Edgar Filing: ATMOS ENERGY CORP

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2009
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		(IRS employer
incorporation or organization)		identification no.)

Three Lincoln Centre, Suite 1800		75240
5430 LBJ Freeway, Dallas, Texas		(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 has submitted electronically and posted on its Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).* Yes o No o

* The registrant has not yet been phased into the interactive data requirements.

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” in Rule 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 in Rule 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 April 22, 2009.


Class		Shares Outstanding

No Par Value		92,008,920

TABLE OF CONTENTS


GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits
SIGNATURE
EXHIBITS INDEX Item 6
EX-12
EX-15
EX-31
EX-32

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation
AEH		Atmos Energy Holdings, Inc.
AEM		Atmos Energy Marketing, LLC
AOCI		Accumulated other comprehensive income
APS		Atmos Pipeline and Storage, LLC
Bcf		Billion cubic feet
FASB		Financial Accounting Standards Board
Fitch		Fitch Ratings, Ltd.
FSP		FASB Staff Position
GRIP		Gas Reliability Infrastructure Program
LPSC		Louisiana Public Service Commission
Mcf		Thousand cubic feet
MMcf		Million cubic feet
MPSC		Mississippi Public Service Commission
Moody’s		Moody’s Investors Services, Inc.
NYMEX		New York Mercantile Exchange, Inc.
PPA		Pension Protection Act of 2006
RRC		Railroad Commission of Texas
RRM		Rate Review Mechanism
S&P		Standard & Poor’s Corporation
SEC		United States Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
WNA		Weather Normalization Adjustment

PART I. FINANCIAL INFORMATION


Item 1.	*Financial Statements*

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,			September 30,
	2009			2008
	(Unaudited)
	(In thousands, except
	share data)

ASSETS
Property, plant and equipment	$	5,873,028		$	5,730,156
Less accumulated depreciation and amortization		1,609,836			1,593,297

Net property, plant and equipment		4,263,192			4,136,859
Current assets
Cash and cash equivalents		482,085			46,717
Accounts receivable, net		531,749			477,151
Gas stored underground		327,288			576,617
Other current assets		137,433			184,619

Total current assets		1,478,555			1,285,104
Goodwill and intangible assets		738,772			739,086
Deferred charges and other assets		205,242			225,650

	$	6,685,761		$	6,386,699

CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding:
March 31, 2009 — 91,947,614 shares;
September 30, 2008 — 90,814,683 shares	$	460		$	454
Additional paid-in capital		1,768,307			1,744,384
Retained earnings		480,355			343,601
Accumulated other comprehensive loss		(70,628	)		(35,947	)

Shareholders’ equity		2,178,494			2,052,492
Long-term debt		2,169,141			2,119,792

Total capitalization		4,347,635			4,172,284
Current liabilities
Accounts payable and accrued liabilities		472,078			395,388
Other current liabilities		413,764			460,372
Short-term debt		—			350,542
Current maturities of long-term debt		400,225			785

Total current liabilities		1,286,067			1,207,087
Deferred income taxes		466,868			441,302
Regulatory cost of removal obligation		313,486			298,645
Deferred credits and other liabilities		271,705			267,381

	$	6,685,761		$	6,386,699

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended
	March 31
	2009			2008
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	1,230,420		$	1,521,856
Regulated transmission and storage segment		59,234			51,440
Natural gas marketing segment		708,658			1,128,653
Pipeline, storage and other segment		12,272			10,022
Intersegment eliminations		(189,178	)		(227,986	)

		1,821,406			2,483,985
Purchased gas cost
Natural gas distribution segment		863,340			1,164,332
Regulated transmission and storage segment		—			—
Natural gas marketing segment		685,114			1,112,321
Pipeline, storage and other segment		1,656			338
Intersegment eliminations		(188,755	)		(227,400	)

		1,361,355			2,049,591

Gross profit		460,051			434,394
Operating expenses
Operation and maintenance		121,740			120,053
Depreciation and amortization		53,450			48,790
Taxes, other than income		58,314			54,408

Total operating expenses		233,504			223,251

Operating income		226,547			211,143
Miscellaneous income (expense)		(1,565	)		1,467
Interest charges		35,533			33,516

Income before income taxes		189,449			179,094
Income tax expense		60,446			67,560

Net income	$	129,003		$	111,534

Basic net income per share	$	1.42		$	1.25

Diluted net income per share	$	1.41		$	1.24

Cash dividends per share	$	0.330		$	0.325

Weighted average shares outstanding:
Basic		90,895			89,314

Diluted		91,567			89,990

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Six Months Ended
	March 31
	2009			2008
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	2,286,388		$	2,450,033
Regulated transmission and storage segment		113,916			96,486
Natural gas marketing segment		1,496,153			1,969,370
Pipeline, storage and other segment		28,720			16,749
Intersegment eliminations		(387,439	)		(391,143	)

		3,537,738			4,141,495
Purchased gas cost
Natural gas distribution segment		1,620,924			1,819,309
Regulated transmission and storage segment		—			—
Natural gas marketing segment		1,442,586			1,907,075
Pipeline, storage and other segment		5,559			1,067
Intersegment eliminations		(386,594	)		(389,988	)

		2,682,475			3,337,463

Gross profit		855,263			804,032
Operating expenses
Operation and maintenance		256,495			241,242
Depreciation and amortization		106,576			97,303
Taxes, other than income		102,451			95,835

Total operating expenses		465,522			434,380

Operating income		389,741			369,652
Miscellaneous income (expense)		(1,866	)		1,374
Interest charges		74,524			70,333

Income before income taxes		313,351			300,693
Income tax expense		108,385			115,356

Net income	$	204,966		$	185,337

Basic net income per share	$	2.26		$	2.08

Diluted net income per share	$	2.24		$	2.06

Cash dividends per share	$	0.66		$	0.65

Weighted average shares outstanding:
Basic		90,637			89,133

Diluted		91,311			89,817

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended
	March 31
	2009			2008
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities
Net income	$	204,966		$	185,337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		106,576			97,303
Charged to other accounts		21			67
Deferred income taxes		97,892			72,277
Other		13,634			6,853
Net assets/liabilities from risk management activities		5,810			(22,667	)
Net change in operating assets and liabilities		185,723			140,022

Net cash provided by operating activities		614,622			479,192
Cash Flows From Investing Activities
Capital expenditures		(221,330	)		(198,722	)
Other, net		(3,925	)		(3,132	)

Net cash used in investing activities		(225,255	)		(201,854	)
Cash Flows From Financing Activities
Net decrease in short-term debt		(353,468	)		(150,582	)
Net proceeds from debt offering		446,188			—
Settlement of Treasury lock agreement		1,938			—
Repayment of long-term debt		(625	)		(2,253	)
Cash dividends paid		(60,446	)		(58,431	)
Issuance of common stock		12,414			12,839

Net cash provided by (used in) financing activities		46,001			(198,427	)

Net increase in cash and cash equivalents		435,368			78,911
Cash and cash equivalents at beginning of period		46,717			60,725

Cash and cash equivalents at end of period	$	482,085		$	139,636

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2009


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 regulation and/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 conducted through 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 Southeast and Midwest 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 financial instruments.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS owns and operates a 21 mile pipeline located in New Orleans, Louisiana. This pipeline is used primarily to aggregate gas supply for our regulated natural gas distribution division in Louisiana and for AEM, but also provides limited third party transportation services.

APS also engages in asset optimization activities whereby it seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls. Certain of these arrangements are asset management plans with regulated affiliates of the Company which have been approved by applicable state regulatory commissions. Generally, these asset management plans require APS to share with our regulated customers a portion of the profits earned from these arrangements.

Further, APS owns or has an interest in underground storage fields in Kentucky and Louisiana that are used to reduce the need of our natural gas distribution divisions to contract for pipeline capacity to meet customer demand during peak periods. Finally, APS manages our natural gas gathering operations, which were limited in nature as of March 31, 2009.


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 to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, 2009 are not indicative of our results of operations for the full 2009 fiscal year, which ends September 30, 2009.

Significant accounting policies

Our accounting policies are described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, and there were no changes to those policies. However, during the six months ended March 31, 2009, we recognized a non-recurring $8.3 million increase in gross profit associated with a one-time update to our estimate for gas delivered to customers but not yet billed, resulting from base rate changes in several jurisdictions.

During the second quarter of fiscal 2009, we updated the tax rates used to record deferred taxes. The one-time tax benefit resulted in a favorable impact to net income of $11.3 million.

Additionally, during the second quarter of fiscal 2009, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

Effective October 1, 2008, the Company adopted Statement of Financial Accounting Standards (SFAS) 157, Fair Value Measurements, the measurement date requirements of SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115, SFAS 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 and FASB Staff Position (FSP) FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. Except for the adoption of these accounting pronouncements, which are further discussed below, there were no significant changes to our accounting policies during the six months ended March 31, 2009.

SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosure on fair value measurements required under other accounting pronouncements but does not change existing

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

guidance as to whether or not an instrument is carried at fair value. The adoption of this standard did not materially impact our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 4.

Effective October 1, 2008, the Company adopted the measurement date requirements of SFAS 158 using the remeasurement approach. Under this approach, the Company remeasured its projected benefit obligation, fair value of plan assets and its fiscal 2009 net periodic cost. In accordance with the transition rules of SFAS 158, the impact of changing the measurement date from June 30, 2008 to September 30, 2008 decreased retained earnings by $7.8 million, net of tax, decreased the unrecognized actuarial loss by $9.0 million and increased our postretirement liabilities by $3.5 million during the first quarter of fiscal 2009.

SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of the standard is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis. The fair value option is irrevocable, unless a new election date occurs. The adoption of this standard did not impact our financial position, results of operations or cash flows.

SFAS 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement requires specific disclosures regarding how and why an entity uses derivative instruments; the accounting for derivative instruments and related hedged items; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Since SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard did not have an impact on our financial position, results of operations or cash flows. The new disclosures required by this standard are presented in Note 3.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP requires companies to disclose the fair value of financial instruments for which it is practicable to estimate the value and the methods and significant assumptions used to estimate the fair value. The disclosure is required for interim and annual reports. The disclosure requirements of this FSP are presented in Note 4.

Regulatory assets and liabilities

We record certain costs as regulatory assets in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and 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 March 31, 2009 and September 30, 2008 included the following:


	March 31,		September 30,
	2009		2008
	(In thousands)

Regulatory assets:
Pension and postretirement benefit costs	$	89,244	$	100,563
Merger and integration costs, net		7,374		7,586
Deferred gas costs		58,660		55,103
Environmental costs		741		980
Rate case costs		9,144		12,885
Deferred franchise fees		597		651
Deferred income taxes, net		343		343
Other		7,846		8,120

	$	173,949	$	186,231

Regulatory liabilities:
Deferred gas costs	$	61,177	$	76,979
Regulatory cost of removal obligation		329,120		317,273
Other		5,499		5,639

	$	395,796	$	399,891

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 six-month periods ended March 31, 2009 and 2008:


	Three Months Ended March 31						Six Months Ended March 31
	2009			2008			2009			2008
	(In thousands)

Net income	$	129,003		$	111,534		$	204,966		$	185,337
Unrealized holding losses on investments, net of tax benefit of $429 and $1,385 for the three months ended March 31, 2009 and 2008 and of $3,759 and $671 for the six months ended March 31, 2009 and 2008		(862	)		(2,262	)		(6,295	)		(1,097	)
Other than temporary impairment of investments, net of tax expense of $790 for the six months ended March 31, 2009		—			—			1,288			—
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $1,353 and $482 for the three months ended March 31, 2009 and 2008 and $1,835 and $964 for the six months ended March 31, 2009 and 2008		1,854			787			2,641			1,574
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $(7,524) and $2,260 for the three months ended March 31, 2009 and 2008 and $(21,341) and $7,197 for the six months ended March 31, 2009 and 2008		(9,771	)		3,690			(32,315	)		11,743

Comprehensive income	$	120,224		$	113,749		$	170,285		$	197,557

Accumulated other comprehensive loss, net of tax, as of March 31, 2009 and September 30, 2008 consisted of the following unrealized gains (losses):


	March 31,			September 30,
	2009			2008
	(In thousands)

Accumulated other comprehensive loss:
Unrealized holding gains (losses) on investments	$	(4,097	)	$	910
Treasury lock agreements		(8,463	)		(11,104	)
Cash flow hedges		(58,068	)		(25,753	)

	$	(70,628	)	$	(35,947	)


3.	Financial Instruments

We currently use financial instruments to mitigate commodity price risk. Additionally, we periodically utilize financial instruments to manage interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. Currently, we utilize financial instruments in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. However, our pipeline, storage

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.

Regulated Commodity Risk Management Activities

In our natural gas distribution segment, our customers are exposed to the effect of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. If the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2008-2009 heating season, in the jurisdictions where we are permitted to utilize financial instruments, we anticipated hedging approximately 29 percent, or 25.5 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.

The costs associated with and the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue 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 instruments.

Nonregulated Commodity Risk Management Activities

Our natural gas marketing segment, through AEM, aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request.

We also perform asset optimization activities in both our natural gas marketing segment and pipeline, storage and other segment. Through asset optimization activities, we 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. Over time, gains and losses on the sale of storage gas

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

inventory will be offset by gains and losses on the financial instruments, resulting in the realization of the economic gross profit margin we anticipated at the time we structured the original transaction.

As a result of these activities, our nonregulated operations are exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Futures contracts provide the right to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.

We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our natural gas marketing segment associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 46 months. The effective portion of the unrealized gains and losses arising from the use of cash flow hedges is recorded as a component of accumulated other comprehensive income (AOCI) on the balance sheet. Amounts associated with cash flow hedges recognized in the income statement include (i) the amount of unrealized gain or loss that has been reclassified from AOCI when the hedged volumes are sold and (ii) the amount of ineffectiveness associated with these hedges in the period the ineffectiveness arises.

We use financial instruments, designated as fair value hedges, to hedge the exposure to changes in the fair value of our natural gas inventory used in our asset optimization activities in our natural gas marketing and pipeline, storage and other segments. Therefore, gains and losses arising from these financial instruments should offset the changes in the fair value of the hedged item to the extent the hedging relationship is effective. Ineffectiveness is recognized in the income statement in the period the ineffectiveness arises.

Also, in our natural gas marketing segment, we use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges pursuant to SFAS 133, Accounting for Derivative Instruments and Hedging Activities.

Our nonregulated risk management activities are controlled through various risk management policies and procedures. Our Audit Committee has oversight responsibility for our nonregulated risk management limits and policies. Our risk management committee, comprised of corporate and business unit officers, is responsible for establishing and enforcing our nonregulated risk management policies and procedures.

Under our risk management policies, we seek to match our financial instrument positions to our physical storage positions as well as our expected current and future sales and purchase obligations to maintain no open positions at the end of each trading day. The determination of our net open position as of any day, however, requires us to make assumptions as to future circumstances, including the use of gas by our customers in relation to our anticipated storage and market positions. Because the price risk associated with any net open position at the end of each day may increase if the assumptions are not realized, we review these assumptions as part of our daily monitoring activities. We can also be affected by intraday fluctuations of gas prices, since the price of natural gas purchased or sold for future delivery earlier in the day may not be hedged until later in the day. At times, limited net open positions related to our existing and anticipated commitments may occur. At the close of business on March 31, 2009, AEH had net open positions (including existing storage) of less than 0.1 Bcf.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Rate Risk Management Activities

In March 2009, we entered into a Treasury lock agreement to fix the Treasury yield component of the interest cost associated with our $450 million 8.50% senior notes (the Senior Notes Offering), which was completed on March 26, 2009. The Senior Notes Offering is discussed in Note 5. We designated this Treasury lock as a cash flow hedge of an anticipated transaction. This Treasury lock was settled on March 23, 2009 with the receipt of $1.9 million from the counterparty due to an increase in the 10 year Treasury rates between inception of the Treasury lock and settlement. Because the Treasury lock was effective, the net $1.2 million unrealized gain was recorded as a component of accumulated other comprehensive income and will be recognized over the 10 year life of the senior notes.

In prior years, we similarly managed interest rate risk by entering into Treasury lock agreements to fix the Treasury yield component of the interest cost associated with anticipated financings. These Treasury locks were settled at various times at a net loss. These realized gains and losses were recorded as a component of accumulated other comprehensive income (loss) and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these Treasury locks extend through fiscal 2035. However, the majority of the remaining amounts of these Treasury locks will be recognized as a component of interest expense through fiscal 2019.

Quantitative Disclosures Related to Financial Instruments

The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.

As of March 31, 2009, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of March 31, 2009, we had net long/(short) commodity contracts outstanding in the following quantities:


		Natural		Natural			Pipeline,
	Hedge	Gas		Gas			Storage
Contract Type	Designation	Distribution		Marketing			and Other
		Quantity (MMcf)

Commodity contracts	Fair Value		—		(19,052	)		(1,410	)
	Cash Flow		—		38,822			(1,905	)
	Not designated		7,727		109,450			(688	)

			7,727		129,220			(4,003	)

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of March 31, 2009 and September 30, 2008. As required by SFAS 161, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include $79.1 million and $56.6 million of cash held on deposit in margin accounts as of March 31, 2009 and September 30, 2008 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.


		Natural			Natural
		Gas			Gas
	Balance Sheet Location	Distribution			Marketing⁽¹⁾			Total
		(In thousands)

March 31, 2009:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	73,163		$	73,163
Noncurrent commodity contracts	Deferred charges and other assets		—			8,018			8,018
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(116,698	)		(116,698	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(1,712	)		(1,712	)

Total			—			(37,229	)		(37,229	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		676			40,262			40,938
Noncurrent commodity contracts	Deferred charges and other assets		—			5,108			5,108
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(22,535	)		(39,098	)		(61,633	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(4	)		(1,689	)		(1,693	)

Total			(21,863	)		4,583			(17,280	)

Total Financial Instruments		$	(21,863	)	$	(32,646	)	$	(54,509	)


⁽¹⁾		Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.


		Natural			Natural
		Gas			Gas
	Balance Sheet Location	Distribution			Marketing⁽¹⁾			Total
		(In thousands)

September 30, 2008:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	101,191		$	101,191
Noncurrent commodity contracts	Deferred charges and other assets		—			4,984			4,984
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(89,397	)		(89,397	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(206	)		(206	)

Total			—			16,572			16,572
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		—			20,010			20,010
Noncurrent commodity contracts	Deferred charges and other assets		—			1,093			1,093
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(58,566	)		(20,145	)		(78,711	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(5,111	)		(988	)		(6,099	)

Total			(63,677	)		(30	)		(63,707	)

Total Financial Instruments		$	(63,677	)	$	16,542		$	(47,135	)


⁽¹⁾		Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Impact of Financial Instruments on the Income Statement

The following tables present the impact that financial instruments had on our condensed consolidated income statement, by operating segment, as applicable, for the three and six months ended March 31, 2009 and 2008.

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. For the three months ended March 31, 2009 and 2008 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $4.2 million and $6.5 million. For the six months ended March 31, 2009 and 2008 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $24.6 million and $45.2 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below. Although these unrealized gains and losses are currently recorded in our income statement, they are not necessarily indicative of the economic gross profit we anticipate realizing when the underlying physical and financial transactions are settled.

Fair Value Hedges

The impact of commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and six months ended March 31, 2009 and 2008 is presented below.


	Three Months Ended March 31, 2009
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
	(In thousands)

Commodity contracts	$	19,870		$	2,105		$	21,975
Fair value adjustment for natural gas inventory designated as the hedged item		(18,562	)		(437	)		(18,999	)

Total impact on revenue	$	1,308		$	1,668		$	2,976

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	2,327		$	—		$	2,327
Timing ineffectiveness		(1,019	)		1,668			649

	$	1,308		$	1,668		$	2,976

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended March 31, 2008
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
	(In thousands)

Commodity contracts	$	(33,448	)	$	(735	)	$	(34,183	)
Fair value adjustment for natural gas inventory designated as the hedged item		39,922			1,352			41,274

Total impact on revenue	$	6,474		$	617		$	7,091

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(739	)	$	—		$	(739	)
Timing ineffectiveness		7,213			617			7,830

	$	6,474		$	617		$	7,091


	Six Months Ended March 31, 2009
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
	(In thousands)

Commodity contracts	$	45,553		$	6,044		$	51,597
Fair value adjustment for natural gas inventory designated as the hedged item		(30,422	)		(1,990	)		(32,412	)

Total impact on revenue	$	15,131		$	4,054		$	19,185

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	4,279		$	—		$	4,279
Timing ineffectiveness		10,852			4,054			14,906

	$	15,131		$	4,054		$	19,185


	Six Months Ended March 31, 2008
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other		Consolidated
	(In thousands)

Commodity contracts	$	(16,221	)	$	1,387	$	(14,834	)
Fair value adjustment for natural gas inventory designated as the hedged item		57,523			2,410		59,933

Total impact on revenue	$	41,302		$	3,797	$	45,099

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	1,217		$	—	$	1,217
Timing ineffectiveness		40,085			3,797		43,882

	$	41,302		$	3,797	$	45,099

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises 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. As the commodity contract nears the settlement date, spot to forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on revenue.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and six months ended March 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.


	Three Months Ended March 31, 2009
	Natural			Natural			Pipeline,
	Gas			Gas			Storage
	Distribution			Marketing			and Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(48,585	)	$	16,170	$	(32,415	)
Gain arising from ineffective portion of commodity contracts		—			1,180			—		1,180

Total impact on revenue		—			(47,405	)		16,170		(31,235	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(1,269	)		—			—		(1,269	)

Total Impact from Cash Flow Hedges	$	(1,269	)	$	(47,405	)	$	16,170	$	(32,504	)


	Three Months Ended March 31, 2008
	Natural			Natural			Pipeline,
	Gas			Gas			Storage
	Distribution			Marketing			and Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(8,040	)	$	13,492	$	5,452
Loss arising from ineffective portion of commodity contracts		—			(634	)		—		(634	)

Total impact on revenue		—			(8,674	)		13,492		4,818
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(1,269	)		—			—		(1,269	)

Total Impact from Cash Flow Hedges	$	(1,269	)	$	(8,674	)	$	13,492	$	3,549


	Six Months Ended March 31, 2009
	Natural			Natural			Pipeline,
	Gas			Gas			Storage
	Distribution			Marketing			and Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(76,829	)	$	24,139	$	(52,690	)
Gain arising from ineffective portion of commodity contracts		—			5,372			—		5,372

Total impact on revenue		—			(71,457	)		24,139		(47,318	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(2,538	)		—			—		(2,538	)

Total Impact from Cash Flow Hedges	$	(2,538	)	$	(71,457	)	$	24,139	$	(49,856	)

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Six Months Ended March 31, 2008
	Natural			Natural			Pipeline,
	Gas			Gas			Storage
	Distribution			Marketing			and Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(17,294	)	$	13,916	$	(3,378	)
Gain arising from ineffective portion of commodity contracts		—			126			—		126

Total impact on revenue		—			(17,168	)		13,916		(3,252	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(2,538	)		—			—		(2,538	)

Total Impact from Cash Flow Hedges	$	(2,538	)	$	(17,168	)	$	13,916	$	(5,790	)

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 six months ended March 31, 2009 and 2008. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the income statement as incurred.


	Three Months Ended						Six Months Ended
	March 31						March 31
	2009			2008			2009			2008
	(In thousands)

Increase (decrease) in fair value:
Treasury lock agreements	$	1,221		$	—		$	1,221		$	—
Forward commodity contracts		(29,544	)		7,070			(64,659	)		9,649
Recognition of (gains) losses in earnings due to settlements:
Treasury lock agreements		633			787			1,420			1,574
Forward commodity contracts		19,773			(3,380	)		32,344			2,094

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	(7,917	)	$	4,477		$	(29,674	)	$	13,317


⁽¹⁾		Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.

The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of March 31, 2009:


	Treasury
	Lock			Commodity
	Agreements			Contracts			Total
	(In thousands)

Next twelve months	$	(2,426	)	$	(54,233	)	$	(56,659	)
Thereafter		(6,037	)		(3,835	)		(9,872	)

Total⁽¹⁾	$	(8,463	)	$	(58,068	)	$	(66,531	)


⁽¹⁾		Utilizing an income tax rate of approximately 37 percent comprised of the effective rates in each taxing jurisdiction.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three and six months ended March 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact to our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.


	Three Months Ended March 31					Six Months Ended March 31
	2009		2008			2009		2008
	(In thousands)

Natural gas marketing commodity contracts	$	10,593	$	(14,120	)	$	6,761	$	(13,794	)
Pipeline, storage and other commodity contracts		183		(245	)		100		(889	)

Total impact on revenue	$	10,776	$	(14,365	)	$	6,861	$	(14,683	)


4.	Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) and expands disclosures about fair value measurements. This Statement does not require any new fair value measurements; rather it provides guidance on how to perform fair value measurements as required or permitted under previous accounting pronouncements.

We prospectively adopted the provisions of SFAS 157 on October 1, 2008 for most of the financial assets and liabilities recorded on our balance sheet at fair value. Adoption of this statement for these assets and liabilities did not have a material impact on our financial position, results of operations or cash flows.

In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No. 157, which provided a one-year deferral of SFAS 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. Under this partial deferral, SFAS 157 will not be effective until October 1, 2009 for fair value measurements for the following:


	•	Asset retirement obligations

	•	Most nonfinancial assets and liabilities that may be acquired in a business combination

	•	Impairment analyses performed for nonfinancial assets

We believe the adoption of SFAS 157 for the reporting of these nonfinancial assets and liabilities will not have a material impact on our financial position, results of operations or cash flows.

In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, which clarified the application of SFAS 157 in inactive markets. This FSP did not impact our financial position, results of operations or cash flows.

SFAS 157 also applies to the valuation of our pension and post-retirement plan assets. The adoption of this standard did not affect these valuations because SFAS 157 specifically excluded pension and post-

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

retirement assets from its prescribed disclosure provisions. Accordingly, these plan assets are not included in the tabular disclosures below. However, in December 2008, the FASB issued FSP FAS 132(R)-1 — Employers’ Disclosures about Postretirement Benefit Plan Assets, which will, among other things, require disclosure about fair value measurements similar to those required by SFAS 157. This FSP will impact our annual disclosure requirements beginning in fiscal 2010.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP requires companies to disclose the fair value of financial instruments for which it is practicable to estimate the value and the methods and significant assumptions used to estimate the fair value. We have adopted the disclosure requirements of this FSP, which are presented below.

Determining Fair Value

SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.

Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value. Within our nonregulated operations, we utilize a mid-market pricing convention (the mid-point between the bid and ask prices) as a practical expedient for determining fair value measurement, as permitted under SFAS 157. Values derived from these sources reflect the market in which transactions involving these financial instruments are executed. We utilize models and other valuation methods to determine fair value when external sources are not available. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then-current market conditions. We believe the market prices and models used to value these assets and liabilities represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the assets and liabilities.

Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. Recent adverse developments in the global financial and credit markets have made it more difficult and more expensive for companies to access the short-term capital markets, which may negatively impact the creditworthiness of our counterparties. A continued tightening of the credit markets could cause more of our counterparties to fail to perform. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.

SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements consist primarily of exchange-traded financial instruments, gas stored underground that has been designated as the hedged item in a fair value hedge and our available-for-sale securities.

Level 2 — Pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable.

Level 3 — Generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. Currently, we have no assets or liabilities recorded at fair value that would qualify for Level 3 reporting.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. The following table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009. As required under SFAS 157, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.


	Quoted		Significant		Significant
	Prices in		Other		Other
	Active		Observable		Unobservable		Netting and
	Markets		Inputs		Inputs		Cash			March 31,
	(Level 1)		(Level 2)		(Level 3)		Collateral⁽¹⁾			2009
	(In thousands)

Assets:
Financial instruments
Natural gas distribution segment	$	—	$	676	$	—	$	—		$	676
Natural gas marketing segment		45,770		80,564		—		(75,558	)		50,776

Total financial instruments		45,770		81,240		—		(75,558	)		51,452
Hedged portion of gas stored underground
Natural gas marketing segment		62,912		—		—		—			62,912
Pipeline, storage and other segment⁽²⁾		3,656		—		—		—			3,656

Total gas stored underground		66,568		—		—		—			66,568
Available-for-sale securities		26,605		—		—		—			26,605

Total assets	$	138,943	$	81,240	$	—	$	(75,558	)	$	144,625

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	22,539	$	—	$	—		$	22,539
Natural gas marketing segment		117,413		41,567		—		(154,656	)		4,324

Total liabilities	$	117,413	$	64,106	$	—	$	(154,656	)	$	26,863


⁽¹⁾		This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and FSP FIN 39-1. In addition, as of March 31, 2009, we had $79.1 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $71.6 million was used to offset financial instruments in a liability position. The remaining $7.5 million has been reflected as a financial instrument asset.

⁽²⁾		Our pipeline, storage and other segment uses financial instruments acquired from AEM on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment; however, the underlying hedged item is reported in the pipeline, storage and other segment.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other Fair Value Measures

In addition to the financial instruments above, we have several nonfinancial assets and liabilities subject to fair value measures. These assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable, debt, asset retirement obligations and pension and post-retirement plan assets. As noted above, fair value disclosures for asset retirement obligations and pension and post-retirement plan assets are not currently effective for us. We record cash and cash equivalents, accounts receivable, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities. The fair value of our debt is determined using a discounted cash flow analysis based upon borrowing rates currently available to us, the remaining average maturities and our credit rating. The following table presents the carrying value and fair value of our debt as of March 31, 2009:


	March 31, 2009
	(In thousands)

Carrying Amount	$	2,572,987
Fair Value	$	2,166,454

The fair value as of March 31, 2009 was calculated utilizing discount rates ranging from 6.6 percent to 9.6 percent, remaining average maturities ranging from one to 26 years, and a credit adjustment of 6.0 percent.


5.	Debt

Long-term debt

Long-term debt at March 31, 2009 and September 30, 2008 consisted of the following:


	March 31,			September 30,
	2009			2008
	(In thousands)

Unsecured 4.00% Senior Notes, due April 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 8.50% Senior Notes, due 2019		450,000			—
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
Other term notes due in installments through 2013		684			1,309

Total long-term debt		2,572,987			2,123,612
Less:
Original issue discount on unsecured senior notes and debentures		(3,621	)		(3,035	)
Current maturities		(400,225	)		(785	)

	$	2,169,141		$	2,119,792

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On March 26, 2009, we closed our Senior Notes Offering. The effective interest rate on these notes is 8.69 percent, after giving effect to the settlement of the $450 million treasury lock discussed in Note 3. Most of the net proceeds of approximately $446 million were used to redeem our $400 million 4.00% unsecured senior notes, which, on March 30, 2009, were called for redemption on April 30, 2009, prior to their October 2009 maturity. In connection with the repayment of the $400 million 4.00% unsecured senior notes, we paid a $6.6 million call premium in accordance with the terms of the senior notes and accrued interest of approximately $0.6 million. The remaining net proceeds will be used for general corporate purposes.

Short-term debt

Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings reach their highest levels in the winter months.

We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. At March 31, 2009, there was no short-term debt outstanding. At September 30, 2008, there was $350.5 million of short-term debt outstanding, comprised of $330.5 million outstanding under our bank credit facilities and $20.0 million outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.

Regulated Operations

We fund our regulated operations as needed primarily through a $566.7 million commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $800 million of working capital funding. The first facility is a five-year unsecured facility, expiring December 2011, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At the time this credit facility was established, borrowings under this facility were limited to $600 million. However, in September 2008, the limit on borrowings was effectively reduced to $566.7 million after one lender with a 5.55% share of the commitments ceased funding under the facility. On March 30, 2009, the credit facility was amended to reflect this reduction. At March 31, 2009, there were no borrowings under this facility and $566.7 million was available.

The second facility is a $212.5 million unsecured 364-day facility expiring October 2009, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 1.25 percent to 2.50 percent, based on the Company’s credit ratings. At March 31, 2009, there were no borrowings outstanding under this facility.

The third facility was an $18 million unsecured facility that bore interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. At March 31, 2009, there were no borrowings outstanding under this facility. This facility expired on March 31, 2009 and was replaced with a $25 million unsecured facility effective April 1, 2009 that bears interest at a daily negotiated rate.

The availability of funds under these 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 each of these 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 March 31, 2009, our total-debt-to-

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

total-capitalization ratio, as defined, was 56 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

In addition to these third-party facilities, our regulated operations had a $200 million intercompany revolving credit facility with AEH. Through December 31, 2008, this facility bore interest at the one-month LIBOR rate plus 0.20 percent. In January 2009, this facility was replaced with a new $200 million 364 day-facility that bears interest at the lower of (i) the one-month LIBOR rate plus 0.45 percent or (ii) the marginal borrowing rate available to the Company on the date of borrowing. The marginal borrowing rate is defined as the lower of (i) a rate based upon the lower of the Prime Rate or the Eurodollar rate under the five year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved the new facility through December 31, 2009. There were no borrowings outstanding under this facility at March 31, 2009.

Nonregulated Operations

On December 30, 2008, AEM and the participating banks amended and restated AEM’s former uncommitted credit facility, primarily to convert the $580 million uncommitted demand credit facility to a 364-day $375 million committed revolving credit facility and extend it to December 29, 2009.

The amended facility also provides the ability for AEM to increase the borrowing base up to a maximum of $450 million through an accordion feature, subject to the approval of the participating banks; adds a swing line loan feature; adjusts the interest rate on borrowings as discussed below and increases the fees paid to reflect the facility’s conversion to a committed facility and current credit market conditions. The swing line loan feature allows AEM to borrow, on a same day basis, an amount ranging from $17 million to $27 million based on the terms of an election within the agreement. Effective April 1, 2009, the borrowing base was increased to $450 million as a result of the exercise of the accordion feature in the facility.

AEM uses this facility primarily to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. At AEM’s option, borrowings made under the credit facility are based on a base rate or an offshore rate, in each case plus an applicable margin. The base rate is a floating rate equal to the higher of: (a) 0.50 percent per annum above the latest federal funds rate; (b) the per annum rate of interest established by BNP Paribas from time to time as its “prime rate” or “base rate” for U.S. dollar loans; (c) an offshore rate (based on LIBOR with a one-month interest period) as in effect from time to time; and (d) the “cost of funds” rate based on an average of interest rates reported by one or more of the lenders to the administrative agent. The offshore rate is a floating rate equal to the higher of (a) an offshore rate based upon LIBOR for the applicable interest period; and (b) a “cost of funds” rate referred to above. In the case of both base rate and offshore rate loans, the applicable margin ranges from 2.250 percent to 2.625 percent per annum, depending on the excess tangible net worth of AEM, as defined in the credit facility. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

At March 31, 2009, there were no borrowings outstanding under this credit facility. However, at March 31, 2009, AEM letters of credit totaling $48.4 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 $201.0 million at March 31, 2009.

AEM is required by the financial covenants in this facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At March 31, 2009, AEM’s ratio of total liabilities to tangible net worth, as defined, was 0.83 to 1. Additionally, AEM must maintain minimum levels of net working capital and net worth ranging from $75 million to $112.5 million. As defined in the financial

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

covenants, at March 31, 2009, AEM’s net working capital was $251.5 million and its tangible net worth was $271.3 million.

To supplement borrowings under this facility, through December 31, 2008, AEM had a $200 million intercompany demand credit facility with AEH, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Amounts outstanding under this facility are subordinated to AEM’s committed credit facility. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. A total of $60.0 million was outstanding under this facility at March 31, 2009.

Finally, through December 31, 2008, AEH had a $200 million intercompany demand credit facility with AEC, which bore interest at the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. This facility was replaced with another $200 million 364-day facility in January 2009 with no material changes to its terms except for the rate of interest, which is the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved the new facility through December 31, 2009. There were no borrowings outstanding under this facility at March 31, 2009.

Shelf Registration

As of March 31, 2009, we had $450 million of availability remaining under the registration statement after completing our Senior Notes Offering. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $300 million of equity securities and $150 million of subordinated debt securities.

Debt Covenants

In addition to the financial covenants described above, our debt instruments contain various covenants that are usual and customary for debt instruments of these types.

Additionally, 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.

Further, 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.

Finally, AEM’s credit 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. We have no other 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We were in compliance with all of our debt covenants as of March 31, 2009. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.


6.	Earnings Per Share

Basic and diluted earnings per share for the three and six months ended March 31, 2009 and 2008 are calculated as follows:


	Three Months Ended				Six Months Ended
	March 31				March 31
	2009		2008		2009		2008
	(In thousands, except per share amounts)

Net income	$	129,003	$	111,534	$	204,966	$	185,337

Denominator for basic income per share — weighted average common shares		90,895		89,314		90,637		89,133
Effect of dilutive securities:
Restricted and other shares		639		583		639		585
Stock options		33		93		35		99

Denominator for diluted income per share — weighted average common shares		91,567		89,990		91,311		89,817

Income per share — basic	$	1.42	$	1.25	$	2.26	$	2.08

Income per share — diluted	$	1.41	$	1.24	$	2.24	$	2.06

There were approximately 260,000 out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2009. There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2008 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 six months ended March 31, 2009 and 2008 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 March 31
	Pension Benefits						Other Benefits
	2009			2008			2009			2008
	(In thousands)

Components of net periodic pension cost:
Service cost	$	3,703		$	3,878		$	2,946		$	3,341
Interest cost		7,554			6,736			3,520			2,912
Expected return on assets		(6,238	)		(6,311	)		(573	)		(715	)
Amortization of transition asset		—			—			378			378
Amortization of prior service cost		(183	)		(171	)		—			—
Amortization of actuarial loss		955			1,926			—			—

Net periodic pension cost	$	5,791		$	6,058		$	6,271		$	5,916

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Six Months Ended March 31
	Pension Benefits						Other Benefits
	2009			2008			2009			2008
	(In thousands)

Components of net periodic pension cost:
Service cost	$	7,406		$	7,756		$	5,892		$	6,682
Interest cost		15,108			13,472			7,040			5,824
Expected return on assets		(12,476	)		(12,621	)		(1,146	)		(1,430	)
Amortization of transition asset		—			—			756			756
Amortization of prior service cost		(366	)		(342	)		—			—
Amortization of actuarial loss		1,910			3,852			—			—

Net periodic pension cost	$	11,582		$	12,117		$	12,542		$	11,832

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2009 and 2008 are as follows:


	Pension Benefits						Other Benefits
	2009			2008			2009			2008

Discount rate		7.57	%		6.30	%		7.57	%		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	%		5.00	%

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. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2009. Based upon this valuation, we expect we will be required to contribute less than $25 million to our pension plans by September 15, 2009.

We contributed $5.2 million to our other post-retirement benefit plans during the six months ended March 31, 2009. We expect to contribute a total of approximately $10 million to these plans during fiscal 2009.


8.	Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 12 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, there were no material changes in the status of such litigation and environmental-related matters or claims during the six months ended March 31, 2009. 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Purchase Commitments

AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At March 31, 2009, AEM was committed to purchase 97.6 Bcf within one year, 32.5 Bcf within one to three years and 1.0 Bcf after three years under indexed contracts. AEM is committed to purchase 1.3 Bcf within one year under fixed price contracts with prices ranging from $2.59 to $7.68 per Mcf. Purchases under these contracts totaled $431.5 million and $860.3 million for the three months ended March 31, 2009 and 2008 and $959.0 million and $1,432.3 million for the six months ended March 31, 2009 and 2008.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of March 31, 2009 are as follows (in thousands):


2009	$	40,033
2010		53,425
2011		5,245
2012		6,769
2013		7,453
Thereafter		2,571

	$	115,496

Regulatory Matters

As previously described in Note 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008, 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 for pre-arranged released firm capacity on natural gas pipelines.

After responding to two sets of data requests received from the Commission, the Commission agreed to allow us to conduct our own internal investigation into compliance with the Commission’s rules. During the second quarter, we completed our internal investigation and submitted the results to the Commission. During our investigation, we identified certain transactions that could possibly be considered non-compliant, and we continue to fully cooperate with the Commission as we work to resolve this matter. We have accrued what we believe is an adequate amount for the anticipated resolution of this proceeding. While the ultimate resolution of this investigation cannot be predicted with certainty, we believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

As of March 31, 2009, rate cases were in progress in our City of Dallas and Virginia service areas and annual rate filing mechanisms were in progress in our Mid-Tex, West Texas, Louisiana and Atmos Pipeline — Texas divisions. These regulatory proceedings are discussed in further detail in Management’s Discussion and Analysis — Recent Ratemaking Developments.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


9.	Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 14 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. During the six months ended March 31, 2009, there were no material changes in our concentration of credit risk.


10.	Segment Information

Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution, transmission and storage business as well as other nonregulated businesses. We distribute 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, 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 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.

	•	The pipeline, storage and other segment, which includes our nonregulated natural gas transmission and storage services.

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our 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 on Form 10-K for the fiscal year ended September 30, 2008. We evaluate performance based on net income or loss of the respective operating units.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income statements for the three and six month periods ended March 31, 2009 and 2008 by segment are presented in the following tables:


	Three Months Ended March 31, 2009
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	1,230,196	$	32,097	$	549,136	$	9,977	$	—		$	1,821,406
Intersegment revenues		224		27,137		159,522		2,295		(189,178	)		—

		1,230,420		59,234		708,658		12,272		(189,178	)		1,821,406
Purchased gas cost		863,340		—		685,114		1,656		(188,755	)		1,361,355

Gross profit		367,080		59,234		23,544		10,616		(423	)		460,051
Operating expenses
Operation and maintenance		90,710		17,327		12,323		1,889		(509	)		121,740
Depreciation and amortization		47,541		5,006		396		507		—			53,450
Taxes, other than income		55,101		2,572		446		195		—			58,314

Total operating expenses		193,352		24,905		13,165		2,591		(509	)		233,504

Operating income		173,728		34,329		10,379		8,025		86			226,547
Miscellaneous income (expense)		835		283		118		2,060		(4,861	)		(1,565	)
Interest charges		28,821		7,349		3,461		677		(4,775	)		35,533

Income before income taxes		145,742		27,263		7,036		9,408		—			189,449
Income tax expense		44,166		7,798		3,688		4,794		—			60,446

Net income	$	101,576	$	19,465	$	3,348	$	4,614	$	—		$	129,003

Capital expenditures	$	84,618	$	28,303	$	88	$	954	$	—		$	113,963

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended March 31, 2008
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	1,521,636	$	22,830	$	931,990	$	7,529	$	—		$	2,483,985
Intersegment revenues		220		28,610		196,663		2,493		(227,986	)		—

		1,521,856		51,440		1,128,653		10,022		(227,986	)		2,483,985
Purchased gas cost		1,164,332		—		1,112,321		338		(227,400	)		2,049,591

Gross profit		357,524		51,440		16,332		9,684		(586	)		434,394
Operating expenses
Operation and maintenance		98,578		15,086		5,525		1,536		(672	)		120,053
Depreciation and amortization		43,130		4,907		374		379		—			48,790
Taxes, other than income		52,304		1,385		407		312		—			54,408

Total operating expenses		194,012		21,378		6,306		2,227		(672	)		223,251

Operating income		163,512		30,062		10,026		7,457		86			211,143
Miscellaneous income		3,670		209		602		1,942		(4,956	)		1,467
Interest charges		29,084		6,776		2,002		524		(4,870	)		33,516

Income before income taxes		138,098		23,495		8,626		8,875		—			179,094
Income tax expense		52,442		8,271		3,347		3,500		—			67,560

Net income	$	85,656	$	15,224	$	5,279	$	5,375	$	—		$	111,534

Capital expenditures	$	89,671	$	13,700	$	38	$	1,158	$	—		$	104,567

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Six Months Ended March 31, 2009
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	2,285,968	$	62,319	$	1,165,980	$	23,471	$	—		$	3,537,738
Intersegment revenues		420		51,597		330,173		5,249		(387,439	)		—

		2,286,388		113,916		1,496,153		28,720		(387,439	)		3,537,738
Purchased gas cost		1,620,924		—		1,442,586		5,559		(386,594	)		2,682,475

Gross profit		665,464		113,916		53,567		23,161		(845	)		855,263
Operating expenses
Operation and maintenance		188,704		44,896		20,839		3,073		(1,017	)		256,495
Depreciation and amortization		94,680		9,961		797		1,138		—			106,576
Taxes, other than income		95,847		5,360		1,039		205		—			102,451

Total operating expenses		379,231		60,217		22,675		4,416		(1,017	)		465,522

Operating income		286,233		53,699		30,892		18,745		172			389,741
Miscellaneous income (expense)		3,956		1,098		419		4,221		(11,560	)		(1,866	)
Interest charges		61,708		15,428		7,363		1,413		(11,388	)		74,524

Income before income taxes		228,481		39,369		23,948		21,553		—			313,351
Income tax expense		76,772		12,243		10,025		9,345		—			108,385

Net income	$	151,709	$	27,126	$	13,923	$	12,208	$	—		$	204,966

Capital expenditures	$	173,621	$	33,363	$	117	$	14,229	$	—		$	221,330

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Six Months Ended March 31, 2008
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		and Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	2,449,665	$	45,267	$	1,634,712	$	11,851	$	—		$	4,141,495
Intersegment revenues		368		51,219		334,658		4,898		(391,143	)		—

		2,450,033		96,486		1,969,370		16,749		(391,143	)		4,141,495
Purchased gas cost		1,819,309		—		1,907,075		1,067		(389,988	)		3,337,463

Gross profit		630,724		96,486		62,295		15,682		(1,155	)		804,032
Operating expenses
Operation and maintenance		195,825		30,518		13,402		2,824		(1,327	)		241,242
Depreciation and amortization		85,962		9,823		761		757		—			97,303
Taxes, other than income		87,922		3,829		3,407		677		—			95,835

Total operating expenses		369,709		44,170		17,570		4,258		(1,327	)		434,380

Operating income		261,015		52,316		44,725		11,424		172			369,652
Miscellaneous income		4,146		383		1,398		3,970		(8,523	)		1,374
Interest charges		60,298		13,847		3,316		1,223		(8,351	)		70,333

Income before income taxes		204,863		38,852		42,807		14,171		—			300,693
Income tax expense		79,043		13,781		16,928		5,604		—			115,356

Net income	$	125,820	$	25,071	$	25,879	$	8,567	$	—		$	185,337

Capital expenditures	$	173,984	$	22,082	$	69	$	2,587	$	—		$	198,722

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at March 31, 2009 and September 30, 2008 by segment is presented in the following tables:


	March 31, 2009
	Natural		Regulated		Natural			Pipeline,
	Gas		Transmission		Gas			Storage and
	Distribution		and Storage		Marketing			Other		Eliminations			Consolidated
	(In thousands)

ASSETS
Property, plant and equipment, net	$	3,577,546	$	608,118	$	7,312		$	70,216	$	—		$	4,263,192
Investment in subsidiaries		484,117		—		(2,096	)		—		(482,021	)		—
Current assets
Cash and cash equivalents		379,391		—		86,143			16,551		—			482,085
Assets from risk management activities		676		—		42,266			2,394		(3,623	)		41,713
Other current assets		671,993		16,614		265,457			77,428		(76,735	)		954,757
Intercompany receivables		504,887		—		—			147,783		(652,670	)		—

Total current assets		1,556,947		16,614		393,866			244,156		(733,028	)		1,478,555
Intangible assets		—		—		1,774			—		—			1,774
Goodwill		569,920		132,367		24,282			10,429		—			736,998
Noncurrent assets from risk management activities		—		—		9,739			—		—			9,739
Deferred charges and other assets		166,610		7,924		873			20,096		—			195,503

	$	6,355,140	$	765,023	$	435,750		$	344,897	$	(1,215,049	)	$	6,685,761

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,178,494	$	157,270	$	75,451		$	251,396	$	(484,117	)	$	2,178,494
Long-term debt		2,168,683		—		—			458		—			2,169,141

Total capitalization		4,347,177		157,270		75,451			251,854		(484,117	)		4,347,635
Current liabilities
Current maturities of long-term debt		400,000		—		—			225		—			400,225
Short-term debt		—		—		60,000			—		(60,000	)		—
Liabilities from risk management activities		22,535		—		6,734			1,200		(3,623	)		26,846
Other current liabilities		586,656		6,850		203,044			76,973		(14,527	)		858,996
Intercompany payables		—		525,249		127,421			—		(652,670	)		—

Total current liabilities		1,009,191		532,099		397,199			78,398		(730,820	)		1,286,067
Deferred income taxes		422,381		71,643		(37,586	)		10,542		(112	)		466,868
Noncurrent liabilities from risk management activities		4		—		13			—		—			17
Regulatory cost of removal obligation		313,486		—		—			—		—			313,486
Deferred credits and other liabilities		262,901		4,011		673			4,103		—			271,688

	$	6,355,140	$	765,023	$	435,750		$	344,897	$	(1,215,049	)	$	6,685,761

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 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	$	3,483,556	$	585,160	$	7,520		$	60,623	$	—		$	4,136,859
Investment in subsidiaries		463,158		—		(2,096	)		—		(461,062	)		—
Current assets
Cash and cash equivalents		30,878		—		9,120			6,719		—			46,717
Assets from risk management activities		—		—		69,008			20,239		(20,956	)		68,291
Other current assets		774,933		18,396		411,648			56,791		(91,672	)		1,170,096
Intercompany receivables		578,833		—		—			135,795		(714,628	)		—

Total current assets		1,384,644		18,396		489,776			219,544		(827,256	)		1,285,104
Intangible assets		—		—		2,088			—		—			2,088
Goodwill		569,920		132,367		24,282			10,429		—			736,998
Noncurrent assets from risk management activities		—		—		5,473			—		—			5,473
Deferred charges and other assets		195,985		11,212		1,182			11,798		—			220,177

	$	6,097,263	$	747,135	$	528,225		$	302,394	$	(1,288,318	)	$	6,386,699

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,052,492	$	130,144	$	114,559		$	218,455	$	(463,158	)	$	2,052,492
Long-term debt		2,119,267		—		—			525		—			2,119,792

Total capitalization		4,171,759		130,144		114,559			218,980		(463,158	)		4,172,284
Current liabilities
Current maturities of long-term debt		—		—		—			785		—			785
Short-term debt		385,592		—		6,500			—		(41,550	)		350,542
Liabilities from risk management activities		58,566		—		20,688			616		(20,956	)		58,914
Other current liabilities		538,777		7,053		236,217			62,796		(47,997	)		796,846
Intercompany payables		—		543,384		171,244			—		(714,628	)		—

Total current liabilities		982,935		550,437		434,649			64,197		(825,131	)		1,207,087
Deferred income taxes		384,860		62,720		(21,936	)		15,687		(29	)		441,302
Noncurrent liabilities from risk management activities		5,111		—		258			—		—			5,369
Regulatory cost of removal obligation		298,645		—		—			—		—			298,645
Deferred credits and other liabilities		253,953		3,834		695			3,530		—			262,012

	$	6,097,263	$	747,135	$	528,225		$	302,394	$	(1,288,318	)	$	6,386,699

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Atmos Energy Corporation

We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation as of March 31, 2009, the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2009 and 2008, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 2009 and 2008. 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, 2008, 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 18, 2008, 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, 2008, 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

April 30, 2009


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

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2008.

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

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 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 on Form 10-K for the year ended September 30, 2008, include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of recent economic conditions on our customers; increased costs of providing pension and postretirement health care benefits and increased funding requirements; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the inherent hazards and risks involved in operating our gas distribution business, natural disasters, terrorist activities or other events; and other risks and uncertainties discussed herein, 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 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 on Form 10-K for the fiscal year ended September 30, 2008 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 quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the six months ended March 31, 2009.

RESULTS OF OPERATIONS

The following table presents our consolidated financial highlights for the three and six months ended March 31, 2009 and 2008:


	Three Months Ended					Six Months Ended
	March 31					March 31
	2009			2008		2009			2008
	(In thousands, except per share data)

Operating revenues	$	1,821,406		$	2,483,985	$	3,537,738		$	4,141,495
Gross profit		460,051			434,394		855,263			804,032
Operating expenses		233,504			223,251		465,522			434,380
Operating income		226,547			211,143		389,741			369,652
Miscellaneous income (expense)		(1,565	)		1,467		(1,866	)		1,374
Interest charges		35,533			33,516		74,524			70,333
Income before income taxes		189,449			179,094		313,351			300,693
Income tax expense		60,446			67,560		108,385			115,356
Net income	$	129,003		$	111,534	$	204,966		$	185,337
Diluted net income per share	$	1.41		$	1.24	$	2.24		$	2.06

Our consolidated net income during the three and six months ended March 31, 2009 and 2008 was earned in each of our business segments as follows:


	Three Months Ended
	March 31
	2009		2008		Change
	(In thousands)

Natural gas distribution segment	$	101,576	$	85,656	$	15,920
Regulated transmission and storage segment		19,465		15,224		4,241
Natural gas marketing segment		3,348		5,279		(1,931	)
Pipeline, storage and other segment		4,614		5,375		(761	)

Net income	$	129,003	$	111,534	$	17,469


	Six Months Ended
	March 31
	2009		2008		Change
	(In thousands)

Natural gas distribution segment	$	151,709	$	125,820	$	25,889
Regulated transmission and storage segment		27,126		25,071		2,055
Natural gas marketing segment		13,923		25,879		(11,956	)
Pipeline, storage and other segment		12,208		8,567		3,641

Net income	$	204,966	$	185,337	$	19,629

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


	Three Months Ended
	March 31
	2009		2008		Change
	(In thousands, except per share data)

Regulated operations	$	121,041	$	100,880	$	20,161
Nonregulated operations		7,962		10,654		(2,692	)

Consolidated net income	$	129,003	$	111,534	$	17,469

Diluted EPS from regulated operations	$	1.32	$	1.12	$	0.20
Diluted EPS from nonregulated operations		0.09		0.12		(0.03	)

Consolidated diluted EPS	$	1.41	$	1.24	$	0.17


	Six Months Ended
	March 31
	2009		2008		Change
	(In thousands, except per share data)

Regulated operations	$	178,835	$	150,891	$	27,944
Nonregulated operations		26,131		34,446		(8,315	)

Consolidated net income	$	204,966	$	185,337	$	19,629

Diluted EPS from regulated operations	$	1.96	$	1.68	$	0.28
Diluted EPS from nonregulated operations		0.28		0.38		(0.10	)

Consolidated diluted EPS	$	2.24	$	2.06	$	0.18

The following summarizes the results of our operations and other significant events for the six months ended March 31, 2009:


	•	Regulated operations generated 87 percent of our net income during the six months ended March 31, 2009 compared to 81 percent during the six months ended March 31, 2008. The $27.9 million increase in our regulated operations net income primarily reflects favorable ratemaking activity coupled with a one-time tax benefit discussed below.

	•	Nonregulated operations contributed 13 percent of net income during the six months ended March 31, 2009 compared to 19 percent during the six months ended March 31, 2008. The $8.3 million decrease in our nonregulated operations net income primarily reflects a decrease in unrealized margins and an increase in operating expenses partially offset by favorable asset optimization margins.

	•	For the six months ended March 31, 2009, we generated $614.6 million in operating cash flow compared with $479.2 million for the six months ended March 31, 2008, primarily reflecting the favorable impact on our working capital due to the decline in natural gas prices in the current year compared to the prior-year period and the favorable timing of the recovery of gas costs.

	•	On March 23, 2009, we filed a $900 million shelf registration statement with the Securities and Exchange Commission (SEC) that replaced our previously existing shelf registration statement. On March 26, 2009, we completed an offering of $450 million unsecured 8.50% senior notes and received net proceeds of approximately $446 million. Most of the net proceeds received were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.

	•	Quarter-to-date and year-to-date results were favorably impacted by a one-time tax benefit of $11.3 million, or $0.12 per diluted share. The benefit arose during the quarter when we updated the tax rates used to record our deferred taxes. This benefit increased natural gas distribution net income by $10.5 million and regulated transmission and storage income by $1.7 million. However, net income for the natural gas marketing and pipeline, storage and other segments’ net income were reduced by $0.3 million and $0.6 million.

Three Months Ended March 31, 2009 compared with Three Months Ended March 31, 2008

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. Prior to January 1, 2009, 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 could 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. Beginning January 1, 2009, changes in our franchise fee agreements in our Mid-Tex Division became effective which should significantly reduce the impact of this timing difference on a prospective basis. However, this timing difference still occurs for gross receipts taxes.

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 March 31, 2009 and 2008 are presented below.


	Three Months Ended
	March 31
	2009		2008		Change
	(In thousands, unless otherwise noted)

Gross profit	$	367,080	$	357,524	$	9,556
Operating expenses		193,352		194,012		(660	)

Operating income		173,728		163,512		10,216
Miscellaneous income		835		3,670		(2,835	)
Interest charges		28,821		29,084		(263	)

Income before income taxes		145,742		138,098		7,644
Income tax expense		44,166		52,442		(8,276	)

Net income	$	101,576	$	85,656	$	15,920

Consolidated natural gas distribution sales volumes — MMcf		121,560		135,568		(14,008	)
Consolidated natural gas distribution transportation volumes — MMcf		35,061		39,730		(4,669	)

Total consolidated natural gas distribution throughput — MMcf		156,621		175,298		(18,677	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.48	$	0.44	$	0.04
Consolidated natural gas distribution average cost of gas per Mcf sold	$	7.10	$	8.59	$	(1.49	)

The following table shows our operating income by natural gas distribution division, in order of total customers served, for the three months ended March 31, 2009 and 2008. 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
	March 31
	2009		2008		Change
	(In thousands)

Mid-Tex	$	80,374	$	72,479	$	7,895
Kentucky/Mid-States		27,404		29,875		(2,471	)
Louisiana		19,782		19,236		546
West Texas		14,806		8,919		5,887
Mississippi		16,771		16,514		257
Colorado-Kansas		13,623		15,536		(1,913	)
Other		968		953		15

Total	$	173,728	$	163,512	$	10,216

The $9.6 million increase in natural gas distribution gross profit primarily reflects a net $21.9 million increase in rates. The net increase in rates was attributable primarily to the Mid-Tex Division, which increased $16.5 million as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all incorporated cities in the division other than the City of Dallas (the Settled Cities) and rate adjustments for customers in the City of Dallas. The current year period also reflects a $5.4 million increase in rate adjustments primarily in Georgia, Louisiana and West Texas. The increase also reflects the reversal of a $7.0 million accrual for estimated unrecoverable gas costs recorded in a prior year. These increases in gross profit were partially offset by a $13.5 million decrease as a result of an 11 percent decrease in distribution throughput, primarily associated with lower residential and commercial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.

Partially offsetting these increases was a decrease of approximately $8.9 million in revenue-related taxes primarily due to lower revenues, on which the tax is calculated, in the current-year quarter compared to the prior-year quarter. This decrease was partially offset by a $0.8 million quarter-over-quarter decrease in the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income, resulting in an $8.1 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, decreased $0.7 million.

Operation and maintenance expense, excluding the provision for doubtful accounts, decreased $6.9 million, primarily due to lower legal, fuel and other administrative costs.

Depreciation and amortization expense increased $4.4 million for the second quarter of fiscal 2009 compared with second quarter of fiscal 2008. The increase primarily was attributable to additional assets placed in service during the current-year period.

Results for the quarter include the aforementioned $10.5 million tax benefit, which more than offset the decrease attributable to the absence in the current-year quarter of a $1.2 million gain on the sale of irrigation assets in our West Texas Division in the prior-year quarter.

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the six months ended March 31, 2009 are discussed below. The amounts described below represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s final ruling.

Annual Rate Filing Mechanisms

In March 2009, the Mid-Tex Division filed its second RRM with the Settled Cities. The filing requested an increase in operating income of $9.7 million for the Settled Cities. Representatives of the Settled Cities are currently reviewing the filing and a final determination is expected in July 2009. Beginning in November 2008, rates were implemented from our first RRM filing with the Settled Cities, which resulted in an increase in operating income on a system-wide basis of approximately $27.3 million. The impact to the Mid-Tex Division for the Settled Cities was approximately $21.8 million.

In April 2009, the West Texas Division filed its second RRM with the West Texas Cities. The filing requested an increase in operating income of $11.1 million. Representatives of the West Texas Cities are currently reviewing the filing and a final determination is expected in August 2009. Beginning in November 2008, rates were implemented from our first RRM with the West Texas Cities, which resulted in an increase in operating income of $4.5 million, of which $3.9 million is being collected over a 91/2 month period.

In April 2009, the City of Lubbock approved an RRM tariff similar to the RRM tariff utilized by the West Texas Cities. The West Texas Division filed its first RRM with the City of Lubbock on April 15, 2009. The filing requested an increase in operating income of $3.5 million. The City of Lubbock is currently reviewing the filing and a final determination is expected in October 2009.

In December 2008, the Louisiana Division filed its TransLa annual rate stabilization clause with the Louisiana Public Service Commission (LPSC) for the test year ended September 30, 2008. The filing resulted in an increase in operating income of $0.6 million and was implemented in April 2009.

In April 2009, the Louisiana Division filed its LGS annual rate stabilization clause with the LPSC requesting an increase in operating income of $3.9 million. The filing was for the test year ended December 31, 2008. We anticipate final resolution of this proceeding by June 2009.

In September 2008, we filed our Mississippi stable rate filing with the Mississippi Public Service Commission (MPSC) requesting an increase of $3.5 million. In January 2009, we withdrew this request after we were unable to reach a mutually agreeable settlement with the MPSC.

GRIP Filings

In May 2008, the Mid-Tex Division made a GRIP filing seeking a $10.3 million increase on a system-wide basis. However, this filing was only applicable to the City of Dallas and the Mid-Tex environs and sought a $1.8 million increase for customers in those service areas. Rates were approved for this filing in December 2008 and were implemented in January 2009. However, in April 2009, the City of Dallas challenged the legality of the implementation of the GRIP rates, which the Company is contesting in the District Courts of Dallas and Travis Counties.

In March 2009, the Mid-Tex Division made a GRIP filing seeking an $18.7 million increase on a system-wide basis. However, this filing is applicable to the City of Dallas only and seeks a $2.7 million increase for customers in the City of Dallas. The City of Dallas has until July 10, 2009 to either accept or object to the filing. If this filing is accepted, the rates will go into effect until such time that they are superseded by the statement of intent filed with the City of Dallas discussed below.

Rate Case Filings

In October 2008, our Kentucky/Mid-States Division filed a rate case with the Tennessee Regulatory Authority seeking an increase in operating income of $6.3 million. In January 2009, the Consumer Advocate and Protection Division recommended a decrease in rates of $3.7 million. In March 2009, a unanimous stipulation was filed and approved in the case. The parties agreed to an increase in operating income of $2.5 million with a stated return on equity of 10.3 percent. The increase in rates was implemented in April 2009.

In November 2008, the Mid-Tex Division filed a statement of intent to increase operating income for customers within the City of Dallas by $9.1 million. The City of Dallas suspended the filing on December 10, 2008 and denied the increase in March 2009. The Company has appealed the filing and in April 2009 we requested an increase in operating income of $7.5 million and concurrently filed for a statement of intent to increase operating income $1.3 million applicable to the Mid-Tex unincorporated areas. A final ruling by the Railroad Commission of Texas (RRC) is expected by October 2009. If the statement of intent applicable to the

City of Dallas is approved by the RRC, the new rates implemented could supersede the City of Dallas GRIP rates discussed above.

In April 2009, the Kentucky/Mid-States Division filed an expedited rate case with the Virginia State Corporation Commission seeking an increase in operating income of $1.7 million. Interim rates will be implemented subject to refund on May 1, 2009. The application is currently in discovery with a final determination expected in October 2009.

Other Ratemaking Activity

In May 2007, our Mid-Tex Division filed for a 36-month gas contract review filing. This filing was mandated by prior RRC orders and related to the prudency of gas purchases made from November 2003 through October 2006, which total approximately $2.7 billion. The intervening parties recommended disallowances ranging from $58 million to $89 million. A hearing was held at the RRC in September 2008. In December 2008, a proposal for decision was issued by the Hearing Examiner recommending no gas cost disallowance. In February 2009, the RRC approved the Hearing Examiner’s recommendation to disallow no gas costs.

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 March 31, 2009 and 2008 are presented below.


	Three Months Ended
	March 31
	2009		2008		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	27,061	$	28,260	$	(1,199	)
Third-party transportation		23,846		18,229		5,617
Storage and park and lend services		2,657		1,862		795
Other		5,670		3,089		2,581

Gross profit		59,234		51,440		7,794
Operating expenses		24,905		21,378		3,527

Operating income		34,329		30,062		4,267
Miscellaneous income		283		209		74
Interest charges		7,349		6,776		573

Income before income taxes		27,263		23,495		3,768
Income tax expense		7,798		8,271		(473	)

Net income	$	19,465	$	15,224	$	4,241

Gross pipeline transportation volumes — MMcf		193,356		223,476		(30,120	)

Consolidated pipeline transportation volumes — MMcf		123,285		141,108		(17,823	)

The $7.8 million increase in gross profit was attributable primarily to a $3.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions and a $3.3 million increase from higher demand-based fees. The improvement in gross profit also reflects a $2.9 million gain on the routine sale of excess gas during the quarter and a $1.4 million increase due to our 2006 and 2007 GRIP filings. These increases were partially offset by a $4.1 million decrease arising from lower city-gate, electrical generation, Barnett Shale and HUB deliveries.

Operating expenses increased $3.5 million primarily due to increased employee and pipeline maintenance costs.

Results for the quarter also include the aforementioned $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.

Recent Ratemaking Developments

In February 2009, the Atmos Pipeline — Texas Division made a GRIP filing seeking an increase in operating income of $6.3 million. The filing was approved by the RRC and a final order was issued in April 2009.

Natural Gas Marketing Segment

Our natural gas marketing activities are conducted through Atmos Energy Marketing, LLC (AEM). AEM aggregates and purchases gas supply, arranges transportation and/or storage logistics and ultimately delivers gas to our customers at competitive prices. To facilitate this process, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request, including furnishing natural gas supplies at fixed and market-based prices, contract negotiation and administration, load forecasting, gas storage acquisition and management services, transportation services, peaking sales and balancing services, capacity utilization strategies and gas price hedging through the use of 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 economically 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 financial instruments 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 March 31, 2009 and 2008 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 the physical/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
	March 31
	2009			2008			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	23,165		$	26,195		$	(3,030	)
Asset optimization		(2,073	)		27,737			(29,810	)

		21,092			53,932			(32,840	)
Unrealized margins		2,452			(37,600	)		40,052

Gross profit		23,544			16,332			7,212
Operating expenses		13,165			6,306			6,859

Operating income		10,379			10,026			353
Miscellaneous income		118			602			(484	)
Interest charges		3,461			2,002			1,459

Income before income taxes		7,036			8,626			(1,590	)
Income tax expense		3,688			3,347			341

Net income	$	3,348		$	5,279		$	(1,931	)

Gross natural gas marketing sales volumes — MMcf		123,066			136,677			(13,611	)

Consolidated natural gas marketing sales volumes — MMcf		104,973			120,023			(15,050	)

Net physical position (Bcf)		21.9			20.7			1.2

The $7.2 million increase in our natural gas marketing segment’s gross profit was driven primarily by a $40.1 million increase in unrealized margins. This increase reflects lower volatility during the current quarter

compared with the prior-year quarter between current cash prices used to value our physical inventory and future natural gas prices, which influence the prices used to value the financial instruments used to hedge our physical inventory.

The increase in unrealized margins was partially offset by a $29.8 million decrease in asset optimization margins. During the current quarter, as a result of falling current cash prices, AEM elected to defer storage withdrawals, reset the corresponding financial instruments and inject additional gas into storage to increase the potential gross profit it could realize in future periods from its asset optimization activities. Accordingly, AEM’s results for the quarter reflect lower realized gains from storage withdrawals and the settlement of the associated financial instruments. In the prior-year quarter, AEM elected to withdraw storage and realize the corresponding storage withdrawal gains.

In addition, delivered gas margins decreased $3.0 million compared with the prior-year quarter largely attributable to a 10 percent decrease in gross sales volumes, primarily associated with lower industrial demand due to the current economic climate. Per-unit margins for the quarter were approximately two percent lower compared with the prior-year quarter.

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 March 31, 2009, December 31, 2008 and September 30, 2008.


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

March 31, 2009		21.9	$	33.4	$	2.4	$	31.0
December 31, 2008		16.3	$	20.7	$	4.8	$	15.9
September 30, 2008		8.0	$	48.5	$	36.4	$	12.1


⁽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 our investors a more comprehensive view of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone.

As of March 31, 2009, based upon AEM’s planned inventory withdrawal schedule and associated planned settlement of financial instruments, the economic gross profit was $33.4 million. This amount will be reduced by $2.4 million of net unrealized gains recorded in the financial statements as of March 31, 2009 that will reverse when the inventory is withdrawn and the accompanying financial instruments are settled. Therefore, the potential gross profit was $31.0 million at March 31, 2009.

During the six months ended March 31, 2009, AEM increased its potential gross profit by $18.9 million to $31.0 million. In the first quarter, AEM withdrew gas and substantially realized the associated potential gross profit reported as of September 30, 2008. Since that time, as a result of falling current cash prices, AEM

has been deferring storage withdrawals and has been a net injector of gas into storage to increase the potential gross profit it could realize in future periods from its asset optimization activities. As a result of these activities, AEM has increased its net physical position by 13.9 Bcf since September 30, 2008. However, the captured spreads on these positions have been lower than those captured as of September 30, 2008, resulting in a lower economic gross profit compared to that time, but higher than the economic gross profit of $10.8 million as of March 31, 2008. This decrease from September 2008 to March 2009 was partially offset by lower unrealized gains associated with these positions primarily due to lower current cash prices.

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 March 31, 2009 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 March 31, 2009, without encountering operational or other issues, we anticipate that approximately $1 million of the potential gross profit as of March 31, 2009 will be recognized in fiscal 2009 with the remaining $30 million expected to be recognized during the first six months of fiscal 2010.

Pipeline, Storage and Other Segment

Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS owns and operates a 21 mile pipeline located in New Orleans, Louisiana. This pipeline is primarily used to aggregate gas supply for our regulated natural gas distribution division in Louisiana and for AEM, but also provides limited third party transportation services.

Results for this segment are impacted primarily 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 March 31, 2009 and 2008 are presented below.


	Three Months Ended
	March 31
	2009			2008			Change
	(In thousands)

Asset optimization	$	15,157		$	6,604		$	8,553
Storage and transportation services		3,312			3,895			(583	)
Other		350			1,113			(763	)
Unrealized margins		(8,203	)		(1,928	)		(6,275	)

Gross profit		10,616			9,684			932
Operating expenses		2,591			2,227			364

Operating income		8,025			7,457			568
Miscellaneous income		2,060			1,942			118
Interest charges		677			524			153

Income before income taxes		9,408			8,875			533
Income tax expense		4,794			3,500			1,294

Net income	$	4,614		$	5,375		$	(761	)

Gross profit from our pipeline, storage and other segment increased $0.9 million primarily due to an $8.6 million increase in asset optimization margins resulting from larger realized gains from the settlement of financial positions associated with storage and trading activities and basis gains earned from utilizing controlled pipeline capacity. These increases were partially offset by a $6.3 million decrease in unrealized margins associated with our asset optimization activities due to a widening of the spreads between current cash prices and forward natural gas prices.

Operating expenses for the three months ended March 31, 2009 were consistent with the prior-year quarter.

Six Months Ended March 31, 2009 compared with Six Months Ended March 31, 2008

Natural Gas Distribution Segment

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2009 and 2008 are presented below.


	Six Months Ended
	March 31
	2009		2008		Change
	(In thousands, unless otherwise noted)

Gross profit	$	665,464	$	630,724	$	34,740
Operating expenses		379,231		369,709		9,522

Operating income		286,233		261,015		25,218
Miscellaneous income		3,956		4,146		(190	)
Interest charges		61,708		60,298		1,410

Income before income taxes		228,481		204,863		23,618
Income tax expense		76,772		79,043		(2,271	)

Net income	$	151,709	$	125,820	$	25,889

Consolidated natural gas distribution sales volumes — MMcf		213,006		220,335		(7,329	)
Consolidated natural gas distribution transportation volumes — MMcf		69,397		73,479		(4,082	)

Total consolidated natural gas distribution throughput — MMcf		282,403		293,814		(11,411	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.44	$	0.02
Consolidated natural gas distribution average cost of gas per Mcf sold	$	7.61	$	8.26	$	(0.65	)

The following table shows our operating income by natural gas distribution division, in order of total customers served, for the six months ended March 31, 2009 and 2008. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Six Months Ended
	March 31
	2009		2008		Change
	(In thousands)

Mid-Tex	$	133,052	$	122,704	$	10,348
Kentucky/Mid-States		46,429		44,043		2,386
Louisiana		34,366		31,168		3,198
West Texas		22,819		13,895		8,924
Mississippi		25,206		24,343		863
Colorado-Kansas		22,224		22,224		—
Other		2,137		2,638		(501	)

Total	$	286,233	$	261,015	$	25,218

The $34.7 million increase in natural gas distribution gross profit primarily reflects a net $37.2 million increase in rates. The net increase in rates was attributable primarily to the Mid-Tex Division, which increased $27.8 million as a result of the implementation of its 2008 Rate Review Mechanism (RRM) filing with all

incorporated cities in the division other than the City of Dallas (the Settled Cities) and rate adjustments for customers in the City of Dallas. The current year period also reflects a $9.4 million increase in rate adjustments primarily in Georgia, Kansas, Louisiana and West Texas. The increase in gross profit also reflects the reversal of a $7.0 million uncollectible gas cost accrual recorded in a prior year and an $8.3 million increase attributable to a non-recurring update to our estimate for gas delivered to customers but not yet billed to reflect changes in base rates in several of our jurisdictions recorded in the fiscal first quarter. These increases in gross profit were partially offset by a $14.8 million decrease as a result of a four percent decrease in distribution throughput primarily associated with lower residential and commercial consumption and warmer weather in our Colorado service area, which does not have weather-normalized rates.

Partially offsetting these increases was a decrease of approximately $9.2 million in revenue-related taxes primarily due to lower revenues, on which the tax is calculated, in the current-year period compared to the prior-year period. This decrease, combined with a $7.3 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 $16.5 million decrease 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 $9.5 million.

Operation and maintenance expense, excluding the provision for doubtful accounts, decreased $4.7 million, primarily due to lower legal, fuel and other administrative costs. These decreases were partially offset by a $2.1 million noncash charge in the first quarter of fiscal 2009 to impair certain available-for-sale investments due to the recent deterioration of the financial markets.

Depreciation and amortization expense increased $8.7 million for the current-year period compared with six months ended March 31, 2008. The increase primarily was attributable to additional assets placed in service during the current-year period.

Results for the prior-year period also included a $1.2 million gain on the sale of irrigation assets in our West Texas Division.

Interest charges allocated to the natural gas distribution segment increased $1.4 million due to higher average short-term debt balances, interest rates and commitment fees experienced during the current-year period compared to the prior-year period. These increases are associated with the recent adverse conditions in the credit markets.

Results for the current-year period include the aforementioned $10.5 million tax benefit associated with updating the rates used to determine our deferred taxes.

Regulated Transmission and Storage Segment

Review of Financial and Operating Results

Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2009 and 2008 are presented below.


	Six Months Ended
	March 31
	2009		2008		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	51,413	$	50,648	$	765
Third-party transportation		49,212		36,461		12,751
Storage and park and lend services		5,014		3,901		1,113
Other		8,277		5,476		2,801

Gross profit		113,916		96,486		17,430
Operating expenses		60,217		44,170		16,047

Operating income		53,699		52,316		1,383
Miscellaneous income		1,098		383		715
Interest charges		15,428		13,847		1,581

Income before income taxes		39,369		38,852		517
Income tax expense		12,243		13,781		(1,538	)

Net income	$	27,126	$	25,071	$	2,055

Gross pipeline transportation volumes — MMcf		385,528		412,340		(26,812	)

Consolidated pipeline transportation volumes — MMcf		259,143		277,308		(18,165	)

The $17.4 million increase in gross profit was attributable primarily to a $7.6 million increase resulting from higher transportation fees on through-system deliveries due to market conditions and a $6.4 million increase from higher demand-based fees. The improvement in gross profit also reflects a $2.9 million gain on the sale of excess gas during the current-year period and a $2.7 million increase due to our 2006 and 2007 GRIP filings. These increases were partially offset by a $3.4 million decrease associated with lower city-gate, electrical generation, Barnett Shale and HUB deliveries.

Operating expenses increased $16.0 million primarily due to increased employee and pipeline maintenance costs.

Results for the current-year period also include the aforementioned $1.7 million tax benefit associated with updating the rates used to determine our deferred taxes.

Natural Gas Marketing Segment

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the six months ended March 31, 2009 and 2008 are presented below.


	Six Months Ended
	March 31
	2009			2008			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	41,718		$	44,368		$	(2,650	)
Asset optimization		34,866			27,212			7,654

		76,584			71,580			5,004
Unrealized margins		(23,017	)		(9,285	)		(13,732	)

Gross profit		53,567			62,295			(8,728	)
Operating expenses		22,675			17,570			5,105

Operating income		30,892			44,725			(13,833	)
Miscellaneous income		419			1,398			(979	)
Interest charges		7,363			3,316			4,047

Income before income taxes		23,948			42,807			(18,859	)
Income tax expense		10,025			16,928			(6,903	)

Net income	$	13,923		$	25,879		$	(11,956	)

Gross natural gas marketing sales volumes — MMcf		233,724			245,386			(11,662	)

Consolidated natural gas marketing sales volumes — MMcf		198,281			216,229			(17,948	)

Net physical position (Bcf)		21.9			20.7			1.2

The $8.7 million decrease in our natural gas marketing segment’s gross profit was driven primarily by a $13.7 million decrease in unrealized margins. This decrease reflects higher volatility during the current period between current cash prices used to value our physical inventory and future natural gas prices, which influence the prices used to value the financial instruments used to hedge our physical inventory.

Additionally, realized delivered gas margins decreased by $2.7 million. The decrease was largely attributable to a five percent decrease in gross sales volumes primarily associated with lower industrial demand due to the current economic climate combined with a one percent decrease in per-unit margins, compared with the prior-year period.

The decrease in unrealized margins and delivered gas margins was partially offset by a $7.7 million increase in asset optimization margins. During the first quarter of fiscal 2009, AEM withdrew physical storage inventory and realized the spreads it had captured during fiscal 2008 as a result of deferring storage withdrawals and increasing the spreads associated with those physical positions. These gains were partially offset by the margin loss incurred in the second quarter as a result of deferring storage withdrawals and injecting gas into storage. In the prior-year period, AEM deferred storage withdrawals from the first quarter into the second quarter, and recognized the storage withdrawal gains during the second quarter of fiscal 2008.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $5.1 million primarily due to an increase in legal and other administrative costs partially offset by the absence in the current year of $2.4 million related to tax matters incurred in the prior-year period.

Pipeline, Storage and Other Segment

Review of Financial and Operating Results

Financial and operational highlights for our pipeline, storage and other segment for the six months ended March 31, 2009 and 2008 are presented below.


	Six Months Ended
	March 31
	2009			2008		Change
	(In thousands)

Asset optimization	$	20,624		$	6,374	$	14,250
Storage and transportation services		6,627			7,023		(396	)
Other		1,339			1,840		(501	)
Unrealized margins		(5,429	)		445		(5,874	)

Gross profit		23,161			15,682		7,479
Operating expenses		4,416			4,258		158

Operating income		18,745			11,424		7,321
Miscellaneous income		4,221			3,970		251
Interest charges		1,413			1,223		190

Income before income taxes		21,553			14,171		7,382
Income tax expense		9,345			5,604		3,741

Net income	$	12,208		$	8,567	$	3,641

Gross profit from our pipeline, storage and other segment increased $7.5 million primarily due to a $14.3 million increase in asset optimization margins as a result of larger realized gains from the settlement of financial positions associated with storage and trading activities, basis gains earned from utilizing controlled pipeline capacity and higher margins earned under asset management plans during the current-year period compared with the prior-year period. These increases were partially offset by a $5.9 million decrease in unrealized margins associated with our asset optimization activities due to a widening of the spreads between current cash prices and forward natural gas prices.

Operating expenses for the six months ended March 31, 2009 were consistent with the prior-year period.

Liquidity and Capital Resources

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.

The primary means we use to fund our working capital needs and growth is to utilize internally generated funds and to access the commercial paper markets. Recent adverse developments in global financial and credit markets have made it more difficult and more expensive for the Company to access the short-term capital markets, including the commercial paper market, to satisfy our liquidity requirements. Consequently, during the first quarter, we experienced higher than normal borrowings under our five-year credit facility used to backstop our commercial paper program in lieu of commercial paper borrowings to fund our working capital needs. However, subsequent to the end of the first quarter, credit market conditions improved, both as to availability and interest rates, and we have been able to access the commercial paper markets on more reasonably economical terms. At March 31, 2009, there were no borrowings or commercial paper outstanding under this facility and $566.7 million was available.

On March 26, 2009, we closed our offering of $450 million of 8.50% senior notes due 2019. Most of the net proceeds of approximately $446 million were used to redeem our $400 million 4.00% unsecured senior notes, which, on March 30, 2009, were called for redemption on April 30, 2009, prior to their October 2009 maturity. In connection with the repayment of the $400 million 4.00% unsecured senior notes, we paid a $6.6 million call premium in accordance with the terms of the senior notes and accrued interest of approximately $0.6 million. The remaining net proceeds will be used for general corporate purposes.

During the six months ended March 31, 2009, we increased our liquidity sources in various ways. In October 2008, we replaced our former $300 million 364-day committed credit facility with a new facility that will allow borrowings up to $212.5 million and expires in October 2009. In December 2008, we converted AEM’s former $580 million uncommitted credit facility to a $375 million committed credit facility that will expire in December 2009. Effective April 1, 2009, we exercised the accordion feature of this facility to increase the credit available under the facility to $450 million. In addition, we replaced our $18 million unsecured committed credit facility that expired in March 2009 with a $25 million unsecured facility effective April 1, 2009. As a result of executing these new agreements, we will have a total of approximately $1.3 billion available to us under four committed credit facilities beginning April 1, 2009. As of March 31, 2009, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $998 million.

We believe the liquidity provided by our senior notes and committed credit facilities, combined with our operating cash flows, will be sufficient to fund our working capital needs and capital expenditure program for the remainder of fiscal 2009.

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 and 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 six months ended March 31, 2009, we generated operating cash flow of $614.6 million from operating activities compared with $479.2 million for the six months ended March 31, 2008. Period over period, the $135.4 million increase was attributable primarily to the favorable impact on our working capital due to the decline in natural gas prices in the current year compared to the prior-year period which increased operating cash flow by $61.2 million, coupled with a $51.9 million increase due to the favorable timing in the recovery of gas costs during the current year.

Cash flows from investing activities

In recent years, a substantial portion of our cash resources has been used to fund growth projects, our ongoing construction program and improvements to information technology 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 2009 are expected to range from $500 million to $515 million. For the six months ended March 31, 2009, capital expenditures were $221.3 million compared with $198.7 million for the six months ended March 31, 2008. The increase in capital spending primarily reflects spending for a nonregulated growth project and the construction of a pipeline extension in our regulated operations.

Cash flows from financing activities

For the six months ended March 31, 2009, our financing activities provided $46.0 million compared with a use of cash of $198.4 million in the prior-year period. Our significant financing activities for the six months ended March 31, 2009 and 2008 are summarized as follows:


	•	On March 26, 2009, we issued $450 million of 8.50% senior notes due 2019. The effective interest rate of this offering, inclusive of all debt issue costs, was 8.74 percent. After giving effect to the settlement of our $450 million Treasury lock agreement on March 23, 2009, the effective rate on these senior notes was reduced to 8.69 percent. Most of the net proceeds of approximately $446 million were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.

	•	During the six months ended March 31, 2009, we decreased our borrowings by a net $353.5 million under our short-term credit facilities compared with $150.6 million in the prior-year period. The reduction in the net borrowings reflects the timing of the use of our line of credit to finance natural gas purchases and working capital.

	•	We repaid $0.6 million of long-term debt during the six months ended March 31, 2009 compared with $2.3 million during the six months ended March 31, 2008. Payments in both periods reflected regularly scheduled payments in accordance with our various debt agreements.

	•	During the six months ended March 31, 2009, we paid $60.4 million in cash dividends compared with $58.4 million for the six months ended March 31, 2008. The increase in dividends paid over the prior-year period reflects the increase in our dividend rate from $0.65 per share during the six months ended March 31, 2008 to $0.66 per share during the six months ended March 31, 2009 combined with new share issuances under our various equity plans.

	•	During the six months ended March 31, 2009, we issued 0.6 million shares of common stock under our various equity plans, which generated net proceeds of $12.4 million. In addition, we issued 0.5 million shares of common stock under our 1998 Long-Term Incentive Plan.

The following table summarizes our share issuances for the six months ended March 31, 2009 and 2008.


	Six Months Ended
	March 31
	2009		2008

Shares issued:
Direct Stock Purchase Plan		220,361		203,025
Retirement Savings Plan and Trust		330,990		268,712
1998 Long-Term Incentive Plan		579,990		343,500
Outside Directors Stock-for-Fee Plan		1,590		1,602

Total shares issued		1,132,931		816,839

Credit Facilities

Our short-term borrowing requirements are affected by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply to meet our customers’ needs could significantly affect our borrowing requirements. However, our short-term borrowings reach their highest levels in the winter months.

We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. As of March 31, 2009, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $998 million. These facilities are described in further detail in Note 5 to the unaudited condensed consolidated financial statements.

Shelf Registration

On March 23, 2009, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in common stock and/or debt securities available for issuance, including approximately $450 million of capacity carried over from our prior shelf registration statement filed with the SEC in December 2006. Immediately following the filing of the registration statement, we issued $450 million of 8.50% senior notes due 2019 under the registration statement. Most of the net proceeds of approximately $446 million were used to repay our $400 million unsecured 4.00% senior notes, which were called on March 30, 2009 for redemption on April 30, 2009.

As of March 31, 2009, we had $450 million of availability remaining under the registration statement. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $300 million of equity securities and $150 million of subordinated debt securities.

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). In December 2008, S&P upgraded our credit rating from BBB to BBB+ and affirmed a stable outlook. S&P cited improved financial performance and rate case decisions that have increased cash flow as the key drivers for the upgrade. In January 2009, Moody’s changed our rating outlook from stable to positive. Additionally, our credit rating is currently under review for a possible upgrade by Moody’s. Fitch still maintains its stable outlook. 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

A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of the recent adverse global financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

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 March 31, 2009. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Capitalization

The following table presents our capitalization as of March 31, 2009, September 30, 2008 and March 31, 2008:


	March 31, 2009				September 30, 2008				March 31, 2008
	(In thousands, except percentages)

Short-term debt	$	—	—	%	$	350,542	7.7	%	$	—	—	%
Long-term debt		2,569,366	54.1	%		2,120,577	46.9	%		2,128,149	50.0	%
Shareholders’ equity		2,178,494	45.9	%		2,052,492	45.4	%		2,125,993	50.0	%

Total capitalization	$	4,747,860	100.0	%	$	4,523,611	100.0	%	$	4,254,142	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 54.1 percent at March 31, 2009, 54.6 percent at September 30, 2008 and 50.0 percent at March 31, 2008. 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. The increase in the debt to capital ratio compared to March 31, 2008 is due to the timing of the repayment of our $400 million unsecured 4.00% unsecured senior notes. Had we repaid the notes as of March 31, 2009, our total-debt-to-capital ratio would have been 49.9 percent. 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 six months ended March 31, 2009.

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. Testing of the salt core samples was completed in March 2009 which showed favorable conditions for development. We have filed a 7C application with the Federal Energy Regulatory Commission (FERC) to construct and operate the project and expect approval of this request in June 2009. Finally, we have engaged the services of an investment bank to assist us in determining the optimal ownership and/or development alternatives for this project, which is still in process.

Risk Management Activities

We conduct risk management activities through our natural gas distribution, natural gas marketing and pipeline, storage and other 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 and pipeline, storage and other segments, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.

The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and six months ended March 31, 2009 and 2008:


	Three Months Ended						Six Months Ended
	March 31						March 31
	2009			2008			2009			2008
	(In thousands)

Fair value of contracts at beginning of period	$	(51,314	)	$	(21,528	)	$	(63,677	)	$	(21,053	)
Contracts realized/settled		(47,231	)		(4,972	)		(100,996	)		(27,310	)
Fair value of new contracts		277			1,401			(4,006	)		(280	)
Other changes in value		76,405			34,604			146,816			58,148

Fair value of contracts at end of period	$	(21,863	)	$	9,505		$	(21,863	)	$	9,505

The fair value of our natural gas distribution segment’s financial instruments at March 31, 2009 is presented below by time period and fair value source:


	Fair Value of Contracts at March 31, 2009
	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	$	(21,859	)	$	(4	)	$	—	$	—	$	(21,863	)
Prices based on models and other valuation methods		—			—			—		—		—

Total Fair Value	$	(21,859	)	$	(4	)	$	—	$	—	$	(21,863	)

The following table shows the components of the change in fair value of our natural gas marketing segment’s financial instruments for the three and six months ended March 31, 2009 and 2008:


	Three Months Ended						Six Months Ended
	March 31						March 31
	2009			2008			2009			2008
	(In thousands)

Fair value of contracts at beginning of period	$	(28,598	)	$	51,859		$	16,542		$	26,808
Contracts realized/settled		6,972			(46,331	)		(13,275	)		(41,256	)
Fair value of new contracts		—			—			—			—
Other changes in value		(11,020	)		(28,503	)		(35,913	)		(8,527	)

Fair value of contracts at end of period		(32,646	)		(22,975	)		(32,646	)		(22,975	)
Netting of cash collateral		79,098			29,591			79,098			29,591

Cash collateral and fair value of contracts at period end	$	46,452		$	6,616		$	46,452		$	6,616

The fair value of our natural gas marketing segment’s financial instruments at March 31, 2009 is presented below by time period and fair value source:


	Fair Value of Contracts at March 31, 2009
	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	$	(42,372	)	$	9,726	$	—	$	—	$	(32,646	)
Prices based on models and other valuation methods		—			—		—		—		—

Total Fair Value	$	(42,372	)	$	9,726	$	—	$	—	$	(32,646	)

Pension and Postretirement Benefits Obligations

Effective October 1, 2008, the Company adopted the requirement under SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), that the measurement date used to determine our projected benefit and postretirement obligations and net periodic pension and postretirement costs must correspond to a fiscal year end. In accordance with the transition rules, the impact of changing the measurement date from June 30, 2008 to September 30, 2008 decreased retained earnings by $7.8 million, net of tax, decreased the unrecognized actuarial loss by $9.0 million and increased our postretirement liabilities by $3.5 million.

Further, our fiscal 2009 costs were determined using a September 30, 2008 measurement date. As of September 30, 2008, interest and corporate bond rates utilized to determine our discount rates, were significantly higher than the interest and corporate bond rates as of June 30, 2007, the measurement date for our fiscal 2008 net periodic cost. Accordingly, we increased our discount rate used to determine our fiscal 2009 pension and benefit costs to 7.57 percent. We maintained the expected return on our pension plan assets at 8.25 percent, despite the recent decline in the financial markets as we believe this rate reflects the average rate of expected earnings on plan assets that will fund our projected benefit obligation. Although the fair value of our plan assets has declined as the financial markets have declined, the impact of this decline is mitigated by the fact that assets are “smoothed” for purposes of determining net periodic pension cost. Accordingly, asset gains and losses are recognized over time as a component of net periodic pension and benefit costs for our Pension Account Plan, our largest funded plan. Therefore, our fiscal 2009 pension and postretirement medical costs were materially the same as in fiscal 2008.

For the six months ended March 31, 2009 and 2008, our total net periodic pension and other benefits cost was $24.1 million and $23.9 million. Those 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.

In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2009. Based upon this valuation, we expect we will be required to contribute less than $25 million to our pension plans by September 15, 2009. The need for this funding reflects the decline in the fair value of the plans’ assets resulting from the unfavorable market conditions experienced during the latter half of calendar year 2008. This contribution will increase the level of our plan assets to achieve a desirable PPA funding threshold. With respect to our postretirement medical plans, we anticipate contributing a total of approximately $10 million to these plans during fiscal 2009.

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

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 six-month periods ended March 31, 2009 and 2008.

Natural Gas Distribution Sales and Statistical Data


	Three Months Ended				Six Months Ended
	March 31				March 31
	2009		2008		2009		2008

METERS IN SERVICE, end of period
Residential		2,937,865		2,933,980		2,937,865		2,933,980
Commercial		274,449		275,998		274,449		275,998
Industrial		2,212		2,269		2,212		2,269
Public authority and other		9,243		8,948		9,243		8,948

Total meters		3,223,769		3,221,195		3,223,769		3,221,195

INVENTORY STORAGE BALANCE — Bcf		31.9		34.4		31.9		34.4
SALES VOLUMES — MMcf⁽¹⁾
Gas sales volumes
Residential		74,467		83,934		128,675		132,965
Commercial		36,689		40,506		65,018		67,126
Industrial		5,758		7,258		11,158		13,212
Public authority and other		4,646		3,870		8,155		7,032

Total gas sales volumes		121,560		135,568		213,006		220,335
Transportation volumes		36,169		40,938		71,454		75,791

Total throughput		157,729		176,506		284,460		296,126

OPERATING REVENUES (000’s)⁽¹⁾
Gas sales revenues
Residential	$	785,456	$	971,673	$	1,432,556	$	1,525,962
Commercial		334,815		421,708		637,509		690,177
Industrial		46,259		62,135		96,414		113,311
Public authority and other		36,991		37,244		68,385		67,848

Total gas sales revenues		1,203,521		1,492,760		2,234,864		2,397,298
Transportation revenues		16,889		17,786		32,655		32,791
Other gas revenues		10,010		11,310		18,869		19,944

Total operating revenues	$	1,230,420	$	1,521,856	$	2,286,388	$	2,450,033

Average transportation revenue per Mcf	$	0.47	$	0.43	$	0.46	$	0.43
Average cost of gas per Mcf sold	$	7.10	$	8.59	$	7.61	$	8.26

See footnote following these tables.

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


	Three Months Ended				Six Months Ended
	March 31				March 31
	2009		2008		2009		2008

CUSTOMERS, end of period
Industrial		698		716		698		716
Municipal		61		61		61		61
Other		527		474		527		474

Total		1,286		1,251		1,286		1,251

INVENTORY STORAGE BALANCE — Bcf
Natural gas marketing		20.4		19.6		20.4		19.6
Pipeline, storage and other		2.0		1.2		2.0		1.2

Total		22.4		20.8		22.4		20.8

REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf⁽¹⁾		193,356		223,476		385,528		412,340
NATURAL GAS MARKETING SALES VOLUMES — MMcf⁽¹⁾		123,066		136,677		233,724		245,386
OPERATING REVENUES (000’s)⁽¹⁾
Regulated transmission and storage	$	59,234	$	51,440	$	113,916	$	96,486
Natural gas marketing		708,658		1,128,653		1,496,153		1,969,370
Pipeline, storage and other		12,272		10,022		28,720		16,749

Total operating revenues	$	780,164	$	1,190,115	$	1,638,789	$	2,082,605

Note to preceding tables:


⁽¹⁾		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 on Form 10-K for the year ended September 30, 2008. During the six months ended March 31, 2009, there were no material changes in our quantitative and qualitative disclosures about market risk.


Item 4.	*Controls and Procedures*

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the

SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of the fiscal year ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.	*Legal Proceedings*

During the six months ended March 31, 2009, 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 other matters that were disclosed in Note 12 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2008. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.


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

At the Annual Meeting of Shareholders of Atmos Energy Corporation on February 4, 2009, 79,385,275 votes were cast as follows:


			Votes
	Votes		Withheld/		Votes
	For		Against		Abstaining

Class I Director:
Ruben E. Esquivel		77,254,669		2,130,606		—
Class II Directors:
Richard W. Cardin		77,675,895		1,709,380		—
Thomas C. Meredith		77,720,662		1,664,613		—
Nancy K. Quinn		78,057,677		1,327,598		—
Stephen R. Springer		77,027,075		2,358,200		—
Richard Ware II		77,735,952		1,649,323		—
Ratification of the Audit Committee’s engagement of Ernst & Young LLP to serve as the Company’s registered independent public accounting firm for fiscal year 2009		78,424,677		767,618		192,980
Shareholder proposal regarding declassification of the Board of Directors		45,212,206		17,596,650		527,384

Mr. Dan Busbee, a Class I director, retired on February 4, 2009, at the conclusion of the Annual Meeting of Shareholders, in accordance with the Board’s mandatory retirement policy. The remaining directors will continue to serve until the expiration of their terms. The term of the Class I directors, Travis W. Bain II, Richard W. Douglas, Ruben E. Esquivel and Richard K. Gordon, will expire in 2011. The term of the Class II directors, Richard W. Cardin, Thomas C. Meredith, Nancy K. Quinn, Stephen R. Springer and Richard Ware II, will expire in 2012. The term of the Class III directors, Robert W. Best, Thomas J. Garland, Phillip E. Nichol and Charles K. Vaughan, will expire in 2010.


Item 6.	*Exhibits*

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

SIGNATURE

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/ Fred E. Meisenheimer

Fred E. Meisenheimer

Senior Vice President, Chief Financial

Officer and Controller

(Duly authorized signatory)

Date: May 1, 2009

EXHIBITS INDEX
Item 6


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 on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.