Atmos Energy 10Q 2008 Q3 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 June 30, 2008
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		75240 (Zip code)
(Address of principal executive offices)

(972) 934-9227

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” inRule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer o Smaller Reporting Company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act) Yes o No þ

Number of shares outstanding of each of the issuer’s classes of common stock, as of July 31, 2008.


Class		Shares Outstanding

No Par Value		90,627,522

TABLE OF CONTENTS


GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ATMOS ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
ATMOS ENERGY CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	1. Nature of Business
	2. Unaudited Interim Financial Information
	3. Derivative Instruments and Hedging Activities
	4. Debt
	5. Shareholders’ Equity
	6. Earnings Per Share
	7. Interim Pension and Other Postretirement Benefit Plan Information
	8. Commitments and Contingencies
	9. Concentration of Credit Risk
	10. Segment Information
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
PART II. OTHER INFORMATION
SIGNATURES
EXHIBITS INDEX Item 6(a)
Computation of Ratio of Earnings to Fixed Charges
Letter Regarding Unaudited Interim Financial Information
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation
AEH		Atmos Energy Holdings, Inc.
AEM		Atmos Energy Marketing, LLC
AES		Atmos Energy Services, LLC
APS		Atmos Pipeline and Storage, LLC
Bcf		Billion cubic feet
EITF		Emerging Issues Task Force
FASB		Financial Accounting Standards Board
FIN		FASB Interpretation
Fitch		Fitch Ratings, Ltd.
GRIP		Gas Reliability Infrastructure Program
KCC		Kansas Corporation Commission
LPSC		Louisiana Public Service Commission
Mcf		Thousand cubic feet
MMcf		Million cubic feet
Moody’s		Moody’s Investors Services, Inc.
NYMEX		New York Mercantile Exchange, Inc.
RRC		Railroad Commission of Texas
RSC		Rate Stabilization Clause
S&P		Standard & Poor’s Corporation
SEC		United States Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
TRA		Tennessee Regulatory Authority
WNA		Weather Normalization Adjustment

PART I. FINANCIAL INFORMATION


Item 1.	*Financial Statements*

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,		September 30,
	2008		2007
	(Unaudited)
	(In thousands, except
	share data)

ASSETS
Property, plant and equipment	$	5,604,416	$	5,396,070
Less accumulated depreciation and amortization		1,591,528		1,559,234

Net property, plant and equipment		4,012,888		3,836,836
Current assets
Cash and cash equivalents		46,501		60,725
Cash held on deposit in margin account		62,152		—
Accounts receivable, net		601,164		380,133
Gas stored underground		571,532		515,128
Other current assets		115,609		112,909

Total current assets		1,396,958		1,068,895
Goodwill and intangible assets		737,221		737,692
Deferred charges and other assets		237,723		253,494

	$	6,384,790	$	5,896,917


CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2008 — 90,571,457 shares; September 30, 2007 — 89,326,537 shares	$	453	$	447
Additional paid-in capital		1,732,775		1,700,378
Retained earnings		371,486		281,127
Accumulated other comprehensive income (loss)		693		(16,198	)

Shareholders’ equity		2,105,407		1,965,754
Long-term debt		2,119,729		2,126,315

Total capitalization		4,225,136		4,092,069
Current liabilities
Accounts payable and accrued liabilities		582,353		355,255
Other current liabilities		472,088		409,993
Short-term debt		113,257		150,599
Current maturities of long-term debt		1,059		3,831

Total current liabilities		1,168,757		919,678
Deferred income taxes		450,669		370,569
Regulatory cost of removal obligation		280,108		271,059
Deferred credits and other liabilities		260,120		243,542

	$	6,384,790	$	5,896,917

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended
	June 30
	2008			2007
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	676,639		$	548,251
Regulated transmission and storage segment		46,286			36,707
Natural gas marketing segment		1,189,722			854,167
Pipeline, storage and other segment		3,880			2,073
Intersegment eliminations		(277,382	)		(223,046	)

		1,639,145			1,218,152
Purchased gas cost
Natural gas distribution segment		476,711			357,608
Regulated transmission and storage segment		—			—
Natural gas marketing segment		1,192,353			854,743
Pipeline, storage and other segment		706			228
Intersegment eliminations		(276,847	)		(222,443	)

		1,392,923			990,136

Gross profit		246,222			228,016
Operating expenses
Operation and maintenance		117,822			115,141
Depreciation and amortization		50,356			48,974
Taxes, other than income		57,335			52,881
Impairment of long-lived assets		—			3,289

Total operating expenses		225,513			220,285

Operating income		20,709			7,731
Miscellaneous income		1,600			4,266
Interest charges		33,470			34,479

Loss before income taxes		(11,161	)		(22,482	)
Income tax benefit		(4,573	)		(9,122	)

Net loss	$	(6,588	)	$	(13,360	)

Basic net loss per share	$	(0.07	)	$	(0.15	)

Diluted net loss per share	$	(0.07	)	$	(0.15	)

Cash dividends per share	$	0.325		$	0.320

Weighted average shares outstanding:
Basic		89,648			88,366

Diluted		89,648			88,366

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Nine Months Ended
	June 30
	2008			2007
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	3,126,672		$	2,973,528
Regulated transmission and storage segment		142,772			122,647
Natural gas marketing segment		3,159,092			2,360,902
Pipeline, storage and other segment		20,629			27,483
Intersegment eliminations		(668,525	)		(588,193	)

		5,780,640			4,896,367
Purchased gas cost
Natural gas distribution segment		2,296,020			2,174,071
Regulated transmission and storage segment		—			—
Natural gas marketing segment		3,099,428			2,275,291
Pipeline, storage and other segment		1,773			682
Intersegment eliminations		(666,835	)		(585,971	)

		4,730,386			3,864,073

Gross profit		1,050,254			1,032,294
Operating expenses
Operation and maintenance		359,064			342,373
Depreciation and amortization		147,659			149,035
Taxes, other than income		153,170			149,694
Impairment of long-lived assets		—			3,289

Total operating expenses		659,893			644,391

Operating income		390,361			387,903
Miscellaneous income		2,974			7,683
Interest charges		103,803			109,273

Income before income taxes		289,532			286,313
Income tax expense		110,783			111,907

Net income	$	178,749		$	174,406

Basic net income per share	$	2.00		$	2.02

Diluted net income per share	$	1.99		$	2.00

Cash dividends per share	$	0.975		$	0.960

Weighted average shares outstanding:
Basic		89,281			86,378

Diluted		89,937			87,011

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	June 30
	2008			2007
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities
Net income	$	178,749		$	174,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		147,659			149,035
Charged to other accounts		106			148
Deferred income taxes		77,864			37,266
Other		12,767			17,959
Net assets / liabilities from risk management activities		35,169			12,325
Net change in operating assets and liabilities		(34,933	)		161,531

Net cash provided by operating activities		417,381			552,670
Cash Flows From Investing Activities
Capital expenditures		(312,878	)		(263,023	)
Other, net		(4,303	)		(9,867	)

Net cash used in investing activities		(317,181	)		(272,890	)
Cash Flows From Financing Activities
Net decrease in short-term debt		(35,721	)		(382,416	)
Net proceeds from long-term debt offering		—			247,461
Settlement of Treasury lock agreement		—			4,750
Repayment of long-term debt		(9,945	)		(2,685	)
Cash dividends paid		(87,821	)		(83,118	)
Issuance of common stock		19,063			18,883
Net proceeds from equity offering		—			191,913

Net cash used in financing activities		(114,424	)		(5,212	)

Net increase (decrease) in cash and cash equivalents		(14,224	)		274,568
Cash and cash equivalents at beginning of period		60,725			75,815

Cash and cash equivalents at end of period	$	46,501		$	350,383

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2008


1.	Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions in the service areas described below:


Division		Service Area

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


⁽¹⁾		Denotes states where we have more limited service areas.

In addition, we transport natural gas for others through our distribution system. Our natural gas distribution business is subject to federal and state regulationand/or regulation by local authorities in each of the states in which our natural gas distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.

Our regulated transmission and storage business consists of the regulated operations of our Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division, transports natural gas for third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. Parking arrangements provide short-term interruptible storage of gas on our pipeline. Lending services provide short-term interruptible loans of natural gas from our pipeline to meet market demands.

Our nonregulated businesses operate primarily in the Midwest and Southeast and include our natural gas marketing operations and pipeline, storage and other operations. These businesses are operated through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH), which is wholly-owned by the Company and based in Houston, Texas.

Our natural gas marketing operations are managed by Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH. AEM provides a variety of natural gas management services to municipalities, natural gas utility systems and industrial natural gas customers, primarily in the southeastern and midwestern states and to our Colorado-Kansas, Kentucky/Mid-States and Louisiana 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our pipeline, storage and other segment primarily consists of the operations of Atmos Pipeline and Storage, LLC (APS), Atmos Energy Services, LLC (AES) and Atmos Power Systems, Inc., each of which are wholly-owned by AEH. APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, APS manages our natural gas gathering operations, which were limited in nature as of June 30, 2008. AES provides limited services to our natural gas distribution divisions, and the revenues AES receives are equal to the costs incurred to provide those services. Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.


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 are condensed as permitted by the instructions toForm 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in its Annual Report onForm 10-K for the fiscal year ended September 30, 2007. Because of seasonal and other factors, the results of operations for the three andnine-month periods ended June 30, 2008 are not indicative of our results of operations for the full 2008 fiscal year, which ends September 30, 2008.

Significant accounting policies

Our accounting policies are described in Note 2 to the financial statements in our Annual Report onForm 10-K for the year ended September 30, 2007. Except for the Company’s adoption of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109(FIN 48), discussed below, there were no significant changes to those accounting policies during the nine months ended June 30, 2008.

In June 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

We adopted the provisions of FIN 48 on October 1, 2007. As a result of adopting FIN 48, we determined that we had $6.1 million of liabilities associated with uncertain tax positions. Of this amount, $0.5 million was recognized as a result of adopting FIN 48 with an offsetting reduction to retained earnings.

Prior to October 1, 2007, the $5.6 million liability previously recorded for uncertain tax positions was reflected on the consolidated balance sheet as a component of deferred income taxes. As a result of adopting FIN 48, we recorded a $3.7 million liability as a component of other current liabilities and $2.4 million as a component of deferred credits and other liabilities, with offsetting decreases to the deferred income tax liability.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of June 30, 2008, we had recorded liabilities associated with uncertain tax positions totaling $8.0 million. The realization of all of these tax benefits would reduce our income tax expense by approximately $8.0 million.

The following table presents the changes in unrecognized tax benefits for the nine months ended June 30, 2008 (in thousands):


Total unrecognized tax benefits at October 1, 2007	$	6,156
Gross increases for current year’s tax positions		—
Gross increases for prior years’ tax positions		2,331
Gross decreases for prior years’ tax positions		(528	)
Settlements		—

Total unrecognized tax benefits at June 30, 2008	$	7,959

We recognize accrued interest related to unrecognized tax benefits as a component of interest expense. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements. We did not recognize any material penalty and interest expenses during the nine months ended June 30, 2008.

We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2001. The Internal Revenue Service is currently conducting a routine examination of our fiscal 2002, 2003 and 2004 tax returns, and we anticipate these examinations will be completed by the end of fiscal 2008. We believe all material tax items which relate to the years under audit have been properly accrued.

Additionally, during the second quarter of fiscal 2008, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

Regulatory assets and liabilities

We record certain costs as regulatory assets in accordance with Statement of Financial Accounting Standards (SFAS) 71,Accounting for the Effects of Certain Types of Regulation,when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant regulatory assets and liabilities as of June 30, 2008 and September 30, 2007 included the following:


	June 30,		September 30,
	2008		2007
	(In thousands)

Regulatory assets:
Pension and postretirement benefit costs	$	52,623	$	59,022
Merger and integration costs, net		7,689		7,996
Deferred gas costs		21,473		14,797
Environmental costs		1,014		1,303
Rate case costs		13,758		10,989
Deferred franchise fees		690		796
Other		8,474		10,719

	$	105,721	$	105,622

Regulatory liabilities:
Deferred gas costs	$	109,439	$	84,043
Regulatory cost of removal obligation		300,994		295,241
Deferred income taxes, net		165		165
Other		7,292		7,503

	$	417,890	$	386,952

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive income

The following table presents the components of comprehensive income (loss), net of related tax, for the three-month and nine-month periods ended June 30, 2008 and 2007:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008			2007
	(In thousands)

Net income (loss)	$	(6,588	)	$	(13,360	)	$	178,749		$	174,406
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $531 and $215 for the three months ended June 30, 2008 and 2007 and of $(140) and $964 for the nine months ended June 30, 2008 and 2007		866			353			(231	)		1,575
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $482 and $1,863 for the three months ended June 30, 2008 and 2007 and $1,446 and $3,373 for the nine months ended June 30, 2008 and 2007		787			3,039			2,361			5,501
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $1,850 and $(2,832) for the three months ended June 30, 2008 and 2007 and $9,047 and $12,504 for the nine months ended June 30, 2008 and 2007		3,018			(4,621	)		14,761			20,401

Comprehensive income (loss)	$	(1,917	)	$	(14,589	)	$	195,640		$	201,883

Accumulated other comprehensive income (loss), net of tax, as of June 30, 2008 and September 30, 2007 consisted of the following unrealized gains (losses):


	June 30,			September 30,
	2008			2007
	(In thousands)

Accumulated other comprehensive income (loss):
Unrealized holding gains on investments	$	2,576		$	2,807
Treasury lock agreements		(11,891	)		(14,252	)
Cash flow hedges		10,008			(4,753	)

	$	693		$	(16,198	)

Recently issued accounting pronouncements

In March 2008, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 161,Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 161 expands the disclosure requirements for derivative instruments and for hedging activities. This statement requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. The provisions of this standard will be effective for us beginning January 1, 2009. Since SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard is not expected to have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued FASB Statement No. 141 (revised 2007),Business Combinations. SFAS 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS 141(R) significantly

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

changes the accounting for business combinations in a number of areas, including the treatment of contingent consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, under SFAS 141(R), changes in an acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. The provisions of this standard will apply to any acquisitions we may complete after October 1, 2009.

In December 2007, the FASB issued FASB Statement No. 160,Noncontrolling Interests in Consolidated Financial Statement, an amendment of ARB No. 51. SFAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This new consolidation method significantly changes the accounting for transactions with minority interest holders. The provisions of the standard will be effective for us beginning October 1, 2009. This standard is not expected to have a material impact on our financial position, results of operations or cash flows.


3.	Derivative Instruments and Hedging Activities

We conduct risk management activities through both our natural gas distribution and natural gas marketing segments. We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying derivative. Our determination of the fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains and losses on open contracts. In our determination of fair value, we consider various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. These risk management assets and liabilities are subject to continuing market risk until the underlying derivative contracts are settled.

The following table shows the fair values of our risk management assets and liabilities by segment at June 30, 2008 and September 30, 2007:


	Natural			Natural
	Gas			Gas
	Distribution			Marketing			Total
	(In thousands)

June 30, 2008:
Assets from risk management activities, current	$	37,366		$	5,534		$	42,900
Assets from risk management activities, noncurrent		—			5,904			5,904
Liabilities from risk management activities, current		—			(50,686	)		(50,686	)
Liabilities from risk management activities, noncurrent		—			(3,724	)		(3,724	)

Net assets (liabilities)	$	37,366		$	(42,972	)	$	(5,606	)

September 30, 2007:
Assets from risk management activities, current	$	—		$	21,849		$	21,849
Assets from risk management activities, noncurrent		—			5,535			5,535
Liabilities from risk management activities, current		(21,053	)		(286	)		(21,339	)
Liabilities from risk management activities, noncurrent		—			(290	)		(290	)

Net assets (liabilities)	$	(21,053	)	$	26,808		$	5,755

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Natural Gas Distribution Derivative Activities

In our natural gas distribution segment, we use a combination of physical storage and financial derivatives to partially insulate our natural gas distribution customers against gas price volatility during the winter heating season. These financial derivatives have not been designated as hedges pursuant to SFAS 133,Accounting for Derivative Instruments and Hedging Activities. Accordingly, they are recorded at fair value. However, because the costs associated with and the gains and losses arising from these financial derivatives are included in our purchased gas adjustment mechanisms, changes in the fair value of these financial derivatives are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas costs when the related costs are recovered through our rates in accordance with SFAS 71. Accordingly, there is no earnings impact to our natural gas distribution segment as a result of the use of financial derivatives.

Natural Gas Marketing Derivative Activities

Our natural gas marketing risk management activities are conducted through AEM. AEM is exposed to risks associated with changes in the market price of natural gas, and we manage our exposure to the risk of natural gas price changes through a combination of physical storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. AEM uses financial derivatives designated as fair value hedges to offset changes in the fair value of its natural gas inventory and derivatives designated as cash flow hedges to offset anticipated purchases and sales of gas in the future. AEM also utilizes basis swaps and other non-hedge derivative instruments to manage its exposure to market volatility.

Pipeline, Storage and Other Derivative Activities

Our pipeline, storage and other activities are also exposed to risks associated with changes in the market price of natural gas, which are managed through a combination of physical storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Atmos Pipeline and Storage, LLC uses financial derivatives designated as fair value hedges to offset changes in the fair value of its natural gas inventory.

Under our risk management policies for our nonregulated operations, 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 net 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 may 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 June 30, 2008, AEH had a net open position (including existing storage) of 0.1 Bcf.

Treasury Derivative Activities

We periodically manage our exposure to interest rate changes by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. Since fiscal 2004, we have executed five Treasury lock agreements.

The most recent treasury lock agreement was executed in March 2007, which fixed the Treasury yield component of the interest cost associated with $100 million of our $250 million 6.35% Senior Notes that were

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

issued in June 2007. This Treasury lock agreement was settled in June 2007, and resulted in the receipt of $4.8 million from the counterparties.

The settlement of the five Treasury lock agreements resulted in a net $39.0 million payment to the counterparties. We designated these Treasury lock agreements as a cash flow hedge of an anticipated transaction at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the Treasury lock agreements were recorded as a component of accumulated other comprehensive income. The net realized loss recognized upon settlement of the Treasury lock agreements was initially recorded as a component of accumulated other comprehensive income and is currently being recognized as a component of interest expense over the life of the related financing arrangements.

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2008 and 2007:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008			2007
	(In thousands)

Increase (decrease) in fair value:
Treasury lock agreements	$	—		$	2,204		$	—		$	2,945
Forward commodity contracts		6,636			(4,750	)		16,285			(6,975	)
Recognition of (gains) losses in earnings due to settlements:
Treasury lock agreements		787			835			2,361			2,556
Forward commodity contracts		(3,618	)		129			(1,524	)		27,376

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	3,805		$	(1,582	)	$	17,122		$	25,902


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

Hedge Ineffectiveness

Unrealized margins recorded in our natural gas marketing and pipeline, storage and other segments are comprised of various components, including, but not limited to, unrealized gains and losses arising from hedge ineffectiveness. Our hedge ineffectiveness primarily results from differences in the location and timing of the derivative instrument and the hedged item and could materially affect our results of operations for the reported period. Although these unrealized gains and losses are currently recorded in our income statement, they are not indicative of the economic gross profit we anticipate realizing when the underlying physical and financial transactions are settled.

Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity are referred to

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

as timing ineffectiveness. The portion of our unrealized margins related to basis and timing ineffectiveness gains and losses for the three and nine months ended June 30, 2008 and 2007 are as follows:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008			2007
	(In thousands)

Basis ineffectiveness:
Fair value basis ineffectiveness	$	(2,402	)	$	1,073		$	(1,185	)	$	942
Cash flow basis ineffectiveness		(406	)		1,479			(281	)		710

Total basis ineffectiveness		(2,808	)		2,552			(1,466	)		1,652
Timing ineffectiveness:
Fair value timing ineffectiveness		(1,842	)		(1,759	)		42,040			80,456

Total hedge ineffectiveness	$	(4,650	)	$	793		$	40,574		$	82,108


4.	Debt

Long-term debt

Long-term debt at June 30, 2008 and September 30, 2007 consisted of the following:


	June 30,			September 30,
	2008			2007
	(In thousands)

Unsecured 4.00% Senior Notes, due October 2009	$	400,000		$	400,000
Unsecured 7.375% Senior Notes, due 2011		350,000			350,000
Unsecured 10% Notes, due 2011		2,303			2,303
Unsecured 5.125% Senior Notes, due 2013		250,000			250,000
Unsecured 4.95% Senior Notes, due 2014		500,000			500,000
Unsecured 6.35% Senior Notes, due 2017		250,000			250,000
Unsecured 5.95% Senior Notes, due 2034		200,000			200,000
Medium term notes
Series A,1995-2, 6.27%, due 2010		10,000			10,000
Series A,1995-1, 6.67%, due 2025		10,000			10,000
Unsecured 6.75% Debentures, due 2028		150,000			150,000
First Mortgage Bonds
Series P, 10.43% due May 2008		—			7,500
Other term notes due in installments through 2013		1,648			3,890

Total long-term debt		2,123,951			2,133,693
Less:
Original issue discount on unsecured senior notes and debentures		(3,163	)		(3,547	)
Current maturities		(1,059	)		(3,831	)

	$	2,119,729		$	2,126,315

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Short-term debt

At June 30, 2008, there was $113.3 million outstanding under our commercial paper program and bank credit facilities. At September 30, 2007, there was $150.6 million outstanding under our commercial paper program and bank credit facilities.

Shelf Registration

On December 4, 2006, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in new common stockand/or debt securities available for issuance. As of June 30, 2008, we had approximately $450 million of availability remaining under the registration statement. Due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we are permitted to issue a total of approximately $100 million of equity securities, $50 million of senior debt securities and $300 million of subordinated debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard & Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until we received an investment grade rating from all of the three credit rating agencies.

Credit facilities

We maintain both committed and uncommitted credit facilities. Borrowings under our uncommitted credit facilities are made on awhen-and-as-needed basis at the discretion of the banks. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder winter months. Our working capital needs can vary significantly due to changes in the price of natural gas and the increased gas supplies required to meet customers’ needs during periods of cold weather.

Committed credit facilities

As of June 30, 2008, we had three short-term committed revolving credit facilities totaling $918 million. The first facility is a five-year unsecured facility, expiring December 2011, for $600 million that bears interest at a base rate or at the LIBOR rate for the applicable interest period, plus from 0.30 percent to 0.75 percent, based on the Company’s credit ratings, and serves as a backup liquidity facility for our $600 million commercial paper program. At June 30, 2008, there was $113.3 million outstanding under our commercial paper program.

The second facility is a $300 million unsecured364-day facility expiring November 2008, that bears interest at a base rate or the LIBOR rate for the applicable interest period, plus from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. At June 30, 2008, there were no borrowings under this facility.

The third facility is an $18 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. This facility expired on March 31, 2008 and was renewed effective April 1, 2008 for one year with no material changes to the terms and pricing. At June 30, 2008, there were no borrowings under this facility.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. 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 revolving credit facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At June 30, 2008, our

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

total-debt-to-total-capitalization ratio, as defined, was 55 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under our revolving credit facilities are subject to adjustment depending upon our credit ratings. The revolving credit facilities each contain the same limitation with respect to our total-debt-to-total-capitalization ratio.

Uncommitted credit facilities

AEM has a $580 million uncommitted demand working capital credit facility. On March 31, 2008, AEM and the participating banks amended the facility, primarily to extend it to March 31, 2009. In addition, the amendment removed the financial covenant relating to the amount of cumulative losses that could be incurred by AEM and its subsidiaries over a specific period of time and included provisions permitting the participating banks, or their affiliates, to participate in physical commodity transactions with AEM.

Borrowings under the credit facility can be made either as revolving loans or offshore rate loans. Revolving loan borrowings will bear interest at a floating rate equal to a base rate defined as the higher of (i) 0.50 percent per annum above the Federal Funds rate or (ii) the lender’s prime rate plus 0.25 percent. Offshore rate loan borrowings will bear interest at a floating rate equal to a base rate based upon LIBOR for the applicable interest period plus an applicable margin, ranging from 1.25 percent to 1.625 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. Borrowings drawn down under letters of credit issued by the banks will bear interest at a floating rate equal to the base rate, as defined above, plus an applicable margin, which will range from 1.00 percent to 1.875 percent per annum, depending on the excess tangible net worth of AEM and whether the letters of credit are swap-related standby letters of credit.

AEM is required by the financial covenants in the credit facility not to exceed a maximum ratio of total liabilities to tangible net worth of 5 to 1. At June 30, 2008, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.97 to 1. Additionally, AEM must maintain minimum levels of net working capital ranging from $20 million to $120 million and a minimum tangible net worth ranging from $21 million to $121 million. As defined in the financial covenants, at June 30, 2008, AEM’s net working capital was $253.3 million and its tangible net worth was $256.5 million.

At June 30, 2008, there were no borrowings outstanding under this credit facility. However, at June 30, 2008, AEM letters of credit totaling $161.9 million had been issued under the facility, which reduced the amount available by a corresponding amount. The amount available under this credit facility is also limited by various covenants, including covenants based on working capital. Under the most restrictive covenant, the amount available to AEM under this credit facility was $88.1 million at June 30, 2008. This line of credit is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

The Company also had an unsecured short-term uncommitted credit line of $25 million that is used for working-capital and letter-of-credit purposes. In January 2008, the unused portion of this facility was terminated by the lending bank and the remaining balance will be terminated as the outstanding letters of credit expire. At June 30, 2008, there was $5.3 million in letters of credit outstanding under this facility.

The Company has a $200 million intercompany uncommitted revolving credit facility with AEH. This facility bears interest at the lesser of (i) the one-month LIBOR rate plus 0.20 percent or (ii) the marginal borrowing rate available to the Company on any such date under its commercial paper program. Applicable state regulatory commissions have approved this facility through December 31, 2008. At June 30, 2008, there were no borrowings outstanding under this facility.

AEH has a $200 million intercompany uncommitted demand credit facility with the Company, which bears interest at the rate of AEM’s $580 million uncommitted demand working capital credit facility plus 0.75 percent. Applicable state regulatory commissions have approved this facility through December 31, 2008. At June 30, 2008, there was $17.3 million outstanding under this facility.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In addition, to supplement its $580 million credit facility, AEM has a $200 million intercompany uncommitted demand credit facility with AEH, which bears interest at the rate of AEM’s $580 million uncommitted demand working capital credit facility plus 0.75 percent. Any outstanding amounts under this facility are subordinated to AEM’s $580 million uncommitted demand credit facility. At June 30, 2008, there was $41.0 million outstanding under this facility.

Debt Covenants

We had other covenants in addition to those described above. Our Series P First Mortgage Bonds contained provisions that allowed us to prepay the outstanding balance in whole at any time, subject to a prepayment premium. The First Mortgage Bonds provided for certain cash flow requirements and restrictions on additional indebtedness, sale of assets and payment of dividends. In May 2008, we redeemed our Series P First Mortgage Bonds which were scheduled to mature in November 2013. Since the bonds have been redeemed, the debt covenants described above no longer apply.

We were in compliance with all of our debt covenants as of June 30, 2008. If we were unable to comply with our debt covenants, we could be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions. Our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. In addition, AEM’s credit agreement contains a cross-default provision whereby AEM would be in default if it defaults on other indebtedness, as defined, by at least $250 thousand in the aggregate. Additionally, this agreement contains a provision that would limit the amount of credit available if Atmos Energy were downgraded below an S&P rating of BBB and a Moody’s rating of Baa2.

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


5.	Shareholders’ Equity

Public Offering

On December 13, 2006, we completed a public offering of 6,325,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 825,000 shares. The offering was priced at $31.50 and generated net proceeds of approximately $192 million. We used the net proceeds from this offering to reduce short-term debt.

Shareholder Rights Plan

In November 1997, our Board of Directors declared a dividend distribution of one right for each outstanding share of our common stock to shareholders of record at the close of business on May 10, 1998, the description and terms of which were set forth in a rights agreement between us and the rights agent dated May 10, 1998. From that time until the expiration of the rights agreement on May 10, 2008, when all rights terminated, each share of common stock we issued included a right that entitled the holder to purchase from us a one-tenth share of our common stock at a purchase price of $8.00 per share, subject to adjustment.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Earnings Per Share

Basic and diluted earnings (loss) per share for the three and nine months ended June 30, 2008 and 2007 are calculated as follows:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008		2007
	(In thousands, except per share amounts)

Net income (loss)	$	(6,588	)	$	(13,360	)	$	178,749	$	174,406

Denominator for basic income per share — weighted average common shares		89,648			88,366			89,281		86,378
Effect of dilutive securities:
Restricted and other shares		—			—			557		464
Stock options		—			—			99		169

Denominator for diluted income per share — weighted average common shares		89,648			88,366			89,937		87,011

Income (loss) per share — basic	$	(0.07	)	$	(0.15	)	$	2.00	$	2.02

Income (loss) per share — diluted	$	(0.07	)	$	(0.15	)	$	1.99	$	2.00

There were approximately 557,000 and 466,000 restricted and other shares and approximately 99,000 and 165,000 stock options that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2008 and 2007 as their inclusion in the computation would be anti-dilutive.

There were no out-of-the-money options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2008 and 2007 as their exercise price was less than the average market price of the common stock during that period.


7.	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 and nine months ended June 30, 2008 and 2007 are presented in the following table. All of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.


	Three Months Ended June 30
	Pension Benefits						Other Benefits
	2008			2007			2008			2007
	(In thousands)

Components of net periodic pension cost:
Service cost	$	3,879		$	4,017		$	3,342		$	2,807
Interest cost		6,736			6,496			2,912			2,640
Expected return on assets		(6,311	)		(6,089	)		(715	)		(597	)
Amortization of transition asset		—			—			377			377
Amortization of prior service cost		(171	)		44			—			9
Amortization of actuarial loss		1,926			2,435			—			—

Net periodic pension cost	$	6,059		$	6,903		$	5,916		$	5,236

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30
	Pension Benefits						Other Benefits
	2008			2007			2008			2007
	(In thousands)

Components of net periodic pension cost:
Service cost	$	11,635		$	12,053		$	10,024		$	8,421
Interest cost		20,208			19,486			8,736			7,921
Expected return on assets		(18,932	)		(18,267	)		(2,145	)		(1,791	)
Amortization of transition asset		—			—			1,133			1,133
Amortization of prior service cost		(513	)		134			—			25
Amortization of actuarial loss		5,778			7,303			—			—

Net periodic pension cost	$	18,176		$	20,709		$	17,748		$	15,709

The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2008 and 2007 are as follows:


	Pension Benefits						Other Benefits
	2008			2007			2008			2007

Discount rate		6.30	%		6.30	%		6.30	%		6.30	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected return on plan assets		8.25	%		8.25	%		5.00	%		5.20	%

The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. We are not required to contribute to our pension plans during fiscal 2008 and do not anticipate making contributions. However, we contributed $6.7 million to our other post-retirement benefit plans during the nine months ended June 30, 2008. We expect to contribute a total of approximately $10 million to these plans during fiscal 2008.


8.	Commitments and Contingencies

Litigation and Environmental Matters

In December 2007, the Company received data requests from the Division of Investigations of the Office of Enforcement of the Federal Energy Regulatory Commission (the “Commission”) in connection with its investigation into possible violations of the Commission’s posting and competitive bidding regulations forpre-arranged released firm capacity on natural gas pipelines. We have responded timely to two sets of data requests received from the Commission and are fully cooperating with the Commission during this investigation.

Subsequent to responding to the second set of data requests, the Commission agreed to allow the Company to conduct our own internal investigation into compliance with the Commission’s rules, and we will provide the results of this internal investigation to the Commission upon its completion. We currently are unable to predict the final outcome of this investigation or the potential impact it could have on our financial position, results of operations or cash flows.

On May 29, 2008, the Texas Railroad Commission adopted a rule effective September 1, 2008, which will be applicable to all natural gas utility companies operating in Texas concerning the replacement of compression couplings at pre-bent gas meter risers. Compliance with this rule will require us to expend significant amounts of capital. This will cause us to redirect a greater portion of our capital budget towards

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

our Mid-Tex Division but these prudent and mandatory expenditures should be recoverable through our rates in this division. As a result, we anticipate no long-term adverse impact on our financial position, results of operations or cash flows.

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to the financial statements in our Annual Report onForm 10-K for the year ended September 30, 2007, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2008. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

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

Purchase Commitments

AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2008, AEM was committed to purchase 76.5 Bcf within one year, 38.4 Bcf within one to three years and 1.8 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year and 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $7.68 to $14.37. Purchases under these contracts totaled $842.1 million and $567.9 million for the three months ended June 30, 2008 and 2007 and $2,274.4 million and $1,551.3 million for the nine months ended June 30, 2008 and 2007.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area, which obligate it to purchase specified volumes at market prices. The estimated fiscal year commitments under these contracts as of June 30, 2008 are as follows (in thousands):


2008	$	71,430
2009		632,496
2010		164,008
2011		14,066
2012		12,878
Thereafter		16,124

	$	911,002

Regulatory Matters

During the three months ended June 30, 2008, we concluded rate cases we had filed in our Kansas and Mid-Tex service areas. As of June 30, 2008, rate cases were in progress in our Georgia and Virginia service areas, and we were working with the intervenors to complete their review of the Mid-Tex Division’s first Rate

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Review Mechanism filing made in April 2008. These regulatory proceedings are discussed in further detail inManagement’s Discussion and Analysis — Recent Ratemaking Developments.


9.	Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report onForm 10-K for the year ended September 30, 2007. During the nine months ended June 30, 2008, there were no material changes in our concentration of credit risk.


10.	Segment Information

Atmos Energy Corporation and our subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage businesses as well as certain other nonregulated businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

Through our nonregulated businesses, we provide natural gas management and marketing services to municipalities, other local distribution companies and industrial customers primarily in the Midwest and Southeast. Additionally, we provide natural gas transportation and storage services to certain of our natural gas distribution operations and to third parties.

We operate the Company through the following four segments:


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

	•	the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division,

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

	•	the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.

In our determination of reportable segments, we consider the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report onForm 10-K for the fiscal year ended September 30, 2007. We evaluate performance based on net income or loss of the respective operating units.

As described in our Annual Report onForm 10-K for the fiscal year ended September 30, 2007, we changed the composition of our operating segments. Effective September 2007, all prior period segment information has been restated to conform to our new segment presentation.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income statements for the three and nine-month periods ended June 30, 2008 and 2007 by segment are presented in the following tables:


	Three Months Ended June 30, 2008
	Natural			Regulated		Natural			Pipeline,
	Gas			Transmission		Gas			Storage and
	Distribution			and Storage		Marketing			Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	676,418		$	27,321	$	933,931		$	1,475	$	—		$	1,639,145
Intersegment revenues		221			18,965		255,791			2,405		(277,382	)		—

		676,639			46,286		1,189,722			3,880		(277,382	)		1,639,145
Purchased gas cost		476,711			—		1,192,353			706		(276,847	)		1,392,923

Gross profit		199,928			46,286		(2,631	)		3,174		(535	)		246,222
Operating expenses
Operation and maintenance		95,853			17,042		4,433			1,115		(621	)		117,822
Depreciation and amortization		44,737			4,860		381			378		—			50,356
Taxes, other than income		54,141			2,493		391			310		—			57,335

Total operating expenses		194,731			24,395		5,205			1,803		(621	)		225,513

Operating income (loss)		5,197			21,891		(7,836	)		1,371		86			20,709
Miscellaneous income		3,508			550		377			2,273		(5,108	)		1,600
Interest charges		28,504			6,606		2,850			532		(5,022	)		33,470

Income (loss) before income taxes		(19,799	)		15,835		(10,309	)		3,112		—			(11,161	)
Income tax expense (benefit)		(7,421	)		5,570		(3,995	)		1,273		—			(4,573	)

Net income (loss)	$	(12,378	)	$	10,265	$	(6,314	)	$	1,839	$	—		$	(6,588	)

Capital expenditures	$	92,856		$	18,252	$	132		$	2,916	$	—		$	114,156

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended June 30, 2007
	Natural			Regulated		Natural			Pipeline,
	Gas			Transmission		Gas			Storage and
	Distribution			and Storage		Marketing			Other			Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	548,104		$	20,694	$	649,633		$	(279	)	$	—		$	1,218,152
Intersegment revenues		147			16,013		204,534			2,352			(223,046	)		—

		548,251			36,707		854,167			2,073			(223,046	)		1,218,152
Purchased gas cost		357,608			—		854,743			228			(222,443	)		990,136

Gross profit		190,643			36,707		(576	)		1,845			(603	)		228,016
Operating expenses
Operation and maintenance		93,623			14,139		6,854			1,214			(689	)		115,141
Depreciation and amortization		43,661			4,559		376			378			—			48,974
Taxes, other than income		50,005			2,288		295			293			—			52,881
Impairment of long-lived assets		3,289			—		—			—			—			3,289

Total operating expenses		190,578			20,986		7,525			1,885			(689	)		220,285

Operating income (loss)		65			15,721		(8,101	)		(40	)		86			7,731
Miscellaneous income		2,232			620		1,578			3,992			(4,156	)		4,266
Interest charges		28,987			6,720		2,012			830			(4,070	)		34,479

Income (loss) before income taxes		(26,690	)		9,621		(8,535	)		3,122			—			(22,482	)
Income tax expense (benefit)		(11,000	)		3,459		(2,925	)		1,344			—			(9,122	)

Net income (loss)	$	(15,690	)	$	6,162	$	(5,610	)	$	1,778		$	—		$	(13,360	)

Capital expenditures	$	78,829		$	10,761	$	187		$	454		$	—		$	90,231

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30, 2008
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
					(In thousands)

Operating revenues from external parties	$	3,126,083	$	72,588	$	2,568,643	$	13,326	$	—		$	5,780,640
Intersegment revenues		589		70,184		590,449		7,303		(668,525	)		—

		3,126,672		142,772		3,159,092		20,629		(668,525	)		5,780,640
Purchased gas cost		2,296,020		—		3,099,428		1,773		(666,835	)		4,730,386

Gross profit		830,652		142,772		59,664		18,856		(1,690	)		1,050,254
Operating expenses
Operation and maintenance		291,678		47,560		17,835		3,939		(1,948	)		359,064
Depreciation and amortization		130,699		14,683		1,142		1,135		—			147,659
Taxes, other than income		142,063		6,322		3,798		987		—			153,170

Total operating expenses		564,440		68,565		22,775		6,061		(1,948	)		659,893

Operating income		266,212		74,207		36,889		12,795		258			390,361
Miscellaneous income		7,654		933		1,775		6,243		(13,631	)		2,974
Interest charges		88,802		20,453		6,166		1,755		(13,373	)		103,803

Income before income taxes		185,064		54,687		32,498		17,283		—			289,532
Income tax expense		71,622		19,351		12,933		6,877		—			110,783

Net income	$	113,442	$	35,336	$	19,565	$	10,406	$	—		$	178,749

Capital expenditures	$	266,840	$	40,334	$	201	$	5,503	$	—		$	312,878

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30, 2007
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
					(In thousands)

Operating revenues from external parties	$	2,973,048	$	59,029	$	1,844,271	$	20,019	$	—		$	4,896,367
Intersegment revenues		480		63,618		516,631		7,464		(588,193	)		—

		2,973,528		122,647		2,360,902		27,483		(588,193	)		4,896,367
Purchased gas cost		2,174,071		—		2,275,291		682		(585,971	)		3,864,073

Gross profit		799,457		122,647		85,611		26,801		(2,222	)		1,032,294
Operating expenses
Operation and maintenance		284,064		37,594		19,022		4,173		(2,480	)		342,373
Depreciation and amortization		133,287		13,400		1,153		1,195		—			149,035
Taxes, other than income		141,292		6,584		951		867		—			149,694
Impairment of long-lived assets		3,289		—		—		—		—			3,289

Total operating expenses		561,932		57,578		21,126		6,235		(2,480	)		644,391

Operating income		237,525		65,069		64,485		20,566		258			387,903
Miscellaneous income		6,633		1,530		5,816		5,588		(11,884	)		7,683
Interest charges		91,164		20,852		3,418		5,465		(11,626	)		109,273

Income before income taxes		152,994		45,747		66,883		20,689		—			286,313
Income tax expense		60,530		16,661		26,515		8,201		—			111,907

Net income	$	92,464	$	29,086	$	40,368	$	12,488	$	—		$	174,406

Capital expenditures	$	222,526	$	37,142	$	837	$	2,518	$	—		$	263,023

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at June 30, 2008 and September 30, 2007 by segment is presented in the following tables:


	June 30, 2008
	Natural		Regulated		Natural			Pipeline,
	Gas		Transmission		Gas			Storage and
	Distribution		and Storage		Marketing			Other		Eliminations			Consolidated
					(In thousands)

ASSETS
Property, plant and equipment, net	$	3,398,317	$	556,196	$	7,546		$	50,829	$	—		$	4,012,888
Investment in subsidiaries		476,542		—		(2,096	)		—		(474,446	)		—
Current assets
Cash and cash equivalents		32,949		—		13,308			244		—			46,501
Cash held on deposit in margin account		—		—		62,152			—		—			62,152
Assets from risk management activities		37,366		—		19,770			147		(14,383	)		42,900
Other current assets		687,453		16,669		627,786			49,919		(136,422	)		1,245,405
Intercompany receivables		490,979		—		—			203,115		(694,094	)		—

Total current assets		1,248,747		16,669		723,016			253,425		(844,899	)		1,396,958
Intangible assets		—		—		2,245			—		—			2,245
Goodwill		567,775		132,490		24,282			10,429		—			734,976
Noncurrent assets from risk management activities		—		—		5,904			—		—			5,904
Deferred charges and other assets		203,663		9,477		1,228			17,451		—			231,819

	$	5,895,044	$	714,832	$	762,125		$	332,134	$	(1,319,345	)	$	6,384,790

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,105,407	$	124,055	$	155,832		$	196,655	$	(476,542	)	$	2,105,407
Long-term debt		2,119,140		—		—			589		—			2,119,729

Total capitalization		4,224,547		124,055		155,832			197,244		(476,542	)		4,225,136
Current liabilities
Current maturities oflong-term debt		—		—		—			1,059		—			1,059
Short-term debt		113,257		—		41,000			17,275		(58,275	)		113,257
Liabilities from risk management activities		—		—		50,822			14,247		(14,383	)		50,686
Other current liabilities		635,200		6,078		343,238			95,290		(76,051	)		1,003,755
Intercompany payables		—		536,235		157,859			—		(694,094	)		—

Total current liabilities		748,457		542,313		592,919			127,871		(842,803	)		1,168,757
Deferred income taxes		393,426		44,710		8,948			3,585		—			450,669
Noncurrent liabilities from risk management activities		—		—		3,724			—		—			3,724
Regulatory cost of removal obligation		280,108		—		—			—		—			280,108
Deferred credits and other liabilities		248,506		3,754		702			3,434		—			256,396

	$	5,895,044	$	714,832	$	762,125		$	332,134	$	(1,319,345	)	$	6,384,790

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30, 2007
	Natural		Regulated		Natural			Pipeline,
	Gas		Transmission		Gas			Storage and
	Distribution		and Storage		Marketing			Other		Eliminations			Consolidated
					(In thousands)

ASSETS
Property, plant and equipment, net	$	3,251,144	$	531,921	$	7,850		$	45,921	$	—		$	3,836,836
Investment in subsidiaries		396,474		—		(2,096	)		—		(394,378	)		—
Current assets
Cash and cash equivalents		28,881		—		31,703			141		—			60,725
Cash held on deposit in margin account		—		—		—			—		—			—
Assets from risk management activities		—		—		26,783			12,947		(17,881	)		21,849
Other current assets		643,353		20,065		337,169			76,731		(90,997	)		986,321
Intercompany receivables		536,985		—		—			114,300		(651,285	)		—

Total current assets		1,209,219		20,065		395,655			204,119		(760,163	)		1,068,895
Intangible assets		—		—		2,716			—		—			2,716
Goodwill		567,775		132,490		24,282			10,429		—			734,976
Noncurrent assets from risk management activities		—		—		5,535			—		—			5,535
Deferred charges and other assets		227,869		4,898		1,279			13,913		—			247,959

	$	5,652,481	$	689,374	$	435,221		$	274,382	$	(1,154,541	)	$	5,896,917

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	1,965,754	$	88,719	$	107,090		$	200,665	$	(396,474	)	$	1,965,754
Long-term debt		2,125,007		—		—			1,308		—			2,126,315

Total capitalization		4,090,761		88,719		107,090			201,973		(396,474	)		4,092,069
Current liabilities
Current maturities oflong-term debt		1,250		—		—			2,581		—			3,831
Short-term debt		187,284		—		30,000			—		(66,685	)		150,599
Liabilities from risk management activities		21,053		—		18,167			—		(17,881	)		21,339
Other current liabilities		519,642		6,394		186,792			53,297		(22,216	)		743,909
Intercompany payables		—		550,184		101,101			—		(651,285	)		—

Total current liabilities		729,229		556,578		336,060			55,878		(758,067	)		919,678
Deferred income taxes		326,518		40,565		(8,925	)		12,411		—			370,569
Noncurrent liabilities from risk management activities		—		—		290			—		—			290
Regulatory cost of removal obligation		271,059		—		—			—		—			271,059
Deferred credits and other liabilities		234,914		3,512		706			4,120		—			243,252

	$	5,652,481	$	689,374	$	435,221		$	274,382	$	(1,154,541	)	$	5,896,917

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Atmos Energy Corporation

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of June 30, 2008, and the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2008 and 2007, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2008 and 2007. These financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 2007, 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 27, 2007, 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, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Ernst & Young LLP

Dallas, Texas

August 5, 2008


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 onForm 10-Q and Management’s Discussion and Analysis in our Annual Report onForm 10-K for the year ended September 30, 2007.

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 onForm 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties, which are discussed in more detail in our Annual Report onForm 10-K for the year ended September 30, 2007, include the following: 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, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in one state; adverse weather conditions; our ability to continue to access the capital markets; the effects of inflation and changes in the availability and prices of natural gas, including the volatility of natural gas prices; the capital-intensive nature of our distribution business, increased competition from energy suppliers and alternative forms of energy; increased costs of providing pension and postretirement health care benefits; the impact of environmental regulations on our business; the inherent hazards and risks involved in operating our distribution business, natural disasters, terrorist activities or other events; and other uncertainties, which may be discussed herein, including the outcome of any pending federal or state regulatory investigations, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy Corporation and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately 3.2 million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in 12 states. In addition, we transport natural gas for others through our distribution system.

Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.

We operate the Company through the following four segments:


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

	•	the regulated transmission and storage segment, which includes the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division,

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

	•	the pipeline, storage and other segment, which is comprised of our nonregulated natural gas gathering, transmission and storage services.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

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. Actual results may differ from such estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report onForm 10-K for the year ended September 30, 2007 and include the following:


	•	Regulation

	•	Revenue Recognition

	•	Allowance for Doubtful Accounts

	•	Derivatives and Hedging Activities

	•	Impairment Assessments

	•	Pension and Other Postretirement Plans

Our critical accounting policies are reviewed by the Audit Committee quarterly. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2008.

RESULTS OF OPERATIONS

The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2008 and 2007:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008		2007
	(In thousands, except per share data)

Operating revenues	$	1,639,145		$	1,218,152		$	5,780,640	$	4,896,367
Gross profit		246,222			228,016			1,050,254		1,032,294
Operating expenses		225,513			220,285			659,893		644,391
Operating income		20,709			7,731			390,361		387,903
Miscellaneous income		1,600			4,266			2,974		7,683
Interest charges		33,470			34,479			103,803		109,273
Income (loss) before income taxes		(11,161	)		(22,482	)		289,532		286,313
Income tax expense (benefit)		(4,573	)		(9,122	)		110,783		111,907
Net income (loss)	$	(6,588	)	$	(13,360	)	$	178,749	$	174,406
Diluted net income (loss) per share	$	(0.07	)	$	(0.15	)	$	1.99	$	2.00

Our consolidated net income (loss) during the three and nine months ended June 30, 2008 and 2007 was earned in each of our business segments as follows:


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands)

Natural gas distribution segment	$	(12,378	)	$	(15,690	)	$	3,312
Regulated transmission and storage segment		10,265			6,162			4,103
Natural gas marketing segment		(6,314	)		(5,610	)		(704	)
Pipeline, storage and other segment		1,839			1,778			61

Net loss	$	(6,588	)	$	(13,360	)	$	6,772


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands)

Natural gas distribution segment	$	113,442	$	92,464	$	20,978
Regulated transmission and storage segment		35,336		29,086		6,250
Natural gas marketing segment		19,565		40,368		(20,803	)
Pipeline, storage and other segment		10,406		12,488		(2,082	)

Net income	$	178,749	$	174,406	$	4,343

The following tables segregate our consolidated net income (loss) and diluted earnings per share between our regulated and nonregulated operations:


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands, except per share data)

Regulated operations	$	(2,113	)	$	(9,528	)	$	7,415
Nonregulated operations		(4,475	)		(3,832	)		(643	)

Consolidated net loss	$	(6,588	)	$	(13,360	)	$	6,772

Diluted EPS from regulated operations	$	(0.02	)	$	(0.11	)	$	0.09
Diluted EPS from nonregulated operations		(0.05	)		(0.04	)		(0.01	)

Consolidated diluted EPS	$	(0.07	)	$	(0.15	)	$	0.08


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands, except per share data)

Regulated operations	$	148,778	$	121,550	$	27,228
Nonregulated operations		29,971		52,856		(22,885	)

Consolidated net income	$	178,749	$	174,406	$	4,343

Diluted EPS from regulated operations	$	1.66	$	1.39	$	0.27
Diluted EPS from nonregulated operations		0.33		0.61		(0.28	)

Consolidated diluted EPS	$	1.99	$	2.00	$	(0.01	)

The following summarizes the results of our operations and other significant events for the nine months ended June 30, 2008:


	•	Regulated operations generated 83 percent of net income during the nine months ended June 30, 2008 compared to 70 percent during the nine months ended June 30, 2007. The $27.2 million increase in our regulated operations net income primarily reflects rate increases in our Mid-Tex, Kansas, Kentucky, Louisiana, Tennessee and West Texas service areas coupled with higher rates and throughput in our Atmos Pipeline — Texas Division.

	•	Nonregulated operations contributed 17 percent of net income during the nine months ended June 30, 2008 compared to 30 percent during the nine months ended June 30, 2007. The $22.9 million decrease in our nonregulated operations net income primarily reflects lower asset optimization margins partially offset by higher delivered gas margins and higher unrealized gains.

	•	For the nine months ended June 30, 2008, we generated $417.4 million in operating cash flow compared with $552.7 million for the nine months ended June 30, 2007, primarily reflecting an increase in cash required to collateralize our risk management accounts.

	•	In September 2007, we filed a statement of intent seeking a rate increase of $51.9 million in our Mid-Tex Division. During the fiscal 2008 second quarter, we reached a settlement agreement with approximately 80 percent of the Mid-Tex Division’s customers. In June 2008, the Railroad Commission of Texas (RRC) issued a final order, which ended the case for the remaining 20 percent of the Mid-Tex Division’s customers.

Three Months Ended June 30, 2008 compared with Three Months Ended June 30, 2007

Natural Gas Distribution Segment

The primary factors that impact the results of our natural gas distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.

Seasonal weather patterns can also affect our natural gas distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 90 percent of our residential and commercial meters in the following states for the following time periods:


Georgia		October – May
Kansas		October – May
Kentucky		November – April
Louisiana		December – March
Mississippi		November – April
Tennessee		November – April
Texas: Mid-Tex		November – April
Texas: West Texas		October – May
Virginia		January – December

Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income. Timing differences exist between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. The effect of these timing differences can be significant in periods of volatile gas prices, particularly in our Mid-Tex Division. These timing differences may favorably or unfavorably affect net income; however, these amounts should offset over time with no permanent impact on net income.

Higher gas costs may also adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. Finally, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or use alternative energy sources.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2008 and 2007 are presented below.


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands, unless otherwise noted)

Gross profit	$	199,928		$	190,643		$	9,285
Operating expenses		194,731			190,578			4,153

Operating income		5,197			65			5,132
Miscellaneous income		3,508			2,232			1,276
Interest charges		28,504			28,987			(483	)

Loss before income taxes		(19,799	)		(26,690	)		6,891
Income tax benefit		(7,421	)		(11,000	)		3,579

Net loss	$	(12,378	)	$	(15,690	)	$	3,312

Consolidated natural gas distribution sales volumes — MMcf		41,357			45,252			(3,895	)
Consolidated natural gas distribution transportation volumes — MMcf		32,126			29,311			2,815

Total consolidated natural gas distribution throughput — MMcf		73,483			74,563			(1,080	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.43		$	0.41		$	0.02
Consolidated natural gas distribution average cost of gas per Mcf sold	$	11.53		$	7.90		$	3.63

The following table shows our operating income by natural gas distribution division for the three months ended June 30, 2008 and 2007. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands)

Colorado-Kansas	$	542		$	884		$	(342	)
Kentucky/Mid-States		5,757			1,762			3,995
Louisiana		5,086			5,921			(835	)
Mid-Tex		(3,043	)		(11,415	)		8,372
Mississippi		(946	)		2,115			(3,061	)
West Texas		(563	)		(391	)		(172	)
Other		(1,636	)		1,189			(2,825	)

Total	$	5,197		$	65		$	5,132

The $9.3 million increase in natural gas distribution gross profit primarily reflects an $8.9 million increase in rates. The increase in rates primarily was attributable to the Mid-Tex Division, which increased $5.0 million as a result of the 2006 Gas Reliability Infrastructure Program (GRIP) filing, the current year Mid-Tex rate case and the absence of a one-time GRIP refund in the prior year. The current-year period also reflects $3.9 million in rate increases in our Kansas, Kentucky, Louisiana, Missouri, Tennessee and West Texas service areas.

Gross profit also increased approximately $0.4 million in revenue-related taxes primarily due to higher revenues, on which the tax is calculated, in the current-year quarter compared to the prior-year quarter. This increase, offset by a $2.9 million quarter-over-quarter increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in a $2.5 million decrease in operating income when compared with the prior-year quarter.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $4.2 million.

Operation and maintenance expense, excluding the provision for doubtful accounts, increased $2.3 million, primarily due to an overall increase in administrative costs.

Depreciation and amortization expense increased $1.1 million for the third quarter of fiscal 2008 compared with third quarter of fiscal 2007. The increase primarily was attributable to increases in assets placed in service during the current year.

Operating expenses for the prior-year quarter also include a $3.3 million noncash charge associated with the write-off of software costs.

Interest charges allocated to the natural gas distribution segment decreased $0.5 million due to lower average effective interest rates experienced during the current-year quarter compared to the prior-year quarter.

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the nine months ended June 30, 2008 are discussed below. The amounts described below represent the gross revenues that were requested or received in each 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.

Mid-Tex Division Rate Case

In September 2007, Atmos Energy filed a statement of intent seeking a system-wide rate increase of $51.9 million in our Mid-Tex Division. During the fiscal 2008 second quarter, we reached a settlement with 438 of the 439 cities (the “Settlement Cities”), which represent approximately 80 percent of the Mid-Tex Division’s customers. The settlement agreement includes i) an annual system-wide rate increase of approximately $10 million, of which approximately $8 million related to the Settlement Cities; ii) the ability to recover the gas cost portion of bad debt expense, iii) a rate review mechanism (RRM) that will adjust rates for the Settlement Cities annually to reflect changes in the Mid-Tex Division’s cost of service and rate base; iv) an authorized return on equity of 9.6 percent; v) an approved capital structure of 52 percent debt/48 percent equity and vi) the establishment of a new program designed to encourage natural gas conservation. New rates for the Settlement Cities were implemented April 1, 2008.

In April 2008, the Mid-Tex Division filed its first RRM that will adjust rates, effective October 1, 2008, for the Settlement Cities only. The filing seeks an annual system-wide rate increase of $33.5 million ($26.8 million for the Settlement Cities) and is currently under review.

The City of Dallas and unincorporated areas, which represent the remaining 20 percent of the Mid-Tex Division’s customers, elected not to participate in the settlement agreement. The Mid-Tex Division, the City of Dallas and representatives for the unincorporated areas conducted a full rate case before the Railroad Commission of Texas (RRC), culminating in the issuance of a final order in June 2008. Key terms of the final order include i) a $19.6 million system-wide annual rate increase, of which approximately $3.9 million related to the City of Dallas and unincorporated areas, ii) the ability to recover the gas cost portion of bad debt expense, iii) an authorized return on equity of 10 percent; iv) an approved capital structure of 52 percentdebt/48 percent equity and v) the establishment of a new program designed to encourage natural gas conservation. New rates for the City of Dallas and the unincorporated areas were implemented in July 2008.

The final order did not include an RRM; therefore, we will continue to make annual filings under the Texas Gas Reliability Infrastructure Program (GRIP) in order to update rates for customers in the City of

Dallas and in the unincorporated areas for approved capital expenditures, and we will continue to file traditional rate cases as necessary to assist in earning our authorized return in these areas.

In May 2008, the Mid-Tex Division filed a system-wide 2007 GRIP filing with the RRC. The filing seeks authorization to increase annual rates, on a system-wide basis by $10.3 million based on $58.2 million of capital costs incurred in 2007. It is currently anticipated that the RRC will issue a final order in this proceeding by November 2008. If approved as filed, the filing should result in an annual rate increase of approximately $2 million for customers in the City of Dallas and the unincorporated areas.

Other Rate Case Filings

In May 2006, Atmos Energy began receiving “show cause” ordinances from several of the cities in the West Texas Division. In December 2007, our West Texas Division reached a settlement agreement with the West Texas cities, resulting in an approved GRIP filing to include in rate base approximately $7.0 million of capital costs incurred during calendar year 2006. The filing should result in additional annual revenues of approximately $1.1 million.

In July 2008, the West Texas cities signed an agreement to implement a rate review mechanism for our West Texas system. The RRM will adjust rates on a periodic basis to reflect changes in the West Texas Division’s cost of service and rate base for this service area. The West Texas Division expects to file its first RRM in September 2008, which will adjust rates for the West Texas cities effective November 15, 2008.

In May 2008, the City of Lubbock approved its Conservation and Customer Value Plan (CCVP), which contains an annual rate review mechanism that would adjust rates to reflect changes in the West Texas Division’s cost of service and rate base. The West Texas Division filed its annual review filing under the CCVP in June 2008, which is currently under review by the City of Lubbock. The filing recommends a $0.5 million decrease in annual rates, and is expected to become effective October 1, 2008.

In October 2007, our Kentucky/Mid-States Division settled its $11.1 million rate case filed in May 2007 with the Tennessee Regulatory Authority. The settlement resulted in an increase in annual revenues of $4.0 million and a $4.1 million reduction in depreciation expense.

In September 2007, we filed an application with the Kansas Corporation Commission (KCC) requesting a rate increase of $5.0 million in our Kansas service area. A final order adopting the Company’s settlement with the KCC Staff was issued in May 2008 resulting in an increase in annual revenues of $2.1 million.

In February 2008, we filed for an annual rate increase of $0.9 million in the Virginia jurisdiction of our Kentucky/Mid-States Division. New rates, subject to refund, were implemented in April 2008. A procedural schedule has been established that should result in a final order being issued by the fourth quarter of fiscal year 2008.

In March 2008, we filed for an annual rate increase of $6.2 million in the Georgia jurisdiction of our Kentucky/Mid-States Division. The first round of hearings was completed in July 2008. A procedural schedule has been established that should result in a final order being issued by the fourth quarter of fiscal year 2008.

Stable Rate Filings

Louisiana Division. In December 2007, we filed our TransLa annual rate stabilization clause with the Louisiana Public Service Commission requesting an increase of $2.2 million, including an increase in depreciation expense of approximately $0.4 million. The filing was for the test year ended September 30, 2007. The TransLa filing was approved in March 2008 and resulted in an increase of $2.1 million in annual revenues effective April 1, 2008. In April 2008, we filed the LGS annual rate stabilization clause, requesting an increase of $2.6 million. The filing was for the test year ended December 31, 2007. The LGS filing was approved in June 2008 and resulted in an increase of $1.7 million in annual revenues effective July 1, 2008.

Mississippi Division. In December 2007, the Mississippi Public Service Commission approved our annual stable rate filing with no change in rates.

Regulated Transmission and Storage Segment

Our regulated transmission and storage segment consists of the regulated pipeline and storage operations of the Atmos Pipeline — Texas Division. The Atmos Pipeline — Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services customary in the pipeline industry including parking and lending arrangements and sales of inventory on hand.

Similar to our natural gas distribution segment, our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service areas. Further, as the Atmos Pipeline — Texas Division operations supply all of the natural gas for our Mid-Tex Division, the results of this segment are highly dependent upon the natural gas requirements of the Mid-Tex Division. Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2008 and 2007 are presented below.


	Three Months Ended
	June 30
	2008		2007		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	18,761	$	15,718	$	3,043
Third-party transportation		22,485		16,807		5,678
Storage and park and lend services		2,387		1,893		494
Other		2,653		2,289		364

Gross profit		46,286		36,707		9,579
Operating expenses		24,395		20,986		3,409

Operating income		21,891		15,721		6,170
Miscellaneous income		550		620		(70	)
Interest charges		6,606		6,720		(114	)

Income before income taxes		15,835		9,621		6,214
Income tax expense		5,570		3,459		2,111

Net income	$	10,265	$	6,162	$	4,103

Gross pipeline transportation volumes — MMcf		181,112		157,825		23,287

Consolidated pipeline transportation volumes — MMcf		152,450		125,639		26,811

The $9.6 million increase in gross profit primarily was attributable to a $4.4 million increase from rate adjustments resulting from our 2006 and 2007 GRIP filings and a $2.5 million increase from transportation volumes. Consolidated throughput increased 21 percent, primarily due to increased transportation in the Barnett Shale region of Texas. The improvement in gross profit also reflects $1.5 million of increasedper-unit transportation margins due to favorable market conditions.

Operating expenses increased $3.4 million primarily due to increased pipeline integrity and maintenance costs.

Recent Ratemaking Developments

In April 2008, the RRC approved the GRIP filing for our Atmos Pipeline — Texas Division to include in rate base approximately $46.6 million of capital costs incurred during calendar year 2007. The filing should

result in additional annual revenues of approximately $7.0 million. These revenues represent the gross revenues that were received in the filing, which may not necessarily result in an equal increase in operating income, as some operating costs may increase.

Natural Gas Marketing Segment

Our natural gas marketing activities are conducted through Atmos Energy Marketing, LLC (AEM). AEM aggregates and purchases gas supply, arranges transportationand/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of financial instruments. As a result, our revenues arise from the types of commercial transactions we have structured with our customers and include the value we extract by optimizing the storage and transportation capacity we own or control as well as revenues received for services we deliver.

Our asset optimization activities seek to maximize the economic value associated with the storage and transportation capacity we own or control. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit from the pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to lock in a gross profit margin. We also seek to participate in transactions in which we combine the natural gas commodity and transportation costs to minimize our costs incurred to serve our customers by identifying the lowest cost alternative within the natural gas supplies, transportation and markets to which we have access. Through the use of transportation and storage services and financial instruments, we also seek to capture gross profit margin through the arbitrage of pricing differences that exist in various locations and by recognizing pricing differences that occur over time.

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

We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our natural gas marketing storage activities. These financial instruments are marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains and losses in the period of change. The hedged natural gas inventory is marked to market at the end of each month based on the Gas Daily index with changes in fair value recognized as unrealized gains and losses in the period of change. Changes in the spreads between the forward natural gas prices used to value the financial hedges designated against our physical inventory and the market (spot) prices used to value our physical storage result in unrealized margins until the underlying physical gas is withdrawn and the related financial instruments are settled. Once the gas is withdrawn and the financial instruments are settled, the previously unrealized margins associated with these net positions are realized.

AEM also uses financial instruments to capture additional storage arbitrage opportunities that may arise after the execution of the original physical inventory hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the three months ended June 30, 2008 and 2007 are presented below. Gross profit margin consists primarily of margins earned from the delivery of gas and related services requested by our customers and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.

Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical (spot) and forward natural gas prices. Generally, if thephysical/financial spread narrows, we will record unrealized gains or lower unrealized losses. If the physical/financial spread widens, we will record unrealized losses or lower unrealized gains. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	11,231		$	9,999		$	1,232
Asset optimization		(37,551	)		(33,376	)		(4,175	)

		(26,320	)		(23,377	)		(2,943	)
Unrealized margins		23,689			22,801			888

Gross profit		(2,631	)		(576	)		(2,055	)
Operating expenses		5,205			7,525			(2,320	)

Operating loss		(7,836	)		(8,101	)		265
Miscellaneous income		377			1,578			(1,201	)
Interest charges		2,850			2,012			838

Loss before income taxes		(10,309	)		(8,535	)		(1,774	)
Income tax benefit		(3,995	)		(2,925	)		(1,070	)

Net loss	$	(6,314	)	$	(5,610	)	$	(704	)

Gross natural gas marketing sales volumes — MMcf		103,403			104,783			(1,380	)

Consolidated natural gas marketing sales volumes — MMcf		82,122			85,413			(3,291	)

Net physical position (Bcf)		17.5			21.5			(4.0	)

The $2.1 million decrease in our natural gas marketing segment’s gross profit primarily reflects a $4.2 million decrease in realized asset optimization margins. Natural gas market conditions were significantly less volatile during the current-year compared with the prior-year, which created fewer opportunities to realize arbitrage gains. During the quarter, AEM elected to defer storage withdrawals and reset the corresponding financial instruments in order to increase, in future periods, the potential gross profit it could realize from its asset optimization activities. As a result, AEM realized settlement losses without corresponding storage withdrawal gains in the current quarter. In the prior year, AEM accelerated the withdrawal of physical gas into the fiscal 2007 second quarter and executed new financial instruments to hedge the original financial instruments. The losses incurred on the settlement of these financial instruments in the prior-year quarter were smaller than the settlement losses experienced in the current quarter.

The increased loss generated from realized asset optimization activities was partially offset by a $1.2 million increase in realized delivered gas margins. The increase was largely attributable to slightly higherper-unit margins, compared with the prior-year quarter, partially offset by slightly lower sales volumes.

Gross profit margin was also favorably impacted by a $0.9 million increase in unrealized margins attributable to a narrowing of the spreads between current cash prices and forward natural gas prices. The change in unrealized margins also reflects the recognition of previously unrealized margins as a component of realized margins as a result of injecting and withdrawing gas and settling financial instruments as a part of AEM’s asset optimization activities.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, decreased $2.3 million primarily due to a decrease in employee and other administrative costs.

Economic Gross Profit

AEM monitors the impact of its asset optimization efforts by estimating the gross profit, before associated storage fees, that it captured through the purchase and sale of physical natural gas and the execution of the associated financial instruments. This economic gross profit, combined with the effect of the future reversal of unrealized gains or losses currently recognized in the income statement is referred to as the potential gross profit.⁽¹⁾ The following table presents AEM’s economic gross profit and its potential gross profit at June 30, 2008, March 31, 2008, December 31, 2007 and September 30, 2007.


					Associated Net
	Net Physical		Economic Gross		Unrealized Gain			Potential Gross
Period Ending	Position		Profit		(Loss)			Profit⁽¹⁾
	(Bcf)		(In millions)		(In millions)			(In millions)

June 30, 2008		17.5	$	48.2	$	34.3		$	13.9
March 31, 2008		20.7	$	10.8	$	(0.6	)	$	11.4
December 31, 2007		17.7	$	44.2	$	32.9		$	11.3
September 30, 2007		12.3	$	40.8	$	10.8		$	30.0


⁽¹⁾		Potential gross profit represents the increase in AEM’s gross profit in future periods if its optimization efforts are executed as planned. This amount does not include storage and other operating expenses and increased income taxes that will be incurred to realize this amount. Therefore, it does not represent an estimated increase in future net income. There is no assurance that the economic gross profit or the potential gross profit will be fully realized in the future. We consider this measure a non-GAAP financial measure as it is calculated using both forward-looking storage injection/withdrawal and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.

As of June 30, 2008, based upon AEM’s planned inventory withdrawal schedule and associated planned settlement of financial instruments, the economic gross profit was $48.2 million. This amount will be reduced by $34.3 million of net unrealized gains recorded in the financial statements as of June 30, 2008 that will reverse when the inventory is withdrawn and the accompanying financial instruments are settled. Therefore, the potential gross profit was $13.9 million at June 30, 2008.

The $2.5 million increase in potential gross profit as compared to March 31, 2008, is comprised of a $37.4 million increase in the economic gross profit, principally due to the election to roll positions into forward months as described above, partially offset by a $34.9 million increase in unrealized gains primarily attributable to recognizing as a component of realized margin previously unrealized losses and a favorable movement in the market prices used to value our natural gas storage inventory.

The economic gross profit is based upon planned storage injection and withdrawal schedules and its realization is contingent upon the execution of this plan, weather and other execution factors. Since AEM actively manages and optimizes its portfolio to attempt to enhance the future profitability of its storage position, it may change its scheduled storage injection and withdrawal plans from one time period to another based on market conditions. Therefore, we cannot ensure that the economic gross profit or the potential gross profit calculated as of June 30, 2008 will be fully realized in the future nor can we predict in what time

periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted. Assuming AEM fully executes its plan in place on June 30, 2008, without encountering operational or other issues, we anticipate a portion of the potential gross profit as of June 30, 2008 will be recognized during the final quarter of fiscal 2008 with most of the remainder recognized during fiscal 2009.

Pipeline, Storage and Other Segment

APS owns or has an interest in underground storage fields in Kentucky and Louisiana. We use these storage facilities to reduce the need to contract for additional pipeline capacity to meet customer demand during peak periods. Additionally, beginning in fiscal 2006, APS initiated activities in the natural gas gathering business. As of June 30, 2008, these activities were limited in nature.

AES, through December 31, 2006, provided natural gas management services to our natural gas distribution operations, other than the Mid-Tex Division. These services included aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering the gas to our natural gas distribution service areas at competitive prices. Effective January 1, 2007, these services were moved to our shared services function included in our natural gas distribution segment. AES continues to provide limited services to our natural gas distribution divisions, and the revenues AES receives are equal to the costs incurred to provide those services.

Through Atmos Power Systems, Inc., we have constructed electric peaking power-generating plants and associated facilities and lease these plants through lease agreements that are accounted for as sales under generally accepted accounting principles.

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

Review of Financial and Operating Results

Financial and operational highlights for our pipeline, storage and other segment for the three months ended June 30, 2008 and 2007 are presented below.


	Three Months Ended
	June 30
	2008			2007			Change
	(In thousands)

Storage and transportation services	$	3,691		$	4,060		$	(369	)
Asset optimization		(1,329	)		(2,247	)		918
Other		1,210			845			365
Unrealized margins		(398	)		(813	)		415

Gross profit		3,174			1,845			1,329
Operating expenses		1,803			1,885			(82	)

Operating income (loss)		1,371			(40	)		1,411
Miscellaneous income		2,273			3,992			(1,719	)
Interest charges		532			830			(298	)

Income before income taxes		3,112			3,122			(10	)
Income tax expense		1,273			1,344			(71	)

Net income	$	1,839		$	1,778		$	61

Pipeline, storage and other gross profit increased $1.3 million primarily due to a $0.9 million increase in asset optimization margins as a result of a more favorable settlement of our asset management contracts in the current-year period. This increase was coupled with a $0.4 million increase in unrealized margins associated with asset optimization activities.

Operating expenses for the three months ended June 30, 2008 were consistent with the prior-year quarter.

Nine Months Ended June 30, 2008 compared with Nine Months Ended June 30, 2007

Natural Gas Distribution Segment

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2008 and 2007 are presented below.


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands, unless otherwise noted)

Gross profit	$	830,652	$	799,457	$	31,195
Operating expenses		564,440		561,932		2,508

Operating income		266,212		237,525		28,687
Miscellaneous income		7,654		6,633		1,021
Interest charges		88,802		91,164		(2,362	)

Income before income taxes		185,064		152,994		32,070
Income tax expense		71,622		60,530		11,092

Net income	$	113,442	$	92,464	$	20,978

Consolidated natural gas distribution sales volumes — MMcf		261,692		265,508		(3,816	)
Consolidated natural gas distribution transportation volumes — MMcf		105,605		101,572		4,033

Total consolidated natural gas distribution throughput — MMcf		367,297		367,080		217

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.44	$	0.46	$	(0.02	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	8.77	$	8.19	$	0.58

The following table shows our operating income by natural gas distribution division for the nine months ended June 30, 2008 and 2007. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands)

Colorado-Kansas	$	22,766	$	24,524	$	(1,758	)
Kentucky/Mid-States		49,800		44,913		4,887
Louisiana		36,254		39,540		(3,286	)
Mid-Tex		119,661		82,932		36,729
Mississippi		23,397		25,918		(2,521	)
West Texas		13,332		18,230		(4,898	)
Other		1,002		1,468		(466	)

Total	$	266,212	$	237,525	$	28,687

The $31.2 million increase in natural gas distribution gross profit primarily reflects a $31.7 million net increase in rates. The net increase in rates primarily was attributable to the Mid-Tex Division which increased $24.1 million as a result of the 2006 GRIP filing, the previous and current year Mid-Tex rate cases and the absence of a one time GRIP refund in the prior year. The current-year period also reflects $10.7 million in rate increases in our Kansas, Kentucky, Louisiana, Tennessee and West Texas service areas.

Gross profit also increased approximately $6.5 million in revenue-related taxes primarily due to higher revenues, on which the tax is calculated, in the current-year period compared to the prior-year period. This increase, partially offset by a $2.5 million period-over-period increase in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulted in a $4.0 million increase in operating income, when compared with the prior-year period.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased by $2.5 million.

Operation and maintenance expense, excluding the provision for doubtful accounts, increased $11.1 million, primarily due to increased administrative and natural gas odorization costs partially offset by lower employee costs. The increase in operation and maintenance expense also reflects the absence in the current-year period of a nonrecurring $4.3 million deferral of hurricane-related operation and maintenance expenses in the prior-year period.

The provision for doubtful accounts decreased $3.5 million to $10.2 million for the nine months ended June 30, 2008. The decrease primarily was attributable to strong collection efforts.

Depreciation and amortization expense decreased $2.6 million for the nine months ended June 30, 2008 compared with the nine months ended June 30, 2007. The decrease primarily was attributable to changes in depreciation rates as a result of recent rate cases.

Operating expenses for the prior-year period also include a $3.3 million noncash charge associated with the write-off of software costs.

Results for the current-year period include a $1.2 million gain on the sale of irrigation assets in our West Texas Division during the fiscal 2008 second quarter.

Interest charges allocated to the natural gas distribution segment decreased $2.4 million due to lower average outstanding short-term debt balances in the current-year period compared with the prior-year period.

Regulated Transmission and Storage Segment

Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2008 and 2007 are presented below.


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	69,409	$	62,149	$	7,260
Third-party transportation		58,946		45,162		13,784
Storage and park and lend services		6,288		6,943		(655	)
Other		8,129		8,393		(264	)

Gross profit		142,772		122,647		20,125
Operating expenses		68,565		57,578		10,987

Operating income		74,207		65,069		9,138
Miscellaneous income		933		1,530		(597	)
Interest charges		20,453		20,852		(399	)

Income before income taxes		54,687		45,747		8,940
Income tax expense		19,351		16,661		2,690

Net income	$	35,336	$	29,086	$	6,250

Gross pipeline transportation volumes — MMcf		593,452		528,144		65,308

Consolidated pipeline transportation volumes — MMcf		429,758		359,447		70,311

The $20.1 million increase in gross profit primarily was attributable to a $10.0 million increase from rate adjustments resulting from our 2006 and 2007 GRIP filings and a $6.1 million increase from transportation volumes. Consolidated throughput increased 20 percent primarily due to increased transportation in the Barnett Shale region of Texas. The improvement in gross profit also reflects increased service fees andper-unit transportation margins due to favorable market conditions which contributed $3.6 million. New compression contracts and transportation capacity enhancements also contributed $2.4 million. These increases were partially offset by a $1.6 million decrease in sales of excess gas compared to the same period in the prior year and a $1.0 million decrease in parking and lending services due to market conditions.

Operating expenses increased $11.0 million primarily due to increased pipeline integrity and maintenance costs.

Natural Gas Marketing Segment

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the nine months ended June 30, 2008 and 2007 are presented below.


	Nine Months Ended
	June 30
	2008			2007		Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	55,599		$	44,320	$	11,279
Asset optimization		(10,339	)		38,558		(48,897	)

		45,260			82,878		(37,618	)
Unrealized margins		14,404			2,733		11,671

Gross profit		59,664			85,611		(25,947	)
Operating expenses		22,775			21,126		1,649

Operating income		36,889			64,485		(27,596	)
Miscellaneous income		1,775			5,816		(4,041	)
Interest charges		6,166			3,418		2,748

Income before income taxes		32,498			66,883		(34,385	)
Income tax expense		12,933			26,515		(13,582	)

Net income	$	19,565		$	40,368	$	(20,803	)

Gross natural gas marketing sales volumes — MMcf		348,789			306,931		41,858

Consolidated natural gas marketing sales volumes — MMcf		298,351			264,325		34,026

Net physical position (Bcf)		17.5			21.5		(4.0	)

The $25.9 million decrease in our natural gas marketing segment’s gross profit primarily reflects a $48.9 million decrease in realized asset optimization margins. As a result of a less volatile natural gas market experienced during the year, AEM has been regularly deferring storage withdrawals and resetting the associated financial instruments to increase the potential gross profit it could realize from its asset optimization activities in future periods. As a result, AEM recognized settlement losses without corresponding storage withdrawal gains during the current fiscal year. Additionally, AEM experienced increased storage fees charged by third parties during this time period. In the prior year, AEM was able to recognize arbitrage gains as changes in its originally scheduled storage injection and withdrawal plans had a significantly smaller impact.

The decrease in realized asset optimization margins was partially offset by an $11.3 million increase in realized delivered gas margins. The increase reflects both increased sales volumes and increasedper-unit margins. Gross sales volumes increased 14 percent compared with the prior-year period as we were able to successfully execute our marketing initiatives. The increase in theper-unit margin primarily reflects favorable basis gains on certain contracts. After excluding the effect of these location basis gains, ourper-unit margins decreased four percent in the current-year period due to increased competition experienced during the third fiscal quarter in a higher-priced natural gas market.

Gross profit margin was also favorably impacted by an $11.7 million increase in unrealized margins attributable to a narrowing of the spreads between current cash prices and forward natural gas prices. The change in unrealized margins also reflects the recognition of previously unrealized margins as a component of realized margins as a result of injecting and withdrawing gas and settling financial instruments as a part of AEM’s asset optimization activities.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $1.6 million. The increase reflects $2.4 million for the settlement of certain tax matters partially offset by a $0.8 million decrease in employee and other administrative costs.

Pipeline, Storage and Other Segment

Review of Financial and Operating Results

Financial and operational highlights for our pipeline, storage and other segment for the nine months ended June 30, 2008 and 2007 are presented below.


	Nine Months Ended
	June 30
	2008		2007		Change
	(In thousands)

Storage and transportation services	$	11,325	$	11,850	$	(525	)
Asset optimization		3,783		10,947		(7,164	)
Other		3,701		2,992		709
Unrealized margins		47		1,012		(965	)

Gross profit		18,856		26,801		(7,945	)
Operating expenses		6,061		6,235		(174	)

Operating income		12,795		20,566		(7,771	)
Miscellaneous income		6,243		5,588		655
Interest charges		1,755		5,465		(3,710	)

Income before income taxes		17,283		20,689		(3,406	)
Income tax expense		6,877		8,201		(1,324	)

Net income	$	10,406	$	12,488	$	(2,082	)

Pipeline, storage and other gross profit decreased $7.9 million primarily due to a $7.2 million decrease in asset optimization margins as a result of a less volatile natural gas market. The change in gross profit also reflects a decrease of $1.0 million in unrealized margins associated with asset optimization activities.

Operating expenses for the nine months ended June 30, 2008 remained generally unchanged compared with the prior-year period.

Liquidity and Capital Resources

Our working capital and liquidity for capital expenditures and other cash needs are provided from internally generated funds and borrowings under our credit facilities and commercial paper program. Additionally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.

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, prices for our products and services, 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

Period-over-period changes in our operating cash flows primarily are attributable to changes in net income, working capital changes, particularly within our natural gas distribution segment resulting from the

price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the nine months ended June 30, 2008, we generated operating cash flow of $417.4 million from operating activities compared with $552.7 million for the nine months ended June 30, 2007. Period over period, our operating cash flow was reduced primarily by cash required to collateralize our risk management accounts, which reduced operating cash flows by $84.2 million. Additionally, changes in accounts receivable and gas stored underground reduced operating cash flow by $219.9 million. These decreases were partially offset by favorable timing of accounts payable and accrued liabilities which increased operating cash flow by $141.8 million. Finally, other changes in working capital and other items increased operating cash flow by $27.0 million.

Cash flows from investing activities

In recent years, a substantial portion of our cash resources has been used to fund acquisitions and growth projects, our ongoing construction program and improvements to information systems. Our ongoing construction program enables us to provide natural gas distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. In executing our current rate strategy, we are directing discretionary capital spending to jurisdictions that permit us to earn a timely return on our investment. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division have rate designs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

Capital expenditures for fiscal 2008 are expected to range from $455 million to $465 million. For the nine months ended June 30, 2008, we incurred $312.9 million for capital expenditures compared with $263.0 million for the nine months ended June 30, 2007. The increase in capital spending primarily reflects an increase in main replacements in our Mid-Tex Division and spending in the natural gas distribution segment for our new automated metering initiative. This initiative is expected to improve the efficiency of our meter reading process through the installation of equipment that automatically reads and transfers customer consumption and other data to our customer information systems.

Cash flows from financing activities

For the nine months ended June 30, 2008, our financing activities reflected a use of cash of $114.4 million compared with $5.2 million in the prior-year period. Our significant financing activities for the nine months ended June 30, 2008 and 2007 are summarized as follows.


	•	During the nine months ended June 30, 2008, we repaid a net $35.7 million under our short-term credit facilities. The net repayment reflects the timing of the use of our line of credit to finance natural gas purchases.

	•	We repaid $9.9 million of long-term debt during the nine months ended June 30, 2008 compared with $2.7 million during the nine months ended June 30, 2007. The increased payments during the current-year period reflects the prepayment of $7.5 million of our Series P First Mortgage Bonds. In connection with this prepayment we paid a $0.2 million make-whole premium in accordance with the terms of the bonds and related indenture.

	•	In December 2006, we sold 6.3 million shares of common stock in an offering, including the underwriters’ exercise of their overallotment option of 0.8 million shares, generating net proceeds of approximately $192 million. The net proceeds from this issuance were used to reduce our short-term debt.

	•	During the nine months ended June 30, 2008, we paid $87.8 million in cash dividends compared with $83.1 million for the nine months ended June 30, 2007. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.96 per share during the nine months


		ended June 30, 2007 to $0.975 per share during the nine months ended June 30, 2008 combined with our December 2006 equity offering and new share issuances under our various equity plans.


	•	During the nine months ended June 30, 2008, we issued 0.7 million shares of common stock under our various equity plans which generated net proceeds of $19.1 million. In addition, we granted 0.5 million shares of common stock under our 1998 Long-Term Incentive Plan.

The following table summarizes our share issuances for the nine months ended June 30, 2008 and 2007.


	Nine Months Ended
	June 30
	2008		2007

Shares issued:
Direct Stock Purchase Plan		294,071		238,689
Retirement Savings Plan		410,350		306,920
1998 Long-Term Incentive Plan		538,100		500,684
Outside Directors Stock-for-Fee Plan		2,399		1,776
Public Offering		—		6,325,000

Total shares issued		1,244,920		7,373,069

Credit Facilities

As of June 30, 2008, we had a total of approximately $1.5 billion of credit facilities, comprised of three short-term committed credit facilities totaling $918 million and, through AEM, an uncommitted credit facility that can provide up to $580 million. Borrowings under our uncommitted credit facilities are made on awhen-and-as-needed basis at the discretion of the banks. Our credit capacity and the amount of unused borrowing capacity are affected by the seasonal nature of the natural gas business and our short-term borrowing requirements, which are typically highest during colder winter months. Our working capital needs can vary significantly due to changes in the price of natural gas charged by suppliers and the increased gas supplies required to meet customers’ needs during periods of cold weather.

As of June 30, 2008, the amount available to us under our credit facilities, net of outstanding letters of credit, was $1.0 billion. We believe these credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs. These facilities are described in further detail in Note 4 to the unaudited condensed consolidated financial statements.

Shelf Registration

On December 4, 2006, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in new common stockand/or debt securities available for issuance. As of June 30, 2008, we had approximately $450 million available for issuance under the registration statement. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the registration statement, we are permitted to issue a total of approximately $100 million of equity securities, $50 million of senior debt securities and $300 million of subordinated debt securities. In addition, due to restrictions imposed by another state regulatory commission, if the credit ratings on our senior unsecured debt were to fall below investment grade from either Standard & Poor’s Corporation (BBB-), Moody’s Investors Services, Inc. (Baa3) or Fitch Ratings, Ltd. (BBB-), our ability to issue any type of debt securities under the registration statement would be suspended until an investment grade rating from all three credit rating agencies was achieved.

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt,

operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.

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

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB

Baa3

BBB+

Commercial paper

A-2

P-3

F-2

Currently, with respect to our unsecured senior long-term debt, S&P maintains its positive outlook and Fitch maintains its stable outlook. Moody’s recently reaffirmed its stable outlook. None of our ratings are currently under review.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independent of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of June 30, 2008. Our debt covenants are described in Note 4 to the unaudited condensed consolidated financial statements.

Capitalization

The following table presents our capitalization as of June 30, 2008, September 30, 2007 and June 30, 2007:


	June 30,				September 30,				June 30,
	2008				2007				2007
	(In thousands, except percentages)

Short-term debt	$	113,257	2.6	%	$	150,599	3.5	%	$	—	—	%
Long-term debt		2,120,788	48.9	%		2,130,146	50.2	%		2,430,518	55.0	%
Shareholders’ equity		2,105,407	48.5	%		1,965,754	46.3	%		1,988,142	45.0	%

Total capitalization	$	4,339,452	100.0	%	$	4,246,499	100.0	%	$	4,418,660	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 51.5 percent at June 30, 2008, 53.7 percent at September 30, 2007 and 55.0 percent at June 30, 2007. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and access to the equity capital markets.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2008.

In February 2008, Atmos Pipeline and Storage, LLC announced plans to construct and operate a salt-cavern gas storage project in Franklin Parish, Louisiana. The project, located near several large interstate pipelines, includes the development of three 5 billion cubic feet (Bcf) caverns for a total of 15 Bcf of working gas storage, with six-turn injection and withdrawal capacity. Pending regulatory approval, the first cavern is projected to go into operation by mid-2011, with the other two caverns projected to be operational by 2012 and 2014. Based on market demand, four additional storage caverns could potentially be developed.

Risk Management Activities

We conduct risk management activities through both our natural gas distribution and natural gas marketing segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. In our natural gas marketing segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial derivatives, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our fair value hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the derivatives being treated as mark-to-market instruments through earnings. In addition, natural gas inventory would be reflected on the balance sheet at the lower of cost or market instead of at fair value.

We record our derivatives as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying derivative. Substantially all of our derivative financial instruments are valued using external market quotes and indices. The following tables show the components of the change in the fair value of our natural gas distribution and natural gas marketing commodity derivative contracts for the three and nine months ended June 30, 2008 and 2007:


	Three Months Ended					Three Months Ended
	June 30, 2008					June 30, 2007
	Natural Gas		Natural Gas			Natural Gas			Natural Gas
	Distribution		Marketing			Distribution			Marketing
	(In thousands)

Fair value of contracts at beginning of period	$	9,505	$	(22,975	)	$	3,802		$	(24,994	)
Contracts realized/settled		339		30,185			(144	)		15,994
Fair value of new contracts		5,675		—			(5,797	)		—
Other changes in value		21,847		(50,182	)		(5,385	)		24,898

Fair value of contracts at end of period	$	37,366	$	(42,972	)	$	(7,524	)	$	15,898


	Nine Months Ended						Nine Months Ended
	June 30, 2008						June 30, 2007
	Natural Gas			Natural Gas			Natural Gas			Natural Gas
	Distribution			Marketing			Distribution			Marketing
	(In thousands)

Fair value of contracts at beginning of period	$	(21,053	)	$	26,808		$	(27,209	)	$	15,003
Contracts realized/settled		(26,971	)		(11,071	)		(27,662	)		(10,593	)
Fair value of new contracts		5,395			—			(7,058	)		—
Other changes in value		79,995			(58,709	)		54,405			11,488

Fair value of contracts at end of period	$	37,366		$	(42,972	)	$	(7,524	)	$	15,898

The fair value of our natural gas distribution and natural gas marketing derivative contracts at June 30, 2008, is segregated below by time period and fair value source:


	Fair Value of Contracts at June 30, 2008
	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	$	(7,511	)	$	2,373		$	—	$	—	$	(5,138	)
Prices based on models and other valuation methods		(275	)		(193	)		—		—		(468	)

Total Fair Value	$	(7,786	)	$	2,180		$	—	$	—	$	(5,606	)

Pension and Postretirement Benefits Obligations

For the nine months ended June 30, 2008 and 2007, our total net periodic pension and other benefits cost was $35.9 million and $36.4 million. These costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Our total net periodic pension and other benefit costs remained relatively unchanged during the current-year period when compared with the prior-year period as the assumptions we made during our annual pension plan valuation completed June 30, 2007 were consistent with the prior year. The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. At our June 30, 2007 measurement date, the interest rates were consistent with rates at our prior-year measurement date, which resulted in no change to our 6.30 percent discount rate used to determine our fiscal 2008 net periodic and post-retirement cost. In addition, our expected return on our pension plan assets remained constant at 8.25 percent.

We are currently in the process of completing our fiscal 2008 pension plan valuation. Based upon market conditions as of the June 30, 2008 valuation date, we expect no significant increase in our fiscal 2009 net periodic pension cost.

During the nine months ended June 30, 2008, we contributed $6.7 million to our other postretirement plans, and we expect to contribute a total of approximately $10 million to these plans during fiscal 2008.

OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage, natural gas marketing and pipeline, storage and other segments for the three and nine-month periods ended June 30, 2008 and 2007.

Natural Gas Distribution Sales and Statistical Data


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2008			2007			2008			2007

METERS IN SERVICE, end of period
Residential		2,922,415			2,900,716			2,922,415			2,900,716
Commercial		271,542			274,273			271,542			274,273
Industrial		2,265			2,739			2,265			2,739
Public authority and other		9,234			16,576			9,234			16,576

Total meters		3,205,456			3,194,304			3,205,456			3,194,304

INVENTORY STORAGE BALANCE — Bcf		41.7			43.9			41.7			43.9
HEATING DEGREE DAYS⁽¹⁾
Actual (weighted average)		174			163			2,810			2,873
Percent of normal		102	%		98	%		100	%		101	%
SALES VOLUMES — MMcf⁽²⁾
Gas sales volumes
Residential		18,584			21,421			151,549			155,021
Commercial		15,199			16,672			82,325			83,231
Industrial		4,687			5,248			17,899			18,551
Public authority and other		2,887			1,911			9,919			8,705

Total gas sales volumes		41,357			45,252			261,692			265,508
Transportation volumes		33,211			30,431			109,002			105,125

Total throughput		74,568			75,683			370,694			370,633

OPERATING REVENUES (000’s)⁽²⁾
Gas sales revenues
Residential	$	352,893		$	294,756		$	1,878,855		$	1,795,124
Commercial		213,594			170,425			903,771			855,468
Industrial		53,843			44,345			167,154			162,621
Public authority and other		33,135			18,193			100,983			84,550

Total gas sales revenues		653,465			527,719			3,050,763			2,897,763
Transportation revenues		14,163			12,040			46,954			46,997
Other gas revenues		9,011			8,492			28,955			28,768

Total operating revenues	$	676,639		$	548,251		$	3,126,672		$	2,973,528

Average transportation revenue per Mcf	$	0.43		$	0.40		$	0.43		$	0.45
Average cost of gas per Mcf sold	$	11.53		$	7.90		$	8.77		$	8.19

See footnotes following these tables.

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


	Three Months Ended				Nine Months Ended
	June 30				June 30
	2008		2007		2008		2007

CUSTOMERS, end of period
Industrial		702		700		702		700
Municipal		56		64		56		64
Other		503		424		503		424

Total		1,261		1,188		1,261		1,188

INVENTORY STORAGE BALANCE — Bcf
Natural gas marketing		18.8		25.1		18.8		25.1
Pipeline, storage and other		1.2		1.9		1.2		1.9

Total		20.0		27.0		20.0		27.0

REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf⁽²⁾		181,112		157,825		593,452		528,144
NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽²⁾		103,403		104,783		348,789		306,931
OPERATING REVENUES (000’s)⁽²⁾
Regulated transmission and storage	$	46,286	$	36,707	$	142,772	$	122,647
Natural gas marketing		1,189,722		854,167		3,159,092		2,360,902
Pipeline, storage and other		3,880		2,073		20,629		27,483

Total operating revenues	$	1,239,888	$	892,947	$	3,322,493	$	2,511,032

Notes to preceding tables:


⁽¹⁾		A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Generally, normal degree days are based on30-year average National Weather Service data for selected locations. For service areas that have weather normalized operations, normal degree days are used instead of actual degree days in computing the total number of heating degree days.

⁽²⁾		Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

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 unaudited condensed consolidated financial statements.


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report onForm 10-K for the year ended September 30, 2007. During the nine months ended June 30, 2008, there were no material changes in our quantitative and qualitative disclosures about market risk.


Item 4.	*Controls and Procedures*

As indicated in the certifications in Exhibit 31 of this report, the Company’s Chief Executive Officer and Chief Financial Officer have evaluated the Company’s disclosure controls and procedures as of June 30, 2008. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are effective in ensuring that material information required to be disclosed by the Company in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. In addition, there were no changes during the Company’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.	*Legal Proceedings*

During the nine months ended June 30, 2008, except as noted in Note 8 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and environmental-related matters that were disclosed in Note 13 to our Annual Report onForm 10-K for the year ended September 30, 2007. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.


Item 6.	*Exhibits*

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atmos Energy Corporation

(Registrant)


	By:	/s/ John P. Reddy

John P. Reddy

Senior Vice President and Chief Financial Officer

(Duly authorized signatory)

Date: August 6, 2008

EXHIBITS INDEX
Item 6(a)


Exhibit			Page
Number		Description	Number

	12	Computation of ratio of earnings to fixed charges
	15	Letter regarding unaudited interim financial information
	31	Rule 13a-14(a)/15d-14(a) Certifications
	32	Section 1350 Certifications*


*		These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report onForm 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

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Atmos Energy (ATO) 10-Q2008 Q3 Quarterly report

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