ended March 31, 2003. Total throughput for our utility business was 103.3 billion cubic feet (Bcf) during the current-year quarter, compared to 106.6 Bcf in the prior-year quarter. Excluding intercompany throughput, total consolidated throughput for our utility business was 97.8 Bcf, compared with 100.2 Bcf.

The decrease in utility gross profit margin primarily reflects lower throughput primarily attributable to weather that was 2 percent warmer than the prior-year quarter and 3 percent warmer than normal during the second quarter, resulting in a decrease of $3.8 million. Warmer-than-normal weather particularly impacted our service areas in our Mid-States and Louisiana divisions. The decrease in throughput also reflects a decrease in consumption attributable to the impact of consumer conservation and the continued introduction of more efficient gas appliances in our service areas. Finally, our gross profit margin for the three months ended March 31, 2004 reflects a reduction resulting from a regulatory ruling to refund $1.9 million to our

customers in our Colorado service area. These decreases were offset partially by a $4.7 million increase in the effect of WNA in our WNA service areas, compared with the prior-year quarter.

The average cost of gas per Mcf sold increased 9.6 percent to $6.72 for the three months ended March 31, 2004 from $6.13 for the prior-year quarter. However, changes in the cost of gas do not directly affect utility gross profit margin because the fluctuations in gas prices are passed through to customers.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased 4.6 percent to $94.0 million for the three months ended March 31, 2004 from $89.9 million for the three months ended March 31, 2003. The increase in operating expense was attributable primarily to higher employee and insurance costs.

As a result of the factors described above, utility operating income decreased to $95.5 million for the three months ended March 31, 2004 from $104.0 million for the three months ended March 31, 2003.


	Miscellaneous Income (Expense)

Miscellaneous income for the three months ended March 31, 2004 was $1.3 million, compared with expense of $1.4 million for the three months ended March 31, 2003. The $2.7 million change was attributable primarily to the absence in 2004 of weather insurance amortization totaling $2.5 million, which was recognized in the three months ended March 31, 2003, due to the termination of our weather insurance policy in the third quarter of fiscal 2003.


	*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 fees for services we deliver.


	Operating Income (Loss)

Gross profit margin for our natural gas marketing segment consists primarily of gross profit margin for our storage and marketing activities. Our gross profit margin from marketing activities results from the difference between revenue arising from the sale of physical natural gas to our natural gas marketing customers less the cost to purchase natural gas. The gross profit margin for our storage activities results from the optimization of our managed proprietary and third party storage and transportation assets. These activities include unrealized gains and losses from changes in the market value of derivatives and realized gains and losses from the settlement of derivative contracts.

Our total natural gas marketing segment’s gross profit margin was $11.9 million for the three months ended March 31, 2004 compared to gross profit margin of $1.7 million for the three months ended March 31, 2003. Natural gas marketing sales volumes were 81.2 Bcf during the current-year quarter compared with

92.7 Bcf for the prior-year quarter. Excluding intercompany sales volumes, natural gas marketing sales volumes were 67.2 Bcf during the current-year quarter, compared to 73.4 Bcf in the prior-year quarter. The decrease in natural gas marketing sales volumes was primarily due to overall warmer temperatures during the 2003-2004 heating season compared with the prior year quarter. Our natural gas marketing gross profit margin for the three months ended March 31, 2004 included an unrealized loss on open contracts of $7.2 million compared with an unrealized gain on open contracts of $12.4 million in the prior-year period.

Our storage activities within the natural gas marketing segment contributed a loss of $4.9 million to gross profit margin for the three months ended March 31, 2004 compared to a $2.3 million gain for the three months ended March 31, 2003. The $7.2 million decrease in the contribution from our storage activities was primarily attributable to a $19.7 million greater unrealized loss in the current quarter associated with our storage portfolio partially offset by a $12.6 million increase in the realized storage contributions in the current three month period compared to the prior year quarter. The greater unrealized losses in the current quarter was primarily attributable to unfavorable movement during the quarter in the inside FERC pricing used to value the physical natural gas inventory combined with overall higher physical natural gas storage quantities at March 31, 2004 compared to the prior year quarter-end and favorable movement in the forward indices used to value the storage financial instruments in the prior period. The increase in the realized storage contribution for the three months ended March 31, 2004 primarily was due to our inability during the 2002-2003 heating season to withdraw planned volumes from storage to meet our customer requirements caused by operational, contractual and regulatory limitations relating to our storage facilities, which reduced our realized storage contributions during the three months ended March 31, 2003. This situation did not recur during the three months ended March 31, 2004.

Our marketing activities contributed $16.8 million to gross profit margin for the three months ended March 31, 2004 compared to a loss of $0.6 million for the three months ended March 31, 2003. The increase in the gross profit margin for our marketing activities primarily was attributable to our continued efforts to amend contracts with third parties to transfer risk to our customers and to provide higher gross profit margins and improved position management.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $5.2 million for the three months ended March 31, 2004 from $3.4 million for the three months ended March 31, 2003. The increase in operating expenses was attributable primarily to higher employee incentive compensation costs resulting from the improvement in earnings for the fiscal year.

As a result of the improved gross profit margin, our natural gas marketing segment generated operating income of $6.7 million for the three months ended March 31, 2004 compared with an operating loss of $1.7 million for the three months ended March 31, 2003.


	*Other Nonutility Segment*

Our other nonutility segment provides a variety of services. Through Atmos Pipeline and Storage, LLC we provide storage services to our customers for a fee, as well as capture pricing arbitrage through the use of derivatives. Through Atmos Power Systems, Inc., we construct electric peaking power-generating plants and associated facilities in exchange for a fee. Additionally, we may enter into agreements to either lease or sell these plants. Through Atmos Energy Services, LLC, we earn a fee for providing gas supply management services.


	Operating Income

Our other nonutility operating income decreased to $3.3 million for the three months ended March 31, 2004 from $5.6 million for the three months ended March 31, 2003. Our other nonutility gross profit margin decreased to $5.0 million for the three months ended March 31, 2004 from $7.5 million for the three months ended March 31, 2003. The decrease in our nonutility gross profit margin was attributable primarily to lower transported volumes of approximately 1.1 Bcf by Atmos Pipeline and Storage due to overall warmer weather.


	Miscellaneous Income

Miscellaneous income for the three months ended March 31, 2004 was $4.9 million, compared with $0.5 million for the three months ended March 31, 2003. The $4.4 million increase was attributable primarily to 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 January 2004. This increase was partially offset by lower equity earnings from our investment in USP resulting from the sale.


	*Six Months Ended March 31, 2004 Compared with Six Months Ended March 31, 2003*


	Utility Segment


	*Operating Income*

Utility gross profit margin increased to $327.9 million for the six months ended March 31, 2004 from $323.3 million for the six months ended March 31, 2003. Total throughput for our utility business was 174.7 Bcf during the current-year period compared to 181.0 Bcf in the prior-year period. Excluding intercompany throughput, total consolidated throughput for our utility business was 166.0 Bcf during the current-year period, compared with 171.1 Bcf in the prior-year period.

The increase in utility gross profit margin primarily reflects the impact of the acquisition of Mississippi Valley Gas Company (MVG) for the entire first quarter in the current fiscal year, compared with one month in the first quarter of the prior fiscal year resulting in an increase in utility gross profit margin and total throughput of $12.8 million and 5.0 Bcf. Utility gross profit margin also increased due to a $6.8 million period-over-period increase in the effect of WNA in our WNA service areas. These increases were offset partially by the impact of weather that was 6 percent warmer than that of the prior year and 4 percent warmer than normal, resulting in a decrease of approximately $12.2 million. Warmer than normal weather particularly impacted our service areas in our Mid-States, Louisiana and Texas divisions. The decrease in throughput also reflects a decrease in consumption attributable to the impact of conservation and the continued introduction of more efficient gas appliances in our service areas. Finally, our utility gross profit margin for the six months ended March 31, 2004 reflects the $1.9 million refund to our customers in our Colorado service area described above.

The average cost of gas per Mcf sold increased 15.4 percent to $6.58 for the six months ended March 31, 2004 from $5.70 for the prior-year period. However, changes in the cost of gas do not directly affect utility gross profit margin because the fluctuations in gas prices are passed through to customers.

Operating expenses increased 7.5 percent to $183.0 million for the six months ended March 31, 2004 from $170.2 million for the six months ended March 31, 2003. Operation and maintenance expense increased, primarily due to the addition of $6.1 million related to the MVG acquisition in December 2002 and higher employee costs. Taxes other than income taxes increased $1.7 million, primarily due to additional franchise, payroll and property taxes associated with the MVG assets acquired in December 2002. Franchise and state gross receipts taxes are paid by our customers as a component of their monthly bills; thus, these amounts are offset in revenues through customer billings and have no effect on net income. Depreciation and amortization expense increased $3.9 million, which primarily reflects depreciation for the full six months of 2004 compared with four months in the prior-year period.

As a result of the aforementioned factors, our utility segment operating income for the six months ended March 31, 2004 decreased to $144.8 million from $153.1 million for the six months ended March 31, 2003.


	*Miscellaneous Income (Expense)*

Miscellaneous income for the six months ended March 31, 2004 was $2.3 million, compared with expense of $2.2 million for the six months ended March 31, 2003. The $4.5 million change was attributable primarily to the absence in 2004 of weather insurance amortization totaling $4.4 million, which was recognized in the six months ended March 31, 2003, due to the termination of our weather insurance policy in the third quarter of fiscal 2003.


	*Interest Charges*

Interest charges increased 7.1 percent for the six months ended March 31, 2004 to $33.2 million from $31.0 million for the six months ended March 31, 2003. The increase was attributable primarily to a higher average outstanding debt balance resulting from the financing obtained to fund the acquisition of MVG in December 2002.


	Natural Gas Marketing Segment


	*Operating Income (Loss)*

Our total natural gas marketing segment’s gross profit margin was $29.4 million for the six months ended March 31, 2004 compared to gross profit margin of $5.6 million for the six months ended March 31, 2003. Natural gas marketing sales volumes were 151.4 Bcf during the current-year period compared with 166.1 Bcf for the prior year. Excluding intercompany sales volumes, natural gas marketing sales volumes were 126.1 Bcf during the current-year period compared with 132.7 Bcf in the prior-year period. The decrease in natural gas marketing sales volumes was primarily due to overall warmer temperatures during the 2003-2004 heating season compared with the prior year quarter. Our natural gas marketing gross profit margin for the six months ended March 31, 2004 included an unrealized loss on open contracts of $2.1 million compared with an unrealized gain on open contracts of $11.3 million in the prior-year period.

The contribution to gross profit from our storage activities was $0.4 million for the six months ended March 31, 2004 compared to $0.2 million for the six months ended March 31, 2003. The $0.2 million increase primarily was attributable to a $16.0 million increase in the realized storage contribution for the six months ended March 31, 2004 compared to the prior year period offset by a $15.8 million unrealized loss associated with our storage portfolio compared to the prior year period. The increase in the realized storage contribution for the six months ended March 31, 2004 primarily was due to our inability during the 2002-2003 heating season to withdraw planned volumes from storage to meet our customer requirements caused by operational, contractual and regulatory limitations relating to our storage facilities, which reduced our realized storage contributions during the six months ended March 31, 2003. This situation did not recur during the six months ended March 31, 2004. The greater unrealized loss in the current quarter was primarily attributable to unfavorable movement during the six months ended March 31, 2004 in the inside FERC pricing used to value the physical natural gas inventory combined with overall higher physical natural gas storage quantities at March 31, 2004 compared to the prior year period and favorable movement in the forward indices used to value the storage financial instruments in the prior period.

Our marketing activities contributed $29.0 million to our gross profit margin for the six months ended March 31, 2004 compared to $5.4 million for the six months ended March 31, 2003. The increase in the marketing contribution primarily was attributable to our continued efforts to amend contracts with third parties to transfer risk to our customers and to provide higher gross profit margins and improved position management during the current year.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes other than income taxes, increased to $9.5 million for the six months ended March 31, 2004 from $6.0 million for the six months ended March 31, 2003. The increase in operating expense was attributable primarily to higher employee incentive compensation costs resulting from the improvement in earnings for the fiscal year.

The improved gross profit margin resulted in an increase in our natural gas marketing segment operating income to $19.9 million for the six months ended March 31, 2004 compared with an operating loss of $0.4 million for the six months ended March 31, 2003.


	*Cumulative Effect of Change in Accounting Principle*

us to record estimated future gains on our storage and transportation contracts at the time we entered into the contracts and to mark those contracts to market value each month. Effective January 1, 2003, we have no longer marked those contracts to market. As a result, our natural gas marketing segment recognized an extraordinary charge of $7.8 million, net of applicable income tax benefit, as a cumulative effect of a change in accounting principle.


	Other Nonutility Segment


	*Operating Income*

Our other nonutility operating income decreased to $4.2 million for the six months ended March 31, 2004 from $7.7 million for the six months ended March 31, 2003. Our other nonutility gross profit margin decreased to $8.3 million for the six months ended March 31, 2004 from $11.5 million for the six months ended March 31, 2003. The decrease in our nonutility gross profit margin was attributable primarily to lower transported volumes of approximately 2.3 Bcf by Atmos Pipeline and Storage due to overall warmer weather.


	*Miscellaneous Income*

Miscellaneous income for the six months ended March 31, 2004 was $6.1 million, compared with income of $5.4 million for the six months ended March 31, 2003. The $0.7 million increase was attributable primarily to 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. This increase was offset partially by lower equity earnings from our investment in USP resulting from the sale and the absence in 2004 of a $3.9 million gain recorded in 2003 associated with a sales-type lease of a distributed electric generation plant.

Liquidity and Capital Resources

Our working capital and liquidity for capital 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 fiscal 2004.


	*Capitalization*

The following presents our capitalization as of March 31, 2004 and September 30, 2003:



	March 31, 2004				September 30, 2003



	(In thousands, except percentages)
Short-term debt	$	—	—		$	118,595	6.4	%
Long-term debt		872,717	48.3	%		873,263	47.2	%
Shareholders’ equity		932,849	51.7	%		857,517	46.4	%

Total capitalization, including short-term debt	$	1,805,566	100.0	%	$	1,849,375	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 48.3 percent at March 31, 2004 compared with 53.6 percent at September 30, 2003. Our long-term plan is to maintain the debt-to-capitalization ratio within a target range of 50 to 52 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 debt and equity capital markets and limits to annual maintenance and capital expenditures.


	*Cash Flows*

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


	Cash Flows from Operating Activities

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

For the six months ended March 31, 2004, we generated operating cash flow of $290.6 million compared with $183.8 million for the six months ended March 31, 2003. Our cash flow from operating activities was affected by the following:

• Improved customer collections during the six months ended March 31, 2004, compared with the prior-year period, resulted in a $169.9 million increase in operating cash flows.

• The timing of payments for accounts payable and other accrued liabilities adversely affected operating cash flow by $94.9 million.

• 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 adversely impacted our cash flows from operations by $14.1 million.

• Other working capital changes improved operating cash flow by $45.9 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 and technology improvements. Capital expenditures for fiscal 2004 are expected to approximate $175.0 million. These expenditures will include additional mains, services, meters and equipment.

For the six months ended March 31, 2004, we invested $58.1 million compared with $147.0 million for the six months ended March 31, 2003. Cash flows used for investing activities for the current year include the receipt of proceeds totaling $24.7 million from the sale of our interest in USP in January 2004. Cash flows used for investing activities for the current year included $2.0 million for the ComFurT Gas Inc. acquisition and $74.7 million in the prior-year period for the cash portion of the Mississippi Valley Gas Company purchase in December 2002. Capital expenditures were $83.7 million during the six months ended March 31, 2004 compared with $72.9 million for the prior-year period. Capital projects for each six- month period included expenditures for additional mains, services, meters and equipment to grow our customer base. Additionally, capital expenditures for the current-year period include approximately $7.2 million for Mississippi Valley Gas Company Division capital expenditures, compared with $4.6 million in the prior-year period.


	Cash Flows from Financing Activities

For the six months ended March 31, 2004 our financing activities used $133.2 million of cash compared with $20.5 million for the six months ended March 31, 2003. Our significant financing activities for the six months ended March 31, 2004 and 2003 are summarized as follows:

• During the six months ended March 31, 2003, we received $147.0 million from a short-term acquisition credit facility which was used primarily to fund the $74.7 million cash portion of the purchase price for MVG in December 2002 and to repay $70.9 million of MVG’s outstanding debt. This facility was subsequently repaid with a portion of the net proceeds received from our $250.0 million debt offering completed in January 2003.

• Total short-term debt decreased by $118.6 million and $116.1 million for the six months ended March 31, 2004 and 2003 reflecting the repayment during the second quarter of our lines of credit used to fund our natural gas purchases for the winter heating season.

• We repaid $5.5 million of long-term debt during the six months ended March 31, 2004 compared with a repayment of $69.1 million for the six months ended March 31, 2003, reflecting the payment of scheduled maturities on our long-term debt instruments and the $54.0 million repayment of unsecured

senior notes in the second quarter of 2003 with the proceeds received from our January 2003 debt offering.

• We received $5.0 million in long-term debt for our other nonutility segment to refinance intercompany debt with third-party debt.

• We paid $31.6 million in cash dividends during the six months ended March 31, 2004 compared with dividend payments of $26.2 million for the prior-year period. The increase in dividends paid reflects the 1.7 percent increase in the quarterly dividend rate approved by the Board of Directors and the increase in the number of shares outstanding as a result of the shares issued in connection with our public offering in June and July 2003 (the 2003 Offering), the funding of our pension plan in June 2003 and the acquisition of MVG in December 2002.

During the six months ended March 31, 2004, we issued 760,195 shares of common stock, generating proceeds of $17.6 million. The following table summarizes the issuances for the six months ended March 31, 2004 and 2003:



			Six Months Ended
			March 31

			2004		2003

Shares issued:
	Retirement Savings Plan			164,059		192,137
	Direct Stock Purchase Plan			296,833		275,462
	Outside Directors Stock-for-Fee Plan			1,627		1,254
	Long-Term Incentive Plan			297,676		88,633
	Long-Term Stock Plan for Mid-States Division			—		5,000
	Acquisition of Mississippi Valley Gas Company			—		3,386,287

		Total shares issued		760,195		3,948,773


	*Shelf Registration*

In December 2001, we filed a shelf registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $600.0 million in new common stock and/or debt. The registration statement was declared effective by the SEC on January 30, 2002. On January 16, 2003, we issued $250.0 million of 5 1/8 percent Senior Notes due in 2013 under the registration statement. The net proceeds of $249.3 million were used to repay debt under an acquisition credit facility used to finance our acquisition of MVG, to repay $54.0 million in unsecured senior notes held by institutional lenders and short-term debt under our commercial paper program and to provide funds for general corporate purposes. Additionally, we sold 4,100,000 shares of our common stock in connection with our 2003 Offering under the registration statement to provide additional funding for our Pension Account Plan. At March 31, 2004, approximately $246.0 million remains available, subject to certain regulatory approval, 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. 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 as follows:

S&P

Moody’s

Fitch

Long-term debt

A-

Commercial paper

A-2

P-2

F-2

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.

In January 2003, S&P changed the outlook on our long-term debt rating from “stable” to “negative.” In its press release explaining this action, S&P cited, among other factors, its concern that we have not made significant progress in reducing our debt-to-total-capitalization ratio. Since S&P changed its outlook, we have issued equity and reduced our leverage from 61 percent at December 31, 2002 to 48 percent at March 31, 2004. Moody’s and Fitch each continue to maintain a “stable” outlook for our ratings.


	*Debt Covenants*

In addition to the limit on our total debt-to-capitalization ratio imposed by our committed credit facilities described above, 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 accumulated net income for periods after December 31, 1988, plus $15.0 million. At March 31, 2004, approximately $140.3 million of retained earnings was unrestricted with respect to the payment of dividends.

We are in compliance with all of our debt covenants as of March 31, 2004. 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 $350.0 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 $15 million to $25 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 any other financial obligation, as defined, by at least $250 thousand. 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 Baa1.

We have no trigger 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 trigger events.


	*Contractual Obligations and Commercial Commitments*

Other than changes to our risk management assets and liabilities discussed below, there have been no significant changes in our contractual obligations and commercial commitments during the three- and six-month periods ended March 31, 2004.


	*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. Our risk management activities and related accounting treatment are described in further detail in Note 5 to the condensed consolidated financial statements.

We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying derivative. Substantially all of our derivative financial instruments are valued using external market quotes and indices. The following table shows the components of the change in the fair value of our utility and natural gas marketing derivative contracts for the three and six months ended March 31, 2004 and 2003:



		Three Months Ended						Three Months Ended
		March 31, 2004						March 31, 2003

					Natural Gas						Natural Gas
		Utility			Marketing			Utility			Marketing


		(In thousands)
Fair value of contracts at beginning of period		$	5,699		$	1,270		$	6,695		$	2,980
	Contracts realized/settled		(842	)		(529	)		(7,622	)		8,763
	Fair value of new contracts		20			26			(117	)		1,773
	Other changes in value		(4,583	)		420			2,246			3,545
	Cumulative effect of accounting change		—			—			—			(8,799	)

Fair value of contracts at end of period		$	294		$	1,187		$	1,202		$	8,262



		Six Months Ended						Six Months Ended
		March 31, 2004						March 31, 2003

					Natural Gas						Natural Gas
		Utility			Marketing			Utility			Marketing


		(In thousands)
Fair value of contracts at beginning of period		$	(7,739	)	$	10,144		$	4,424		$	6,651
	Contracts realized/settled		(4,145	)		(5,194	)		(2,451	)		11,577
	Fair value of new contracts		322			(797	)		(117	)		4,631
	Other changes in value		11,856			(2,966	)		(654	)		(5,798	)
	Cumulative effect of accounting change		—			—			—			(8,799	)

Fair value of contracts at end of period		$	294		$	1,187		$	1,202		$	8,262

The fair value of our utility and natural gas marketing derivative contracts at March 31, 2004, is segregated below by time period and fair value source.



	Fair Value of Contracts at March 31, 2004


	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	$	11,452		$	(9	)	$	—	$	—	$	11,443
Prices provided by other external sources		(9,125	)		(208	)		—		—		(9,333	)
Prices based on models and other valuation methods		(51	)		(578	)		—		—		(629	)

Total Fair Value	$	2,276		$	(795	)	$		$	—	$	1,481

As of March 31, 2004, a significant portion of AEM’s stored gas inventory was scheduled to be sold within six months. Since AEM actively manages and optimizes its portfolio, it may change its scheduled injection and withdrawal plans based on market conditions. Therefore, we cannot predict that our actual inventory withdrawals will match the planned schedule as of March 31, 2004. Generally, differences between injection and withdrawal prices are locked-in through the use of derivatives; therefore, there is generally no significant permanent earnings impact associated with changes in monthly prices in the interim between injections and withdrawals. However, there may be significant earnings volatility. Further, permanent earnings impacts may arise if we experience operational or other issues which limit our ability to optimally manage our stored gas positions. Any change in the timing of planned injections or withdrawals from one time period to another generally is conducted to enhance the future profitability of the storage position. Additionally, AEM monitors and adjusts the amount of storage capacity it holds on a discretionary basis.


	*Pension and Postretirement Benefits Obligations*

For the six months ended March 31, 2004 and 2003 our total net periodic pension and other benefits cost was $13.7 million and $14.0 million. A portion of these costs is capitalized into our utility rate base, as these costs are recoverable through our gas utility rates. Costs that are not capitalized are recorded as a component of operation and maintenance expense.

The decrease in total net periodic pension and other benefits cost during the six months ended March 31, 2004 compared with the six months ended March 31, 2003 primarily reflects the impact of adopting the provisions of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), beginning with the second quarter of 2004, which reduced our accumulated postretirement benefit obligation and our net postretirement benefit obligation costs by $4.1 million. The total income statement impact will approximate $2.3 million, as a portion of this benefit will be capitalized.

This decrease was partially offset by an increase in the service cost and interest cost attributable to an increase in the projected benefit obligation. The increase in the projected benefit obligation resulted primarily from an increase in the number of plan participants due to the MVG acquisition and a 125-basis-point decrease in the discount rate used to determine the total net periodic pension cost and other benefits cost in fiscal 2004. Additionally, the expected return on plan assets, which reduces the net periodic pension cost and other benefits cost, increased as compared with the prior year primarily due to the effects of the contributions we made to the Atmos Pension Account Plan in fiscal 2003, offset by a reduction in the expected return on pension plan assets from 9.25 percent to 9 percent used in the determination of the total net periodic pension cost and other benefits cost for fiscal 2004.

In our Annual Report on Form 10-K for the year ended September 30, 2003, we disclosed that anticipated additional voluntary contributions ranging from $0 to $15 million during fiscal 2004 may be necessary to keep the Atmos Energy Corporation Pension Account Plan (the Pension Account Plan) 100 percent funded on an accumulated benefit obligation (ABO) basis. We did not contribute to our pension plan during the six months ended March 31, 2004. As of March 31, 2004 we were still assessing whether a voluntary contribution would be necessary during fiscal 2004.

Operating Statistics and Other Information

The following tables present certain operating statistics for our utility, natural gas marketing and other nonutility segments for the three months and six months ended March 31, 2004 and 2003. Certain prior-year amounts have been reclassified to conform to the current-year presentation.


	*Utility Sales and Statistical Data*



			Three Months Ended						Six Months Ended
			March 31						March 31

			2004			2003			2004			2003⁽¹⁾

METERS IN SERVICE, end of period
	Residential			1,507,992			1,502,374			1,507,992			1,502,374
	Commercial			152,763			152,226			152,763			152,226
	Industrial			2,482			2,848			2,482			2,848
	Agricultural			8,987			10,227			8,987			10,227
	Public authority and other			10,177			9,959			10,177			9,959

		Total meters		1,682,401			1,677,634			1,682,401			1,677,634

HEATING DEGREE DAYS⁽²⁾
	Actual (weighted average)			1,772			1,812			3,012			3,219
	Percent of normal			97	%		100	%		96	%		102	%
UTILITY SALES VOLUMES — MMcf⁽³⁾
Gas sales volumes				46,874			48,876			74,381			79,901
	Residential Commercial			19,112			20,166			32,468			34,085
	Industrial			6,543			7,897			12,792			13,733
	Agricultural			310			698			805			811
	Public authority and other			4,345			4,376			7,419			7,220

		Total gas sales volumes		77,184			82,013			127,865			135,750
Utility transportation volumes				26,112			24,583			46,792			45,230

Total utility throughput				103,296			106,596			174,657			180,980

UTILITY OPERATING REVENUES (000’s)⁽³⁾
Gas sales revenues			$	437,719		$	424,586		$	701,268		$	664,321
	Residential Commercial			172,407			165,631			287,971			265,536
	Industrial			45,806			53,895			90,352			84,529
	Agricultural			2,097			4,517			5,131			5,293
	Public authority and other			35,037			33,290			56,946			51,058

		Total utility gas sales revenues		693,066			681,919			1,141,668			1,070,737
Transportation revenues				8,970			11,724			17,071			19,848
Other gas revenues				6,246			2,918			10,031			5,944

		Total utility operating revenues	$	708,282		$	696,561		$	1,168,770		$	1,096,529

Utility average transportation revenue per Mcf			$	0.34		$	0.48		$	0.36		$	0.44
Utility average cost of gas per Mcf sold			$	6.72		$	6.13		$	6.58		$	5.70

See footnotes following these tables.


	*Natural Gas Marketing and Other Nonutility Operations Sales and Statistical Data*



			Three Months Ended				Six Months Ended
			March 31				March 31

			2004		2003		2004		2003

CUSTOMERS, end of period
	Industrial			744		638		744		638
	Municipal			93		154		93		154

		Total		837		792		837		792

NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽³⁾				81,152		92,726		151,356		166,111
OPERATING REVENUES (000’s)⁽³⁾
	Natural gas marketing		$	517,218	$	620,402	$	891,047	$	963,900
	Other nonutility			10,654		9,657		14,282		12,557

		Total operating revenues	$	527,872	$	630,059	$	905,329	$	976,457

Notes to preceding tables:

⁽¹⁾ The operational and statistical information includes the operations of MVG since the December 3, 2002 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 months ended March 31, 2004 and 2003 is adjusted for service areas that have weather normalized operations.

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


	*Recent Ratemaking Activity*

The following will discuss our recent ratemaking activities during fiscal 2004. 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.

Kansas. In May 2003, we filed a rate case with the Kansas Corporation Commission for approximately $7.4 million in additional annual revenues. In January 2004, the Kansas Corporation Commission approved an agreement that allowed a $2.5 million increase in our rates effective March 1, 2004. Additionally, the agreement allows us to increase our monthly customer charges from $5 to $8 and provides that we will not file another full rate application prior to September 1, 2005. WNA became effective in Kansas in October 2003 in accordance with the Kansas Corporation Commission’s ruling in May 2003.

Colorado. In April 2004, we agreed to credit Colorado customers a total of $1.9 million pending approval of the agreement by the Colorado Public Utility Commission. The agreement was a result of an inquiry by the Colorado Office of Consumer Counsel related to our earnings in Colorado. The staff of the Colorado Public Utility Commission is also a party to the agreement. We accrued this reduction during the three months ended March 31, 2004.

Virginia. In February 2004, we filed a rate case with the Virginia Corporation Commission to request a $1.0 million increase in our base rates, WNA and recovery of the gas cost component of bad-debt expense. The Virginia Corporation Commission is currently reviewing our filing.

Texas. In September 2003, we filed a rate case in our West Texas System to request a $7.7 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. In April 2004, a steering committee representing 66 cities in West Texas recommended that the cities approve an overall increase of $3.2 million in our annual utility revenues. The cities’ steering committee also approved a WNA Rider for residential, commercial, public-authority and state-institution customers. This Rider will become effective in October 2004.

In October 2003, we filed a rate case in Lubbock to request a $3.0 million increase in annual revenues and WNA for our residential, commercial and public-authority customers. The City of Lubbock has approved a $1.5 million increase effective May 1, 2004, as well as the proposed WNA.

Beginning in October 2003, WNA became effective for our Amarillo, Texas, service area in accordance with an agreement approved by the City of Amarillo in August 2003.

Mississippi. The Mississippi Public Service Commission requires that we file for rate adjustments every six months. The rate filings are made in May and November of each year and the rate adjustments typically become effective in June and December. In October 2003, the Mississippi Public Commission issued a final order that denied our May 2003 request for a rate adjustment. However, we filed our second semiannual filing on November 5, 2003, and received a rate increase of $5.9 million effective on December 1, 2003.


	*Supplemental Historical Financial Information*

As discussed in Note 2 to the condensed consolidated financial statements, our utility depreciation rates approved by the various regulatory commissions included a component that allowed us to recover the cost to remove our assets. Historically, we recorded the associated obligation as a component of accumulated depreciation. This classification was consistent with others in the industry. Beginning in the second quarter of fiscal 2004, we are now classifying our regulatory cost of removal obligation as a regulatory liability on the

balance sheet. The following table presents our regulatory cost of removal obligation as of December 31, 2003 and as of September 30, 2003, 2002, 2001, 2000 and 1999.


	Regulatory Cost
	of Removal
	Obligation

	(In thousands)
December 31, 2003	$	110,200
September 30, 2003		108,405
September 30, 2002		79,750
September 30, 2001		74,034
September 30, 2000		63,138
September 30, 1999		58,991

The following table presents certain revised historical information for the years ended September 30, 2003, 2002, 2001, 2000 and 1999 and as of and for the three months ended December 31, 2003 had we reported our regulatory cost of removal accrual as a regulatory liability for these periods.



	Net Property,
	Plant and Equipment				Working Capital						Total Assets

	Originally				Originally						Originally
	Filed		Revised		Filed			Revised			Filed		Revised


	(In thousands)
December 31, 2003	$	1,538,224	$	1,648,424	$	39,767		$	34,363		$	2,812,946	$	2,923,146
September 30, 2003		1,515,989		1,624,394		22,282			16,248			2,518,508		2,626,913
September 30, 2002		1,300,320		1,380,070		(133,116	)		(139,150	)		1,981,385		2,061,135
September 30, 2001		1,335,398		1,409,432		(86,778	)		(90,968	)		2,036,180		2,110,214
September 30, 2000		982,346		1,045,484		(181,890	)		(185,267	)		1,348,758		1,411,896
September 30, 1999		965,782		1,024,773		(151,622	)		(153,472	)		1,230,537		1,289,528

These reclassifications did not impact our financial position, results of operations or cash flows as of and for the years ended September 30, 2003, 2002, 2001, 2000 and 1999 and as of and for the three months ended December 31, 2003. Further, these reclassifications did not impact our ability to satisfy the financial covenants contained in our various credit agreements for any of the periods presented above.

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 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 2004, a hypothetical 10 percent increase in fixed prices based upon the March 31, 2004 three month market strip would have increased our purchased gas cost by approximately $5.3 million in fiscal 2004.


	*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. Based on AEH’s net open position (including existing storage) at March 31, 2004 of 0.1 Bcf, a $0.50 change in the forward NYMEX price would have had less than a $0.1 million impact on our consolidated net income.

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 $1.3 million.

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 $89.4 million.

As of March 31, 2004 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(e) and 15d-15(e). 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 forms, rules and regulations. 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 2004 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*

See Note 9 to the condensed consolidated financial statements for a description of our legal proceedings.


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

At the Annual Meeting of Shareholders of Atmos Energy Corporation on February 11, 2004, 44,559,644 votes were cast as follows:


				Votes
		Votes For		Withheld

Class III Directors:
	Robert W. Best		43,931,407		628,237
	Thomas J. Garland		43,912,748		646,896
	Phillip E. Nichol		43,910,001		649,643
	Charles K. Vaughan		43,925,763		633,881

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 2005. The term of the Class II directors, Richard W. Cardin, Thomas C. Meredith, Carl S. Quinn and Richard Ware II will expire in 2006. The term of the Class III directors, listed above, will expire in 2007.


Item 6.	*Exhibits and Reports on Form 8-K*

(a) 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.

(b) Reports on Form 8-K

The Company filed a Form 8-K Current Report, Item 5, Other Events, dated January 20, 2004, announcing that the Company had issued a news release that it and three other utility partners have completed the sale of their interests in the general partnership and limited partnerships in Heritage Propane Partners, L.P. for $130.0 million. Under Item 7, Financial Statements and Exhibits, an exhibit was attached: a News Release dated January 20, 2004.

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 14, 2004

EXHIBITS INDEX

Item 6(a)


Exhibit			Page
Number		Description	Number

	10.1	Eighth Amendment and Joinder Agreement to Credit Agreement and First Amendment to Subordination, dated as of February 18, 2004, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC (formerly known as Woodward Marketing, L.L.C.), the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas
	10.2	Ninth Amendment to Credit Agreement, dated as of March 31, 2004, in respect of the Uncommitted Amended and Restated Credit Agreement, dated as of July 1, 2002, among Atmos Energy Marketing, LLC (formerly known as Woodward Marketing, L.L.C.), the financial institutions from time to time parties thereto, Fortis Capital Corp. and BNP Paribas
	10.3	Lease Agreement by and between Atmos Power Systems, Inc., a Georgia corporation and A.E. Staley Manufacturing Company dated February 8, 2002
	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 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.


⁽¹⁾	Acquired in December 2002.

⁽²⁾	Denotes locations where we have more limited service areas.


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


	•	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 and

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


	•	Regulation

	•	Revenue Recognition

	•	Allowance for Doubtful Accounts

	•	Derivatives and Hedging Activities

	•	Impairment Assessments

	•	Pension and Other Postretirement Plans


⁽¹⁾	Operating income for Mississippi Valley Gas Company reflects operating income since our acquisition of MVG on December 3, 2002.


⁽¹⁾	Effective beginning in the 2004-2005 winter heating season.

⁽²⁾	Effective beginning in April 2004.


	•	Improved customer collections during the six months ended March 31, 2004, compared with the prior-year period, resulted in a $169.9 million increase in operating cash flows.

	•	The timing of payments for accounts payable and other accrued liabilities adversely affected operating cash flow by $94.9 million.

	•	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 adversely impacted our cash flows from operations by $14.1 million.

	•	Other working capital changes improved operating cash flow by $45.9 million.


	•	During the six months ended March 31, 2003, we received $147.0 million from a short-term acquisition credit facility which was used primarily to fund the $74.7 million cash portion of the purchase price for MVG in December 2002 and to repay $70.9 million of MVG’s outstanding debt. This facility was subsequently repaid with a portion of the net proceeds received from our $250.0 million debt offering completed in January 2003.

	•	Total short-term debt decreased by $118.6 million and $116.1 million for the six months ended March 31, 2004 and 2003 reflecting the repayment during the second quarter of our lines of credit used to fund our natural gas purchases for the winter heating season.

	•	We repaid $5.5 million of long-term debt during the six months ended March 31, 2004 compared with a repayment of $69.1 million for the six months ended March 31, 2003, reflecting the payment of scheduled maturities on our long-term debt instruments and the $54.0 million repayment of unsecured


		senior notes in the second quarter of 2003 with the proceeds received from our January 2003 debt offering.

	•	We received $5.0 million in long-term debt for our other nonutility segment to refinance intercompany debt with third-party debt.

	•	We paid $31.6 million in cash dividends during the six months ended March 31, 2004 compared with dividend payments of $26.2 million for the prior-year period. The increase in dividends paid reflects the 1.7 percent increase in the quarterly dividend rate approved by the Board of Directors and the increase in the number of shares outstanding as a result of the shares issued in connection with our public offering in June and July 2003 (the 2003 Offering), the funding of our pension plan in June 2003 and the acquisition of MVG in December 2002.


⁽¹⁾	The operational and statistical information includes the operations of MVG since the December 3, 2002 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 months ended March 31, 2004 and 2003 is adjusted for service areas that have weather normalized operations.

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



	John P. Reddy
	Senior Vice President and Chief Financial Officer
	(Duly authorized signatory)