ATO 10-Q Quarterly Report June 30, 2010

ATMOS ENERGY CORP

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10-Q 1 d74537e10vq.htm FORM 10-Q 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 June 30, 2010
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 (State or other jurisdiction of incorporation or organization)		75-1743247 (IRS employer identification no.)
Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas (Address of principal executive offices)		75240 (Zip code)

(972) 934-9227

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its website, 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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” 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 July 29, 2010.


Class		Shares Outstanding

No Par Value		90,154,801

TABLE OF CONTENTS


GLOSSARY OF KEY TERMS
PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
CONDENSED CONSOLIDATED BALANCE SHEETS
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	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 6. Exhibits
SIGNATURE
EXHIBITS INDEX
EX-12
EX-15
EX-31
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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.
GRIP		Gas Reliability Infrastructure Program
GSRS		Gas System Reliability Surcharge
ISRS		Infrastructure System Replacement Surcharge
Mcf		Thousand cubic feet
MMcf		Million cubic feet
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
WNA		Weather Normalization Adjustment

PART I. FINANCIAL INFORMATION


Item 1.	*Financial Statements*

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,			September 30,
	2010			2009
	(Unaudited)
	(In thousands, except
	share data)

ASSETS
Property, plant and equipment	$	6,402,065		$	6,086,618
Less accumulated depreciation and amortization		1,733,022			1,647,515

Net property, plant and equipment		4,669,043			4,439,103
Current assets
Cash and cash equivalents		180,383			111,203
Accounts receivable, net		299,835			232,806
Gas stored underground		263,752			352,728
Other current assets		130,003			132,203

Total current assets		873,973			828,940
Goodwill and intangible assets		739,593			740,064
Deferred charges and other assets		303,041			335,659

	$	6,585,650		$	6,343,766


CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share);
200,000,000 shares authorized; issued and outstanding:
June 30, 2010 — 93,112,688 shares;
September 30, 2009 — 92,551,709 shares	$	466		$	463
Additional paid-in capital		1,812,088			1,791,129
Retained earnings		515,742			405,353
Accumulated other comprehensive loss		(14,566	)		(20,184	)

Shareholders’ equity		2,313,730			2,176,761
Long-term debt		1,809,546			2,169,400

Total capitalization		4,123,276			4,346,161
Current liabilities
Accounts payable and accrued liabilities		254,150			207,421
Other current liabilities		393,478			457,319
Short-term debt		—			72,550
Current maturities of long-term debt		360,131			131

Total current liabilities		1,007,759			737,421
Deferred income taxes		755,722			570,940
Regulatory cost of removal obligation		314,708			321,086
Deferred credits and other liabilities		384,185			368,158

	$	6,585,650		$	6,343,766

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended
	June 30
	2010			2009
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	405,271		$	386,985
Regulated transmission and storage segment		44,957			49,345
Natural gas marketing segment		421,406			453,504
Pipeline, storage and other segment		8,196			8,226
Intersegment eliminations		(109,573	)		(117,285	)

		770,257			780,775
Purchased gas cost
Natural gas distribution segment		208,378			195,303
Regulated transmission and storage segment		—			—
Natural gas marketing segment		415,101			438,482
Pipeline, storage and other segment		2,730			4,212
Intersegment eliminations		(109,180	)		(116,862	)

		517,029			521,135

Gross profit		253,228			259,640
Operating expenses
Operation and maintenance		113,348			110,895
Depreciation and amortization		53,288			54,181
Taxes, other than income		52,483			47,577
Asset impairments		—			3,304

Total operating expenses		219,119			215,957

Operating income		34,109			43,683
Miscellaneous income (expense)		(850	)		1,219
Interest charges		37,290			41,511

Income (loss) before income taxes		(4,031	)		3,391
Income tax expense (benefit)		(877	)		1,427

Net income (loss)	$	(3,154	)	$	1,964

Basic net income (loss) per share	$	(0.03	)	$	0.02

Diluted net income (loss) per share	$	(0.03	)	$	0.02

Cash dividends per share	$	0.335		$	0.330

Weighted average shares outstanding:
Basic		92,648			91,338

Diluted		92,648			91,652

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Nine Months Ended
	June 30
	2010			2009
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	2,574,153		$	2,673,373
Regulated transmission and storage segment		146,998			163,261
Natural gas marketing segment		1,657,829			1,949,657
Pipeline, storage and other segment		28,869			36,946
Intersegment eliminations		(404,474	)		(504,724	)

		4,003,375			4,318,513
Purchased gas cost
Natural gas distribution segment		1,697,248			1,816,227
Regulated transmission and storage segment		—			—
Natural gas marketing segment		1,585,259			1,881,068
Pipeline, storage and other segment		5,732			9,771
Intersegment eliminations		(403,262	)		(503,456	)

		2,884,977			3,203,610

Gross profit		1,118,398			1,114,903
Operating expenses
Operation and maintenance		354,298			365,312
Depreciation and amortization		160,207			160,757
Taxes, other than income		154,648			150,028
Asset impairments		—			5,382

Total operating expenses		669,153			681,479

Operating income		449,245			433,424
Miscellaneous expense		(1,070	)		(647	)
Interest charges		115,580			116,035

Income before income taxes		332,595			316,742
Income tax expense		128,293			109,812

Net income	$	204,302		$	206,930

Basic net income per share	$	2.19		$	2.25

Diluted net income per share	$	2.18		$	2.25

Cash dividends per share	$	1.005		$	0.990

Weighted average shares outstanding:
Basic		92,513			90,940

Diluted		92,856			91,246

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	June 30
	2010			2009
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities
Net income	$	204,302		$	206,930
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		160,207			160,757
Charged to other accounts		116			60
Deferred income taxes		186,325			62,658
Other		18,425			23,009
Net assets / liabilities from risk management activities		3,429			53,711
Net change in operating assets and liabilities		21,760			317,469

Net cash provided by operating activities		594,564			824,594
Cash Flows From Investing Activities
Capital expenditures		(362,349	)		(342,326	)
Other, net		(438	)		(6,094	)

Net cash used in investing activities		(362,787	)		(348,420	)
Cash Flows From Financing Activities
Net decrease in short-term debt		(76,019	)		(366,449	)
Net proceeds from issuance of long-term debt		—			445,623
Settlement of Treasury lock agreement		—			1,938
Repayment of long-term debt		(66	)		(407,287	)
Cash dividends paid		(93,913	)		(90,909	)
Repurchase of equity awards		(1,173	)		—
Issuance of common stock		8,574			19,928

Net cash used in financing activities		(162,597	)		(397,156	)

Net increase in cash and cash equivalents		69,180			79,018
Cash and cash equivalents at beginning of period		111,203			46,717

Cash and cash equivalents at end of period	$	180,383		$	125,735

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2010


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. Our corporate headquarters and shared-services function are located in Dallas, Texas and our customer support centers are located in Amarillo and Waco, Texas.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three 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. Our regulated activities also include our regulated pipeline and storage operations, which include the transportation of natural gas to our distribution system and the management of our underground storage facilities. Our natural gas distribution and regulated pipeline and storage businesses are 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 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. Through our nonregulated businesses, we primarily provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers and natural gas transportation and storage services to certain of our natural gas distribution divisions and 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 our 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.


2.	Unaudited Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009. 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, 2009. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2010 are not indicative of our results of operations for the full 2010 fiscal year, which ends September 30, 2010.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We have evaluated subsequent events from the June 30, 2010 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). On July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman, Sachs & Co. to repurchase $100 million of our outstanding common stock. The agreement is designed to offset stock grants made under various employee and director incentive compensation plans. The specific number of shares that we will ultimately repurchase in the transaction will be based generally on the average of the daily volume-weighted average share price of our common stock over the duration of the agreement. The agreement is scheduled to end in March 2011, although the termination date may be accelerated. As a result of this transaction, our weighted-average shares outstanding will be reduced over the remaining three months of fiscal 2010.

Except for the accelerated share repurchase agreement, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.

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, 2009.

During the second quarter of fiscal 2010, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

During the nine months ended June 30, 2010, six new accounting standards became applicable to the Company. Except as indicated below, the adoption of these standards did not have a material impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies during the nine months ended June 30, 2010.

The determination of participating securities in the basic earnings per share calculation — The Financial Accounting Standards Board (FASB) issued guidance related to determining whether instruments granted in share-based payment transactions are considered participating securities. The FASB determined that non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents are participating securities and, as a result, companies with these types of participating securities must use the two-class method to compute earnings per share. Based on this guidance, the Company is required to calculate earnings per share using the two-class method and will include non-vested restricted stock and restricted stock units for which vesting is only predicated upon the passage of time in the basic earnings per share calculation. Non-vested restricted stock and restricted stock units for which vesting is predicated, in part upon the achievement of specified performance targets, continue to be excluded from the calculation of earnings per share. Although the provisions of this standard were effective for us as of October 1, 2009, prior-period earnings per share data must be recalculated and adjusted accordingly. The calculation of basic and diluted earnings per share pursuant

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

to the two-class method is presented in Note 6. The application of the two-class method resulted in the following changes to basic and diluted earnings per share for the three and nine months ended June 30, 2009.


	Three Months Ended		Nine Months Ended
	June 30, 2009		June 30, 2009
	(In thousands, except per share amounts)

Basic Earnings Per Share
Basic EPS — as previously reported	$	0.02	$	2.28
Basic EPS — as adjusted	$	0.02	$	2.25
Weighted average shares outstanding — as previously reported		91,338		90,940
Weighted average shares outstanding — as adjusted		91,338		90,940
Diluted Earnings Per Share
Diluted EPS — as previously reported	$	0.02	$	2.26
Diluted EPS — as adjusted	$	0.02	$	2.25
Weighted average shares outstanding — as previously reported		92,002		91,590
Weighted average shares outstanding — as adjusted		91,652		91,246

Fair value measurements of plan assets of a defined benefit pension or other postretirement plan — This guidance requires employers to disclose annually information about fair value measurements of the assets of a defined benefit pension or other postretirement plan in a manner similar to the requirements established for financial and non-financial assets. The objectives of the required disclosures are to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure fair value of plan assets and significant concentrations of risk within plan assets. These disclosures will appear in our Form 10-K for the year ending September 30, 2010.

Measurement of liabilities at fair value — This guidance requires that, effective October 1, 2009, when a quoted price in an active market for an identical liability is not available, we will be required to measure fair value using a valuation technique that uses quoted prices of similar liabilities, quoted prices of identical or similar liabilities when traded as assets, or another valuation technique that is consistent with U.S. generally accepted accounting principles (GAAP), such as the income or market approach. Additionally, when estimating the fair value of a liability, we will not be required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents our transfer of the liability. The adoption of this guidance did not impact our financial position, results of operations or cash flows.

Business combination accounting — Effective October 1, 2009, this new pronouncement established new principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. This update significantly changes the accounting for business combinations in a number of areas, including the treatment of contingent consideration, preacquisition contingencies, transaction costs and restructuring costs. In addition, under the new guidelines, changes in an acquired entity’s deferred tax assets and uncertain tax positions after the measurement period will impact current period income tax expense.

Accounting and reporting for minority interests — In December 2007, the FASB issued guidance related to the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity. This new consolidation method significantly changed the accounting for transactions with minority interest holders beginning October 1, 2009. As of June 30, 2010, Atmos Energy did not have any transactions with minority interest holders.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair value disclosures — The FASB issued guidance that requires new disclosures surrounding fair value measurements to enhance the existing disclosure requirements including 1) information about transfers in and out of Level 1 and Level 2 fair value measurements as well as a detailed reconciliation of activity in Level 3 fair value measurements; 2) a more detailed level of disaggregation for each class of assets and liabilities; and 3) a requirement to disclose information about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements that fall in either Level 2 or Level 3. The new disclosures and clarifications of existing disclosures became effective for us on January 1, 2010, except for the disclosures related to the detailed reconciliation of Level 3 fair value measurements, which will become effective for us on October 1, 2011. As a result of adopting this standard, beginning in our second fiscal quarter we added a disclosure about the valuation techniques and inputs we used to measure fair value for our Level 2 recurring and nonrecurring fair value measurements which is included in Note 4. As of June 30, 2010, we did not have any Level 3 fair value measurements.

Regulatory assets and liabilities

Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets 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.

Significant regulatory assets and liabilities as of June 30, 2010 and September 30, 2009 included the following:


	June 30,		September 30,
	2010		2009
	(In thousands)

Regulatory assets:
Pension and postretirement benefit costs	$	189,566	$	197,743
Merger and integration costs, net		6,826		7,161
Deferred gas costs		678		22,233
Environmental costs		851		866
Rate case costs		3,991		5,923
Deferred franchise fees		466		10,014
Deferred income taxes, net		639		639
Other		762		6,218

	$	203,779	$	250,797

Regulatory liabilities:
Deferred gas costs	$	56,463	$	110,754
Regulatory cost of removal obligation		343,765		335,428
Other		6,257		7,960

	$	406,485	$	454,142

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Comprehensive income

The following table presents the components of comprehensive income, net of related tax, for the three-month and nine-month periods ended June 30, 2010 and 2009:


	Three Months Ended					Nine Months Ended
	June 30					June 30
	2010			2009		2010			2009
	(In thousands)

Net income (loss)	$	(3,154	)	$	1,964	$	204,302		$	206,930
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $(996) and $1,282 for the three months ended June 30, 2010 and 2009 and of $(198) and $(2,477) for the nine months ended June 30, 2010 and 2009		(1,696	)		2,086		(337	)		(4,209	)
Other than temporary impairment of investments, net of tax expense of $1,222 and $2,012 for the three and nine months ended June 30, 2009		—			2,082		—			3,370
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $247 and $320 for the three months ended June 30, 2010 and 2009 and $743 and $2,155 for the nine months ended June 30, 2010 and 2009		422			543		1,265			3,184
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $5,066 and $16,582 for the three months ended June 30, 2010 and 2009 and $2,999 and $(4,759) for the nine months ended June 30, 2010 and 2009		7,921			25,936		4,690			(6,379	)

Comprehensive income	$	3,493		$	32,611	$	209,920		$	202,896

Accumulated other comprehensive loss, net of tax, as of June 30, 2010 and September 30, 2009 consisted of the following unrealized gains (losses):


	June 30,			September 30,
	2010			2009
	(In thousands)

Accumulated other comprehensive loss:
Unrealized holding gains on investments	$	2,123		$	2,460
Treasury lock agreements		(6,233	)		(7,498	)
Cash flow hedges		(10,456	)		(15,146	)

	$	(14,566	)	$	(20,184	)

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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, 2009. Currently, we utilize financial instruments in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. However, our pipeline, storage and other segment uses financial instruments acquired from Atmos Energy Marketing, LLC (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

Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, 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. Historically, 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 2009-2010 heating season, in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 29 percent, or 26.9 Bcf of the planned winter flowing gas requirements. We have not designated these financial instruments as hedges.

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 applicable authoritative accounting guidance. Accordingly, there is no earnings impact on 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 pricing differences that occur over time. We purchase physical natural gas and then sell financial instruments at advantageous prices to

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

lock in a gross profit margin. 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 inventory should 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 49 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in our asset optimization activities in our natural gas marketing and pipeline, storage and other segments.

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.

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. A risk 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. Our operations 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 June 30, 2010, AEH had net open positions (including existing storage) of 0.3 Bcf.

Interest Rate Risk Management Activities

Currently, we are not managing interest rate risk with financial instruments. However, in prior years, we periodically 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 cumulative 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 associated with these Treasury locks will be recognized by the end of fiscal 2019.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2010, 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 June 30, 2010, we had net long/(short) commodity contracts outstanding in the following quantities:


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

Commodity contracts	Fair Value		—		(19,288	)		(1,710	)
	Cash Flow		—		26,768			(2,580	)
	Not designated		24,772		37,278			2,620

			24,772		44,758			(1,670	)

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 June 30, 2010 and September 30, 2009. As required by authoritative accounting literature, 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 $18.0 million and $11.7 million of cash held on deposit in margin accounts as of June 30, 2010 and September 30, 2009 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 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)

June 30, 2010
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	19,181		$	19,181
Noncurrent commodity contracts	Deferred charges and other assets		—			3,893			3,893
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(33,480	)		(33,480	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(5,100	)		(5,100	)

Total			—			(15,506	)		(15,506	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		1,048			23,299			24,347
Noncurrent commodity contracts	Deferred charges and other assets		46			2,482			2,528
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(21,209	)		(12,254	)		(33,463	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(275	)		(231	)		(506	)

Total			(20,390	)		13,296			(7,094	)

Total Financial Instruments		$	(20,390	)	$	(2,210	)	$	(22,600	)


⁽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)


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

September 30, 2009
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	53,526		$	53,526
Noncurrent commodity contracts	Deferred charges and other assets		—			6,800			6,800
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(47,146	)		(47,146	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(999	)		(999	)

Total			—			12,181			12,181
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		4,395			27,559			31,954
Noncurrent commodity contracts	Deferred charges and other assets		1,620			7,964			9,584
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(20,181	)		(19,657	)		(39,838	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(1,349	)		(1,349	)

Total			(14,166	)		14,517			351

Total Financial Instruments		$	(14,166	)	$	26,698		$	12,532


⁽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.

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 nine months ended June 30, 2010 and 2009.

Hedge ineffectiveness for our natural gas marketing and pipeline storage and other segments is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended June 30, 2010 and 2009 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.8 million and $0.2 million. For the nine months ended June 30, 2010 and 2009 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $44.2 million and $24.7 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 nine months ended June 30, 2010 and 2009 is presented below.


	Three Months Ended June 30, 2010
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
	(In thousands)

Commodity contracts	$	(9,923	)	$	(602	)	$	(10,525	)
Fair value adjustment for natural gas inventory designated as the hedged item		13,654			1,024			14,678

Total impact on revenue	$	3,731		$	422		$	4,153

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(235	)	$	—		$	(235	)
Timing ineffectiveness		3,966			422			4,388

	$	3,731		$	422		$	4,153


	Three Months Ended June 30, 2009
	Natural		Pipeline,
	Gas		Storage and
	Marketing		Other			Consolidated
	(In thousands)

Commodity contracts	$	2,710	$	1,390		$	4,100
Fair value adjustment for natural gas inventory designated as the hedged item		3,929		(741	)		3,188

Total impact on revenue	$	6,639	$	649		$	7,288

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	678	$	—		$	678
Timing ineffectiveness		5,961		649			6,610

	$	6,639	$	649		$	7,288


	Nine Months Ended June 30, 2010
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other		Consolidated
	(In thousands)

Commodity contracts	$	18,820		$	1,476	$	20,296
Fair value adjustment for natural gas inventory designated as the hedged item		21,997			4,198		26,195

Total impact on revenue	$	40,817		$	5,674	$	46,491

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(684	)	$	—	$	(684	)
Timing ineffectiveness		41,501			5,674		47,175

	$	40,817		$	5,674	$	46,491

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30, 2009
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
	(In thousands)

Commodity contracts	$	48,263		$	7,435		$	55,698
Fair value adjustment for natural gas inventory designated as the hedged item		(26,493	)		(2,731	)		(29,224	)

Total impact on revenue	$	21,770		$	4,704		$	26,474

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	4,958		$	—		$	4,958
Timing ineffectiveness		16,812			4,704			21,516

	$	21,770		$	4,704		$	26,474

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.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2010 and 2009 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 or will realize when the underlying physical and financial transactions are settled.


	Three Months Ended June 30, 2010
	Natural						Pipeline,
	Gas			Natural Gas			Storage and
	Distribution			Marketing			Other		Consolidated
	(In thousands)

Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(8,523	)	$	—	$	(8,523	)
Loss arising from ineffective portion of commodity contracts		—			(350	)		—		(350	)

Total impact on revenue		—			(8,873	)		—		(8,873	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(669	)		—			—		(669	)

Total Impact from Cash Flow Hedges	$	(669	)	$	(8,873	)	$	—	$	(9,542	)

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended June 30, 2009
	Natural						Pipeline,
	Gas			Natural Gas			Storage and
	Distribution			Marketing			Other			Consolidated
	(In thousands)

Loss reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(36,669	)	$	(2,503	)	$	(39,172	)
Loss arising from ineffective portion of commodity contracts		—			(7,120	)		—			(7,120	)

Total impact on revenue		—			(43,789	)		(2,503	)		(46,292	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(863	)		—			—			(863	)

Total Impact from Cash Flow Hedges	$	(863	)	$	(43,789	)	$	(2,503	)	$	(47,155	)


	Nine Months Ended June 30, 2010
	Natural						Pipeline,
	Gas			Natural Gas			Storage and
	Distribution			Marketing			Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(43,079	)	$	2,883	$	(40,196	)
Loss arising from ineffective portion of commodity contracts		—			(2,307	)		—		(2,307	)

Total impact on revenue		—			(45,386	)		2,883		(42,503	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(2,008	)		—			—		(2,008	)

Total Impact from Cash Flow Hedges	$	(2,008	)	$	(45,386	)	$	2,883	$	(44,511	)


	Nine Months Ended June 30, 2009
	Natural						Pipeline,
	Gas			Natural Gas			Storage and
	Distribution			Marketing			Other		Consolidated
	(In thousands)

Gain (loss) reclassified from AOCI into revenue for effective portion of commodity contracts	$	—		$	(142,986	)	$	25,213	$	(117,773	)
Loss arising from ineffective portion of commodity contracts		—			(1,748	)		—		(1,748	)

Total impact on revenue		—			(144,734	)		25,213		(119,521	)
Net loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(3,401	)		—			—		(3,401	)

Total Impact from Cash Flow Hedges	$	(3,401	)	$	(144,734	)	$	25,213	$	(122,922	)

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2010 and 2009. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.


	Three Months Ended				Nine Months Ended
	June 30				June 30
	2010		2009		2010			2009
	(In thousands)

Increase (decrease) in fair value:
Treasury lock agreements	$	—	$	—	$	—		$	1,221
Forward commodity contracts		2,722		2,041		(19,829	)		(78,220	)
Recognition of losses in earnings due to settlements:
Treasury lock agreements		422		543		1,265			1,963
Forward commodity contracts		5,199		23,895		24,519			71,841

Total other comprehensive income (loss) from hedging, net of tax ⁽¹⁾	$	8,343	$	26,479	$	5,955		$	(3,195	)


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

Deferred losses recorded in AOCI associated with our treasury lock agreements are recognized in earnings as they are amortized, while deferred losses associated with commodity contracts are recognized in earnings upon settlement. 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 June 30, 2010:


	Treasury
	Lock			Commodity
	Agreements			Contracts			Total
	(In thousands)

Next twelve months	$	(1,687	)	$	(7,081	)	$	(8,768	)
Thereafter		(4,546	)		(3,375	)		(7,921	)

Total ⁽¹⁾	$	(6,233	)	$	(10,456	)	$	(16,689	)


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

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 nine months ended June 30, 2010 and 2009 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 on 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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						Nine Months Ended
	June 30						June 30
	2010			2009			2010		2009
	(In thousands)

Natural gas marketing commodity contracts	$	(6	)	$	6,167		$	12,457	$	12,928
Pipeline, storage and other commodity contracts		704			(6,853	)		536		(6,753	)

Total impact on revenue	$	698		$	(686	)	$	12,993	$	6,175


4.	Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined 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 record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009. During the three and nine months ended June 30, 2010, there were no changes in these methods.

Effective October 1, 2009, the authoritative guidance related to nonrecurring fair value measurements became effective for us with respect to asset retirement obligations, most nonfinancial assets and liabilities that may be acquired in a business combination and impairment analyses performed for nonfinancial assets. The adoption of the FASB’s fair value guidance for the reporting of these nonrecurring fair value measurements did not have a material impact on our financial position, results of operations or cash flows for the three and nine months ended June 30, 2010.

Although fair value measurements also apply to the valuation of our pension and post-retirement plan assets, the current fair value disclosure requirements are not applicable to our pension and post-retirement plan assets. Accordingly, these plan assets are not included in the tabular disclosures below. However, similar disclosures about fair value measurements for our pension and post-retirement plan assets will appear in our Form 10-K for the year ending September 30, 2010.

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. Authoritative accounting literature 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), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 and

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2009. 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			June 30,
	(Level 1)		(Level 2) ⁽¹⁾		(Level 3)		Collateral ⁽²⁾			2010
	(In thousands)

Assets:
Financial instruments
Natural gas distribution segment	$	—	$	1,094	$	—	$	—		$	1,094
Natural gas marketing segment		10,902		37,952		—		(27,266	)		21,588

Total financial instruments		10,902		39,046		—		(27,266	)		22,682
Hedged portion of gas stored underground
Natural gas marketing segment		84,723		—		—		—			84,723
Pipeline, storage and other segment ⁽³⁾		7,112		—		—		—			7,112

Total gas stored underground		91,835		—		—		—			91,835
Available-for-sale securities		38,972		—		—		—			38,972

Total assets	$	141,709	$	39,046	$	—	$	(27,266	)	$	153,489

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	21,484	$	—	$	—		$	21,484
Natural gas marketing segment		29,045		22,019		—		(45,283	)		5,781

Total liabilities	$	29,045	$	43,503	$	—	$	(45,283	)	$	27,265

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Quoted		Significant		Significant
	Prices in		Other		Other
	Active		Observable		Unobservable		Netting and
	Markets		Inputs		Inputs		Cash			September 30,
	(Level 1)		(Level 2) ⁽¹⁾		(Level 3)		Collateral ⁽²⁾			2009
	(In thousands)

Assets:
Financial instruments
Natural gas distribution segment	$	—	$	6,015	$	—	$	—		$	6,015
Natural gas marketing segment		34,281		61,568		—		(56,186	)		39,663

Total financial instruments		34,281		67,583		—		(56,186	)		45,678
Hedged portion of gas stored underground
Natural gas marketing segment		47,967		—		—		—			47,967
Pipeline, storage and other segment ⁽³⁾		6,789		—		—		—			6,789

Total gas stored underground		54,756		—		—		—			54,756
Available-for-sale securities		41,699		—		—		—			41,699

Total assets	$	130,736	$	67,583	$	—	$	(56,186	)	$	142,133

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	20,181	$	—	$	—		$	20,181
Natural gas marketing segment		48,268		20,883		—		(67,850	)		1,301

Total liabilities	$	48,268	$	41,064	$	—	$	(67,850	)	$	21,482


⁽¹⁾		Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps where market data for pricing is observable. The fair values for these assets and liabilities are determined using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences.

⁽²⁾		This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and authoritative accounting literature. In addition, as of June 30, 2010 and September 30, 2009 we had $18.0 million and $11.7 million of cash held in margin accounts used to collateralize certain financial instruments which has been reflected as a financial instrument asset.

⁽³⁾		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

Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations. The following table presents the carrying value and fair value of our debt as of June 30, 2010:


	June 30,
	2010
	(In thousands)

Carrying Amount	$	2,172,761
Fair Value	$	2,406,975


5.	Debt

Long-term debt

Long-term debt at June 30, 2010 and September 30, 2009 consisted of the following:


	June 30,			September 30,
	2010			2009
	(In thousands)

Unsecured 7.375% Senior Notes, due May 2011	$	350,000		$	350,000
Unsecured 10% Notes, due December 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			450,000
Unsecured 5.95% Senior Notes, due 2034		200,000			200,000
Medium term notes
Series A, 1995-2, 6.27%, due December 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
Rental property term note due in installments through 2013		458			524

Total long-term debt		2,172,761			2,172,827
Less:
Original issue discount on unsecured senior notes and debentures		(3,084	)		(3,296	)
Current maturities		(360,131	)		(131	)

	$	1,809,546		$	2,169,400

As noted above, our Unsecured 7.375% Senior Notes will mature in May 2011 and our Series A, 1995-2, 6.27% medium term notes will mature in December 2010; accordingly, these have been classified within the current maturities of long-term debt.

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 typically reach their highest levels in the winter months.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2010, there were no short-term debt borrowings outstanding. At September 30, 2009, there was a total of $72.6 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 our 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 $566.7 million unsecured facility, expiring December 15, 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 June 30, 2010, there were no borrowings under this facility nor was there any commercial paper outstanding.

The second facility is a $200 million unsecured 364-day facility that expires October 22, 2010. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 1.75 percent to 3.00 percent, based on the Company’s credit ratings. At June 30, 2010, there were no borrowings outstanding under this facility.

The third facility is a $25 million unsecured facility that bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin. At June 30, 2010, there were no borrowings outstanding under this facility. This facility expired on March 31, 2010 and was replaced with a $25 million unsecured facility effective April 1, 2010 that also bears interest at a daily negotiated rate, generally based on the Federal Funds rate plus a variable margin.

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 June 30, 2010, our total-debt-to-total-capitalization ratio, as defined, was 51 percent. In addition, both the interest margin over the Eurodollar rate and the fees 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, the Company has a $200 million intercompany revolving credit facility provided by AEH. This facility 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, (ii) a rate based upon the lower of the Prime Rate or the Eurodollar rate under the 364-day revolving credit facility or (iii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2010. There was $67.4 million outstanding under this facility at June 30, 2010.

Nonregulated Operations

On December 10, 2009, AEM and the participating banks amended and restated AEM’s $450 million committed revolving credit facility extending it to December 9, 2010.

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 three-month interest period) as in effect from time to time; and (d) the “cost of funds” rate which is the cost of funds as reasonably determined by the administrative agent plus 0.50 percent. 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 has swing line loan features, which allow 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. This facility is collateralized by substantially all of the assets of AEM and is guaranteed by AEH.

At June 30, 2010, there were no borrowings outstanding under this credit facility. However, at June 30, 2010, AEM letters of credit totaling $22.7 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 $159.6 million at June 30, 2010.

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 June 30, 2010, AEM’s ratio of total liabilities to tangible net worth, as defined, was 1.12 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 covenants, at June 30, 2010, AEM’s net working capital was $166.8 million and its tangible net worth was $179.4 million.

To supplement borrowings under this facility, AEM has a $300 million intercompany demand credit facility with AEH, which bears interest at the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) 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. There were no borrowings outstanding under this facility at June 30, 2010.

Finally, AEH has a $200 million intercompany demand credit facility with AEC, which bears interest at greater of (i) the one-month LIBOR rate plus 3.00 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, 2010. There were no borrowings outstanding under this facility at June 30, 2010.

Shelf Registration

On March 31, 2010, we filed a registration statement with the SEC to issue, from time to time, up to $1.3 billion in common stock and/or debt securities available for issuance.

We received approvals from all requisite state regulatory commissions to issue a total of $1.3 billion in common stock and/or debt securities under the new shelf registration statement, including the carryforward of the $450 million of securities remaining available for issuance under our shelf registration statement filed with the SEC on March 23, 2009. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we will be able to issue a total of $950 million in debt securities and $350 million in equity securities.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Debt Covenants

In addition to the financial covenants described above, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.

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.

We were in compliance with all of our debt covenants as of June 30, 2010. 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

As discussed in Note 2, since we have non-vested share-based payments with a nonforfeitable right to dividends or dividend equivalents (referred to as participating securities) we are required to use the two-class method of computing earnings per share as of October 1, 2009. The Company’s non-vested restricted stock and restricted stock units, granted under the 1998 Long-Term Incentive Plan, for which vesting is predicated solely on the passage of time, are considered to be participating securities. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. The presentation of earnings per share for previously reported periods has been adjusted to reflect the retrospective adoption of this

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

standard. Basic and diluted earnings per share for the three and nine months ended June 30, 2010 and 2009 are calculated as follows:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2010			2009			2010		2009
	(In thousands, except per share amounts)

Basic Earnings Per Share
Net income (loss)	$	(3,154	)	$	1,964		$	204,302	$	206,930
Less: Income (loss) allocated to participating securities		(38	)		13			2,082		1,955

Net income (loss) available to common shareholders	$	(3,116	)	$	1,951		$	202,220	$	204,975

Basic weighted average shares outstanding		92,648			91,338			92,513		90,940

Net income (loss) per share — Basic	$	(0.03	)	$	0.02		$	2.19	$	2.25

Diluted Earnings Per Share
Net income (loss) available to common shareholders	$	(3,116	)	$	1,951		$	202,220	$	204,975
Effect of dilutive stock options and other shares		—			(1	)		4		4

Net income (loss) available to common shareholders	$	(3,116	)	$	1,950		$	202,224	$	204,979

Basic weighted average shares outstanding		92,648			91,338			92,513		90,940
Additional dilutive stock options and other shares		—			314			343		306

Diluted weighted average shares outstanding		92,648			91,652			92,856		91,246

Net income (loss) per share — Diluted	$	(0.03	)	$	0.02		$	2.18	$	2.25

There were approximately 333,000 stock options that were excluded from the calculation of diluted earnings per share for the three months ended June 30, 2010 as their inclusion in the computation would be anti-dilutive.

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the nine months ended June 30, 2010 as their exercise price was less than the average market price of the common stock during that period. There were approximately 33,000 and 132,000 out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2009.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended June 30, 2010 and 2009 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.


	Three Months Ended June 30
	Pension Benefits						Other Benefits
	2010			2009			2010			2009
	(In thousands)

Components of net periodic pension cost:
Service cost	$	3,993		$	3,703		$	3,360		$	2,946
Interest cost		6,524			7,554			3,018			3,520
Expected return on assets		(6,320	)		(6,238	)		(615	)		(573	)
Amortization of transition asset		—			—			377			378
Amortization of prior service cost		(193	)		(183	)		(375	)		—
Amortization of actuarial loss		2,822			955			93			—

Net periodic pension cost	$	6,826		$	5,791		$	5,858		$	6,271


	Nine Months Ended June 30
	Pension Benefits						Other Benefits
	2010			2009			2010			2009
	(In thousands)

Components of net periodic pension cost:
Service cost	$	11,982		$	11,109		$	10,077		$	8,838
Interest cost		19,569			22,662			9,051			10,560
Expected return on assets		(18,960	)		(18,714	)		(1,845	)		(1,719	)
Amortization of transition asset		—			—			1,134			1,134
Amortization of prior service cost		(582	)		(549	)		(1,125	)		—
Amortization of actuarial loss		8,469			2,865			282			—

Net periodic pension cost	$	20,478		$	17,373		$	17,574		$	18,813

The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2010 and 2009 are as follows:


	Pension Benefits						Other Benefits
	2010			2009			2010			2009

Discount rate		5.52	%		7.57	%		5.52	%		7.57	%
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, 2010. Based upon this valuation, we will not be required to contribute to our pension plans during fiscal 2010.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We contributed $9.1 million to our other post-retirement benefit plans during the nine months ended June 30, 2010. We expect to contribute a total of approximately $12 million to these plans during fiscal 2010.

For our Supplemental Executive Retirement Plans, we own equity securities that are classified as available-for-sale securities. These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.

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


			Gross		Gross
	Amortized		Unrealized		Unrealized
	Cost		Gain		Loss			Fair Value
	(In thousands)

As of June 30, 2010:
Domestic equity mutual funds	$	29,379	$	3,212	$	—		$	32,591
Foreign equity mutual funds		4,753		205		(47	)		4,911
Money market funds		1,470		—		—			1,470

	$	35,602	$	3,417	$	(47	)	$	38,972

As of September 30, 2009:
Domestic equity mutual funds	$	26,012	$	3,012	$	—		$	29,024
Foreign equity mutual funds		4,047		893		—			4,940
Money market funds		7,735		—		—			7,735

	$	37,794	$	3,905	$	—		$	41,699

During the three and nine months ended June 30, 2009, we recorded a $3.3 million and $5.4 million noncash charge to impair certain available-for-sale investments due to the deterioration of the financial markets and the uncertainty of a full recovery.

At June 30, 2010, we maintained an investment in one foreign equity mutual fund that was in an unrealized loss position. This fund has been in an unrealized loss position for less than 12 months as of June 30, 2010. Because this fund is only used to fund the supplemental plans, we evaluate investment performance over a long-term horizon. Based on our intent and ability to hold this investment, our ability to direct the source of the payments in order to maximize the life of the portfolio, the short-term nature of the decline in fair value and the fact that this fund continues to receive good ratings from mutual fund rating companies, we do not consider this impairment to be other than temporary as of June 30, 2010.


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, 2009, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2010. 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 or response actions to such environmental-related matters or claims cannot be predicted with certainty, we believe the final outcome of such litigation or response actions will not have a material adverse effect on our financial condition, results of operations or cash flows.

Purchase Commitments

AEM has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2010, AEM was committed to purchase 77.8 Bcf within one year, 11.4 Bcf within one to three years and 2.1 Bcf after three years under indexed contracts. AEM is committed to purchase 2.1 Bcf within one year, 0.8 Bcf within one to three years and 0.1 Bcf after three years under fixed price contracts with prices ranging from $4.03 to $6.36 per Mcf. Purchases under these contracts totaled $315.6 million and $256.0 million for the three months ended June 30, 2010 and 2009 and $1,208.4 million and $1,215.0 million for the nine months ended June 30, 2010 and 2009.

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 June 30, 2010 are as follows (in thousands):


2010	$	44,248
2011		265,224
2012		87,138
2013		6,705
2014		2,293
Thereafter		—

	$	405,608

Our natural gas marketing and pipeline, storage and other segments maintain long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2010.

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, 2009, 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. We have

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

completed our internal investigation and submitted the results to the Commission. During our investigation, we identified certain non-compliant transactions, 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 June 30, 2010, rate cases were in progress in our Kansas and Missouri service areas and annual rate filing mechanisms were in progress in our Mid-Tex, West Texas and Louisiana service areas. In addition, there was a GRIP filing in progress in our Mid-Tex Division along with other rate activity in our Georgia service area. We recently reached a tentative agreement to extend the rate review mechanism (RRM) for our West Texas Cities service area in our West Texas Division and are in discussions to extend the RRM in our Mid-Tex Division and in our Amarillo and Lubbock service areas in our West Texas Division. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments .

We have been replacing certain steel service lines in our Mid-Tex Division since our acquisition of the natural gas distribution system in 2004. We are committed to replacing the steel service lines on an accelerated schedule to ensure the safety and reliability of our distribution system, and as part of this commitment, we support the objectives of the rulemaking outlined by the Texas Railroad Commission (RRC) for steel service-line replacements statewide. The RRC is not scheduled to consider a formal rulemaking for this program until August 2010. Due to the preliminary status of the rulemaking process, we cannot accurately anticipate the impact this rule would have on the Company or the expected cost of the replacement program.


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, 2009. During the nine months ended June 30, 2010, there were no material changes in our concentration of credit risk.


10.	Segment Information

As discussed in Note 1 above, 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 our 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 gathering 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 varying 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, 2009. 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 nine month periods ended June 30, 2010 and 2009 by segment are presented in the following tables:


	Three Months Ended June 30, 2010
	Natural			Regulated		Natural			Pipeline,
	Gas			Transmission		Gas			Storage and
	Distribution			Storage		Marketing			Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	405,049		$	22,796	$	336,408		$	6,004	$	—		$	770,257
Intersegment revenues		222			22,161		84,998			2,192		(109,573	)		—

		405,271			44,957		421,406			8,196		(109,573	)		770,257
Purchased gas cost		208,378			—		415,101			2,730		(109,180	)		517,029

Gross profit		196,893			44,957		6,305			5,466		(393	)		253,228
Operating expenses
Operation and maintenance		89,112			16,050		6,486			2,093		(393	)		113,348
Depreciation and amortization		46,981			5,171		426			710		—			53,288
Taxes, other than income		48,521			3,010		555			397		—			52,483

Total operating expenses		184,614			24,231		7,467			3,200		(393	)		219,119

Operating income (loss)		12,279			20,726		(1,162	)		2,266		—			34,109
Miscellaneous income (expense)		(124	)		94		147			670		(1,637	)		(850	)
Interest charges		29,042			7,667		1,767			451		(1,637	)		37,290

Income (loss) before income taxes		(16,887	)		13,153		(2,782	)		2,485		—			(4,031	)
Income tax expense (benefit)		(5,985	)		4,688		(683	)		1,103		—			(877	)

Net income (loss)	$	(10,902	)	$	8,465	$	(2,099	)	$	1,382	$	—		$	(3,154	)

Capital expenditures	$	106,394		$	22,964	$	176		$	186	$	—		$	129,720

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended June 30, 2009
	Natural			Regulated		Natural		Pipeline,
	Gas			Transmission		Gas		Storage and
	Distribution			Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	386,774		$	29,558	$	358,458	$	5,985	$	—		$	780,775
Intersegment revenues		211			19,787		95,046		2,241		(117,285	)		—

		386,985			49,345		453,504		8,226		(117,285	)		780,775
Purchased gas cost		195,303			—		438,482		4,212		(116,862	)		521,135

Gross profit		191,682			49,345		15,022		4,014		(423	)		259,640
Operating expenses
Operation and maintenance		89,534			13,784		6,445		1,641		(509	)		110,895
Depreciation and amortization		47,928			5,066		392		795		—			54,181
Taxes, other than income		44,014			2,569		628		366		—			47,577
Asset impairments		2,823			370		90		21		—			3,304

Total operating expenses		184,299			21,789		7,555		2,823		(509	)		215,957

Operating income		7,383			27,556		7,467		1,191		86			43,683
Miscellaneous income		2,167			615		71		2,319		(3,953	)		1,219
Interest charges		32,798			8,152		4,020		408		(3,867	)		41,511

Income (loss) before income taxes		(23,248	)		20,019		3,518		3,102		—			3,391
Income tax expense (benefit)		(8,307	)		7,065		1,419		1,250		—			1,427

Net income (loss)	$	(14,941	)	$	12,954	$	2,099	$	1,852	$	—		$	1,964

Capital expenditures	$	86,861		$	28,216	$	82	$	5,837	$	—		$	120,996

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30, 2010
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	2,573,471	$	64,281	$	1,343,214	$	22,409	$	—		$	4,003,375
Intersegment revenues		682		82,717		314,615		6,460		(404,474	)		—

		2,574,153		146,998		1,657,829		28,869		(404,474	)		4,003,375
Purchased gas cost		1,697,248		—		1,585,259		5,732		(403,262	)		2,884,977

Gross profit		876,905		146,998		72,570		23,137		(1,212	)		1,118,398
Operating expenses
Operation and maintenance		272,687		53,877		21,772		7,174		(1,212	)		354,298
Depreciation and amortization		141,586		15,395		1,261		1,965		—			160,207
Taxes, other than income		142,042		9,226		2,237		1,143		—			154,648

Total operating expenses		556,315		78,498		25,270		10,282		(1,212	)		669,153

Operating income		320,590		68,500		47,300		12,855		—			449,245
Miscellaneous income (expense)		1,309		117		642		2,103		(5,241	)		(1,070	)
Interest charges		87,976		23,589		6,965		2,291		(5,241	)		115,580

Income before income taxes		233,923		45,028		40,977		12,667		—			332,595
Income tax expense		90,646		16,039		16,506		5,102		—			128,293

Net income	$	143,277	$	28,989	$	24,471	$	7,565	$	—		$	204,302

Capital expenditures	$	302,621	$	56,786	$	629	$	2,313	$	—		$	362,349

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Nine Months Ended June 30, 2009
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		Storage		Marketing		Other		Eliminations			Consolidated
					(In thousands)

Operating revenues from external parties	$	2,672,742	$	91,877	$	1,524,438	$	29,456	$	—		$	4,318,513
Intersegment revenues		631		71,384		425,219		7,490		(504,724	)		—

		2,673,373		163,261		1,949,657		36,946		(504,724	)		4,318,513
Purchased gas cost		1,816,227		—		1,881,068		9,771		(503,456	)		3,203,610

Gross profit		857,146		163,261		68,589		27,175		(1,268	)		1,114,903
Operating expenses
Operation and maintenance		276,462		58,448		27,228		4,700		(1,526	)		365,312
Depreciation and amortization		142,608		15,027		1,189		1,933		—			160,757
Taxes, other than income		139,861		7,929		1,667		571		—			150,028
Asset impairments		4,599		602		146		35		—			5,382

Total operating expenses		563,530		82,006		30,230		7,239		(1,526	)		681,479

Operating income		293,616		81,255		38,359		19,936		258			433,424
Miscellaneous income (expense)		6,123		1,713		490		6,540		(15,513	)		(647	)
Interest charges		94,506		23,580		11,383		1,821		(15,255	)		116,035

Income before income taxes		205,233		59,388		27,466		24,655		—			316,742
Income tax expense		68,465		19,308		11,444		10,595		—			109,812

Net income	$	136,768	$	40,080	$	16,022	$	14,060	$	—		$	206,930

Capital expenditures	$	260,482	$	61,579	$	199	$	20,066	$	—		$	342,326

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at June 30, 2010 and September 30, 2009 by segment is presented in the following tables:


	June 30, 2010
	Natural		Regulated		Natural			Pipeline,
	Gas		Transmission		Gas			Storage and
	Distribution		and Storage		Marketing			Other		Eliminations			Consolidated
					(In thousands)

ASSETS
Property, plant and equipment, net	$	3,872,364	$	715,411	$	7,233		$	74,035	$	—		$	4,669,043
Investment in subsidiaries		613,652		—		(2,096	)		—		(611,556	)		—
Current assets
Cash and cash equivalents		32,777		—		65,446			82,160		—			180,383
Assets from risk management activities		1,048		—		17,102			6		(421	)		17,735
Other current assets		424,374		16,194		245,605			79,746		(90,064	)		675,855
Intercompany receivables		560,553		—		—			108,687		(669,240	)		—

Total current assets		1,018,752		16,194		328,153			270,599		(759,725	)		873,973
Intangible assets		—		—		990			—		—			990
Goodwill		571,592		132,300		24,282			10,429		—			738,603
Noncurrent assets from risk management activities		46		—		4,950			—		(49	)		4,947
Deferred charges and other assets		269,850		10,877		1,259			16,108		—			298,094

	$	6,346,256	$	874,782	$	364,771		$	371,171	$	(1,371,330	)	$	6,585,650

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,313,730	$	200,190	$	73,285		$	340,177	$	(613,652	)	$	2,313,730
Long-term debt		1,809,219		—		—			327		—			1,809,546

Total capitalization		4,122,949		200,190		73,285			340,504		(613,652	)		4,123,276
Current liabilities
Current maturities of long-term debt		360,000		—		—			131		—			360,131
Short-term debt		67,435		—		—			—		(67,435	)		—
Liabilities from risk management activities		21,209		—		1,929			415		(421	)		23,132
Other current liabilities		450,488		10,484		167,203			16,854		(20,533	)		624,496
Intercompany payables		—		544,307		124,933			—		(669,240	)		—

Total current liabilities		899,132		554,791		294,065			17,400		(757,629	)		1,007,759
Deferred income taxes		636,745		115,117		(7,190	)		11,050		—			755,722
Noncurrent liabilities from risk management activities		275		—		3,858			49		(49	)		4,133
Regulatory cost of removal obligation		314,708		—		—			—		—			314,708
Deferred credits and other liabilities		372,447		4,684		753			2,168		—			380,052

	$	6,346,256	$	874,782	$	364,771		$	371,171	$	(1,371,330	)	$	6,585,650

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30, 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	$	3,703,471	$	672,829	$	7,112		$	55,691	$	—		$	4,439,103
Investment in subsidiaries		547,936		—		(2,096	)		—		(545,840	)		—
Current assets
Cash and cash equivalents		23,655		—		87,266			282		—			111,203
Assets from risk management activities		4,395		—		27,424			2,765		(2,941	)		31,643
Other current assets		499,155		17,017		157,846			112,551		(100,475	)		686,094
Intercompany receivables		552,408		—		—			128,104		(680,512	)		—

Total current assets		1,079,613		17,017		272,536			243,702		(783,928	)		828,940
Intangible assets		—		—		1,461			—		—			1,461
Goodwill		571,592		132,300		24,282			10,429		—			738,603
Noncurrent assets from risk management activities		1,620		—		12,415			6		(6	)		14,035
Deferred charges and other assets		290,327		11,932		1,065			18,300		—			321,624

	$	6,194,559	$	834,078	$	316,775		$	328,128	$	(1,329,774	)	$	6,343,766

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,176,761	$	171,200	$	83,354		$	293,382	$	(547,936	)	$	2,176,761
Long-term debt		2,169,007		—		—			393		—			2,169,400

Total capitalization		4,345,768		171,200		83,354			293,775		(547,936	)		4,346,161
Current liabilities
Current maturities of long-term debt		—		—		—			131		—			131
Short-term debt		158,942		—		—			—		(86,392	)		72,550
Liabilities from risk management activities		20,181		—		4,060			182		(2,941	)		21,482
Other current liabilities		510,749		9,251		116,078			19,167		(11,987	)		643,258
Intercompany payables		—		557,190		123,322			—		(680,512	)		—

Total current liabilities		689,872		566,441		243,460			19,480		(781,832	)		737,421
Deferred income taxes		477,352		92,250		(10,675	)		12,013		—			570,940
Noncurrent liabilities from risk management activities		—		—		6			—		(6	)		—
Regulatory cost of removal obligation		321,086		—		—			—		—			321,086
Deferred credits and other liabilities		360,481		4,187		630			2,860		—			368,158

	$	6,194,559	$	834,078	$	316,775		$	328,128	$	(1,329,774	)	$	6,343,766

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 June 30, 2010, the related condensed consolidated statements of income for the three-month and nine-month periods ended June 30, 2010 and 2009, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2010 and 2009. 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, 2009, 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 16, 2009, 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, 2009, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Ernst & Young LLP

Dallas, Texas

August 5, 2010


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, 2009.

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 fiscal year ended September 30, 2009, include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; the impact of adverse 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 impact of possible future additional regulatory and financial risks associated with global warming and climate change 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 over three 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 regulated distribution and pipeline systems.

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. Through our asset optimization activities, we also seek to maximize the economic value associated with the storage and transportation capacity we own or control.

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, the 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, 2009 and include the following:


	•	Regulation

	•	Revenue Recognition

	•	Allowance for Doubtful Accounts

	•	Financial Instruments and Hedging Activities

	•	Impairment Assessments

	•	Pension and Other Postretirement Plans

	•	Fair Value Measurements

Our critical accounting policies are reviewed quarterly by the Audit Committee. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2010.

RESULTS OF OPERATIONS

Due to the seasonality of our distribution business, we typically incur a net loss in our fiscal third quarter. For the three months ended June 30, 2010, we reported a net loss of $3.2 million, or $0.03 per diluted share compared with net income of $2.0 million, or $0.02 per diluted share in the prior-year quarter. The net loss for the three months ended June 30, 2010 includes noncash, unrealized net losses of $11.1 million, or $0.12 per diluted share compared with net gains of $7.0 million, or $0.08 per diluted share for the three months ended June 30, 2009. Quarter over quarter, lower net losses in our natural gas distribution operations offset lower earnings in our regulated transmission and storage segment associated with a 29 percent decrease in consolidated throughput due to reduced demand and basis spreads. Our nonregulated operations benefited from significantly higher storage and trading margins compared with the prior-year quarter, which more than offset the impact of an 11 percent quarter-over-quarter decrease in sales volumes in our natural gas marketing segment.

We reported net income of $204.3 million, or $2.18 per diluted share for the nine months ended June 30, 2010 compared with net income of $206.9 million, or $2.25 per diluted share in the prior-year period. Unrealized losses in our nonregulated operations during the current period reduced net income by $6.2 million or $0.07 per diluted share compared with net losses recorded in the prior-year period of $9.9 million, or $0.11 per diluted share. Regulated operations contributed 84 percent of our net income during this period with our nonregulated operations contributing the remaining 16 percent. Net income in both periods was impacted by nonrecurring items. The current year period includes the positive impact of a state sales tax refund of $4.5 million, or $0.05 per diluted share. Net income in the prior-year period included the net positive impact of several one-time items totaling $17.3 million, or $0.19 per diluted share related to the following pre-tax amounts:


	•	$11.3 million related to a favorable one-time tax benefit.

	•	$7.8 million related to the favorable impact of an update to the estimate for unbilled accounts.

	•	$7.0 million favorable impact of the reversal of estimated uncollectible gas costs.

	•	$5.4 million unfavorable impact of a non-cash impairment charge related to available-for-sale securities in our Supplemental Executive Retirement Plan.

During the nine months ended June 30, 2010, colder-than-normal weather and recent improvements in rate designs in our natural gas distribution segment partially offset the decline in demand for natural gas, which contributed to a 26 percent year-over-year decrease in consolidated throughput in our regulated transmission and storage segment and a 5 percent year-over-year decrease in consolidated sales volumes in our natural gas marketing segment.

During the year, we continued to successfully access the capital markets and received updated debt ratings from three rating agencies. In October 2009, we renewed a $200 million 364-day committed credit facility and in December 2009 we renewed a $450 million 364-day committed credit facility for our nonregulated operations. In June 2010, Fitch upgraded our rating outlook from stable to positive and affirmed the existing credit rating on our senior unsecured debt and commercial paper. In March 2010, Moody’s upgraded our rating outlook from stable to positive and affirmed the existing credit rating on our senior long-term debt and commercial paper while S&P affirmed our rating outlook as stable and our senior long-term debt credit rating. The new credit facilities should help ensure we have sufficient liquidity to fund our working capital needs, while our credit ratings should help us continue to obtain financing at a reasonable cost in the future.

On July 1, 2010, we entered into an accelerated share repurchase program with Goldman Sachs & Co. as part of our ongoing efforts to improve shareholder value. The shares that will be repurchased under this program will offset the dilutive impact of stock grants made under our various employee and director incentive compensation plans. It is anticipated that the impact of the program will add $0.01 to $0.02 to fiscal 2010 diluted earnings per share.

The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2010 and 2009:


	Three Months Ended					Nine Months Ended
	June 30					June 30
	2010			2009		2010			2009
	(In thousands, except per share data)

Operating revenues	$	770,257		$	780,775	$	4,003,375		$	4,318,513
Gross profit		253,228			259,640		1,118,398			1,114,903
Operating expenses		219,119			215,957		669,153			681,479
Operating income		34,109			43,683		449,245			433,424
Miscellaneous income (expense)		(850	)		1,219		(1,070	)		(647	)
Interest charges		37,290			41,511		115,580			116,035
Income (loss) before income taxes		(4,031	)		3,391		332,595			316,742
Income tax expense (benefit)		(877	)		1,427		128,293			109,812
Net income (loss)	$	(3,154	)	$	1,964	$	204,302		$	206,930
Diluted net income (loss) per share	$	(0.03	)	$	0.02	$	2.18		$	2.25

Our consolidated net income (loss) during the three and nine months ended June 30, 2010 and 2009 was earned in each of our business segments as follows:


	Three Months Ended
	June 30
	2010			2009			Change
	(In thousands)

Natural gas distribution segment	$	(10,902	)	$	(14,941	)	$	4,039
Regulated transmission and storage segment		8,465			12,954			(4,489	)
Natural gas marketing segment		(2,099	)		2,099			(4,198	)
Pipeline, storage and other segment		1,382			1,852			(470	)

Net income (loss)	$	(3,154	)	$	1,964		$	(5,118	)


	Nine Months Ended
	June 30
	2010		2009		Change
	(In thousands)

Natural gas distribution segment	$	143,277	$	136,768	$	6,509
Regulated transmission and storage segment		28,989		40,080		(11,091	)
Natural gas marketing segment		24,471		16,022		8,449
Pipeline, storage and other segment		7,565		14,060		(6,495	)

Net income	$	204,302	$	206,930	$	(2,628	)

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


	Three Months Ended
	June 30
	2010			2009			Change
	(In thousands, except per share data)

Regulated operations	$	(2,437	)	$	(1,987	)	$	(450	)
Nonregulated operations		(717	)		3,951			(4,668	)

Consolidated net income (loss)	$	(3,154	)	$	1,964		$	(5,118	)

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

Consolidated diluted EPS	$	(0.03	)	$	0.02		$	(0.05	)


	Nine Months Ended
	June 30
	2010		2009		Change
	(In thousands, except per share data)

Regulated operations	$	172,266	$	176,848	$	(4,582	)
Nonregulated operations		32,036		30,082		1,954

Consolidated net income	$	204,302	$	206,930	$	(2,628	)

Diluted EPS from regulated operations	$	1.84	$	1.92	$	(0.08	)
Diluted EPS from nonregulated operations		0.34		0.33		0.01

Consolidated diluted EPS	$	2.18	$	2.25	$	(0.07	)

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 includes 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 these 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 existed between the recognition of revenue for franchise fees collected from our customers and the recognition of expense of franchise taxes. These timing differences had a significant temporary effect on operating income in periods with volatile gas prices, particularly in our Mid-Tex Division. Beginning January 1, 2009, changes in our franchise fee agreements in our Mid-Tex Division became effective, which have significantly reduced the impact of this timing difference. Although this timing difference will still be present for gross receipts taxes, the timing differences described above have been and should continue to be less significant.

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.

Three Months Ended June 30, 2010 compared with Three Months Ended June 30, 2009

Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2010 and 2009 are presented below.


	Three Months Ended
	June 30
	2010			2009			Change
	(In thousands, unless otherwise noted)

Gross profit	$	196,893		$	191,682		$	5,211
Operating expenses		184,614			184,299			315

Operating income		12,279			7,383			4,896
Miscellaneous income (expense)		(124	)		2,167			(2,291	)
Interest charges		29,042			32,798			(3,756	)

Loss before income taxes		(16,887	)		(23,248	)		6,361
Income tax benefit		(5,985	)		(8,307	)		2,322

Net loss	$	(10,902	)	$	(14,941	)	$	4,039

Consolidated natural gas distribution sales volumes — MMcf		36,339			40,081			(3,742	)
Consolidated natural gas distribution transportation volumes — MMcf		29,589			29,597			(8	)

Total consolidated natural gas distribution throughput — MMcf		65,928			69,678			(3,750	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46		$	0.46		$	—
Consolidated natural gas distribution average cost of gas per Mcf sold	$	5.73		$	4.87		$	0.86

The following table shows our operating income (loss) by natural gas distribution division, in order of total customers served, for the three months ended June 30, 2010 and 2009. The presentation of our natural gas distribution operating income (loss) is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Three Months Ended
	June 30
	2010			2009			Change
	(In thousands)

Mid-Tex	$	(2,179	)	$	(3,598	)	$	1,419
Kentucky/Mid-States		5,055			2,931			2,124
Louisiana		6,537			5,459			1,078
West Texas		(104	)		1,010			(1,114	)
Mississippi		950			(585	)		1,535
Colorado-Kansas		1,762			1,247			515
Other		258			919			(661	)

Total	$	12,279		$	7,383		$	4,896

The $5.2 million increase in natural gas distribution gross profit primarily reflects a net increase of $5.5 million in rate adjustments, primarily in the Mid-Tex, Louisiana, West Texas and Mississippi service areas.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income and asset impairments increased $0.3 million. This increase was primarily due to an increase in state gross receipts taxes and ad valorem taxes, partially offset by a $2.8 million decrease due to the absence of an impairment of available-for-sale securities recorded in the prior year.

Nine Months Ended June 30, 2010 compared with Nine Months Ended June 30, 2009

Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2010 and 2009 are presented below.


	Nine Months Ended
	June 30
	2010		2009		Change
	(In thousands, unless otherwise noted)

Gross profit	$	876,905	$	857,146	$	19,759
Operating expenses		556,315		563,530		(7,215	)

Operating income		320,590		293,616		26,974
Miscellaneous income		1,309		6,123		(4,814	)
Interest charges		87,976		94,506		(6,530	)

Income before income taxes		233,923		205,233		28,690
Income tax expense		90,646		68,465		22,181

Net income	$	143,277	$	136,768	$	6,509

Consolidated natural gas distribution sales volumes — MMcf		294,183		253,087		41,096
Consolidated natural gas distribution transportation volumes — MMcf		104,090		98,994		5,096

Total consolidated natural gas distribution throughput — MMcf		398,273		352,081		46,192

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.46	$	—
Consolidated natural gas distribution average cost of gas per Mcf sold	$	5.77	$	7.18	$	(1.41	)

The following table shows our operating income by natural gas distribution division, in order of total customers served, for the nine months ended June 30, 2010 and 2009. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.


	Nine Months Ended
	June 30
	2010		2009		Change
	(In thousands)

Mid-Tex	$	128,045	$	129,454	$	(1,409	)
Kentucky/Mid-States		53,858		49,360		4,498
Louisiana		42,775		39,825		2,950
West Texas		33,053		23,829		9,224
Mississippi		28,604		24,621		3,983
Colorado-Kansas		24,635		23,471		1,164
Other		9,620		3,056		6,564

Total	$	320,590	$	293,616	$	26,974

The $19.8 million increase in natural gas distribution gross profit primarily reflects rate adjustments and increased throughput as follows:


	•	$27.9 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana and Mississippi service areas.

	•	$10.8 million increase as a result of a 13 percent increase in consolidated throughput primarily associated with higher residential and commercial consumption and colder weather in most of our service areas.

These increases were partially offset by:


	•	$7.8 million decrease due to a non-recurring adjustment recorded in the prior-year period to update the estimate for gas delivered to customers but not yet billed to reflect base rate changes.

	•	$7.0 million decrease related to a prior year reversal of an accrual for estimated unrecoverable gas costs that did not recur in the current year.

	•	$1.8 million decrease due to a decrease in revenue-related taxes, primarily due to a decrease in revenues on which the tax is calculated.


	•	$7.4 million decrease due to a state sales tax reimbursement received in March 2010.

	•	$4.6 million decrease due to the absence of an impairment charge for available-for-sale securities recorded in the prior year.

	•	$1.6 million decrease in contract labor expenses.

These decreases were partially offset by:


	•	$5.1 million increase in employee-related expenses.

	•	$2.2 million increase in taxes, other than income.

Miscellaneous income decreased $4.8 million due to lower interest income. Interest charges decreased $6.5 million primarily due to lower short-term debt balances and interest rates.

Additionally, results for the nine months ended June 30, 2009, were favorably impacted by a one-time tax benefit of $10.5 million. During the second quarter of fiscal 2009, the Company completed a study of the calculations used to estimate its deferred tax rate, and concluded that revisions to these calculations to include more specific jurisdictional tax rates would result in a more accurate calculation of the tax rate at which deferred taxes would reverse in the future. Accordingly, the Company modified the tax rate used to calculate deferred taxes from 38 percent to an individual rate for each legal entity. These rates vary from 36-41 percent depending on the jurisdiction of the legal entity.

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the nine months ended June 30, 2010 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 or other governmental authority’s final ruling.

Annual net operating income increases totaling $41.1 million resulting from ratemaking activity became effective in the nine months ended June 30, 2010 as summarized below:


	Annual Increase to
Rate Action	Operating Income
	(In thousands)

Rate case filings	$	15,831
GRIP filings		13,768
Annual rate filing mechanisms		8,905
Other rate activity		2,630

	$	41,134

Additionally, the following ratemaking efforts were in progress during the third quarter of fiscal 2010 but had not been completed as of June 30, 2010.


			Operating
			Income
Division	Rate Action	Jurisdiction	Requested
			(In thousands)

Colorado/Kansas	Rate Case ⁽¹⁾	Kansas	$	6,015
Kentucky/Mid-States	PRP ⁽²⁾	Georgia		764
	Rate Case ⁽³⁾	Missouri		6,439
Louisiana	RSC ⁽⁴⁾	LGS		4,296
Mid-Tex	GRIP ⁽⁵⁾⁽⁶⁾	Dallas & RRC		2,985
	Rate Review Mechanism (RRM) ⁽⁷⁾	Settled Cities		56,827
West Texas	RRM ⁽⁸⁾	WT Cities		4,243
	RRM ⁽⁹⁾	Amarillo & Lubbock		2,388

			$	83,957


⁽¹⁾		The Company, the Kansas Corporation Commission Staff and the Citizen’s Utility Ratepayer Board reached a unanimous settlement for an increase in operating income of $3.9 million which the Commission approved, effective August 1, 2010.

⁽²⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽³⁾		The Company, the Staff of the Missouri Public Service Commission, the Office of the Public Counsel, the Missouri Department of Natural Resources and Noranda Aluminum, Inc. reached a unanimous settlement


		in July 2010 for an increase in operating income of $4.0 million. The settlement is subject to final Missouri Public Service Commission approval.

⁽⁴⁾		The Louisiana Commission Staff recommended an increase of $3.9 million effective July 1, 2010, which the Commission accepted.

⁽⁵⁾		Gas Reliability Infrastructure Program (GRIP) is a rate adjustment that allows utilities to recover additional invested capital without filing a rate case.

⁽⁶⁾		This GRIP filing is based on a Mid-Tex System-wide basis and made concurrently with the City of Dallas and the Railroad Commission of Texas (RRC) for approval of their respective jurisdictional customers. The City of Dallas filing is currently on appeal at the RRC.

⁽⁷⁾		The Company and representatives of the Settled Cities are currently in negotiations to settle the filing and extend the rate review mechanism (RRM) in our Mid-Tex Division.

⁽⁸⁾		The Company and representatives of the West Texas Cities have reached a tentative settlement for a one-year extension of the RRM and an increase in operating income of $0.7 million. The settlement is subject to final authorization by each of the West Texas Cities.

⁽⁹⁾		Consultant reports have been received for the RRM filing in Lubbock and discussions are ongoing regarding the final resolution. A tentative settlement for the Amarillo RRM has been reached which would result in an operating income increase of $1.2 million.

Rate Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:

Increase in Annual

Effective

Division

State

Operating Income

Date

(In thousands)

2010 Rate Case Filings:

Kentucky/Mid-States

Kentucky

6,636

06/01/2010

Georgia

2,935

03/31/2010

Mid-Tex

Texas ⁽¹⁾

2,963

01/26/2010

Colorado/Kansas

Colorado

1,900

01/04/2010

Kentucky/Mid-States

Virginia

1,397

11/23/2009

Total 2010 Rate Case Filings

15,831


⁽¹⁾		In its final order, the RRC approved a $3.0 million increase in operating income from customers in the Dallas & Environs portion of the Mid-Tex Division. Net of the GRIP 2008 rates that will be superseded, operating income will increase $0.2 million. The ruling also provided for regulatory accounting treatment for certain costs related to storage assets and costs moving from our Mid-Tex Division within our natural gas distribution segment to our regulated transmission and storage segment.

GRIP Filings

GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years. The following table summarizes our GRIP filings with effective dates during the nine months ended June 30, 2010.


			Incremental Net
			Utility Plant		Additional Annual		Effective
Division	Calendar Year		Investment		Operating Income		Date
			(In thousands)		(In thousands)

2010 GRIP:
West Texas		2009	$	19,158	$	363		06/14/2010
Atmos Pipeline — Texas		2009		95,504		13,405		04/20/2010

Total 2010 GRIP			$	114,662	$	13,768

Annual Rate Filing Mechanisms

As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have annual rate filing mechanisms in our Louisiana and Mississippi divisions and in significant portions of our Mid-Tex and West Texas divisions. These mechanisms are referred to as rate review mechanisms (RRM) in our Mid-Tex and West Texas divisions, stable rate filings in the Mississippi Division and a rate stabilization clause in the Louisiana Division. We have recently reached a tentative agreement to extend the RRM for our West Texas Cities service area in our West Texas Division and are in discussions to extend the RRM in our Mid-Tex Division and in our Amarillo and Lubbock service areas in our West Texas Division. The following table summarizes filings made under our various annual rate filing mechanisms for the nine months ended June 30, 2010.

Additional

Annual

Test Year

Operating

Effective

Division

Jurisdiction

Ended

Income

Date

(In thousands)

2010 Filings:

Louisiana

TransLa

12/31/2009

1,733

04/01/2010

Mississippi

06/30/2009

3,183

12/15/2009

West Texas

Lubbock

12/31/2008

2,704

10/01/2009

West Texas

Amarillo

12/31/2008

1,285

10/01/2009

Total 2010 Filings

8,905

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the nine months ended June 30, 2010:


			Increase in
			Operating		Effective
Division	Jurisdiction	Rate Activity	Income		Date
			(In thousands)

2010 Other Rate Activity:
Kentucky/Mid-States	Missouri	ISRS ⁽¹⁾	$	563	03/02/2010
Colorado-Kansas	Kansas	Ad Valorem ⁽²⁾		392	01/05/2010
	Kansas	GSRS ⁽³⁾		766	12/12/2009
Kentucky/Mid-States	Georgia	PRP Surcharge		909	10/01/2009

Total 2010 Other Rate Activity			$	2,630


⁽¹⁾		Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

⁽²⁾		The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in the Company’s base rates.

⁽³⁾		Gas System Reliability Surcharge (GSRS) relates to safety related investments made since the previous rate case.

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.

Three Months Ended June 30, 2010 compared with Three Months Ended June 30, 2009

Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2010 and 2009 are presented below.


	Three Months Ended
	June 30
	2010		2009		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	21,908	$	19,507	$	2,401
Third-party transportation		17,521		24,285		(6,764	)
Storage and park and lend services		2,646		3,137		(491	)
Other		2,882		2,416		466

Gross profit		44,957		49,345		(4,388	)
Operating expenses		24,231		21,789		2,442

Operating income		20,726		27,556		(6,830	)
Miscellaneous income		94		615		(521	)
Interest charges		7,667		8,152		(485	)

Income before income taxes		13,153		20,019		(6,866	)
Income tax expense		4,688		7,065		(2,377	)

Net income	$	8,465	$	12,954	$	(4,489	)

Gross pipeline transportation volumes — MMcf		127,861		169,641		(41,780	)

Consolidated pipeline transportation volumes — MMcf		100,770		141,556		(40,786	)

The $4.4 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$3.6 million decrease due to decreased through-system volumes primarily associated with declines in basis differentials, electric generation demand and Barnett Shale activity.

	•	$3.5 million decrease due to lower transportation fees on through-system deliveries due to narrower basis spreads.

These decreases were partially offset by a $3.1 million increase associated with our GRIP filings.

Operating expenses increased $2.4 million primarily due to higher levels of pipeline maintenance activities.

Nine Months Ended June 30, 2010 compared with Nine Months Ended June 30, 2009

Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2010 and 2009 are presented below.


	Nine Months Ended
	June 30
	2010		2009		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	81,833	$	70,920	$	10,913
Third-party transportation		49,098		73,497		(24,399	)
Storage and park and lend services		7,924		8,151		(227	)
Other		8,143		10,693		(2,550	)

Gross profit		146,998		163,261		(16,263	)
Operating expenses		78,498		82,006		(3,508	)

Operating income		68,500		81,255		(12,755	)
Miscellaneous income		117		1,713		(1,596	)
Interest charges		23,589		23,580		9

Income before income taxes		45,028		59,388		(14,360	)
Income tax expense		16,039		19,308		(3,269	)

Net income	$	28,989	$	40,080	$	(11,091	)

Gross pipeline transportation volumes — MMcf		478,075		555,169		(77,094	)

Consolidated pipeline transportation volumes — MMcf		295,126		400,699		(105,573	)

The $16.3 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$11.0 million decrease due to lower transportation fees on through-system deliveries due to narrower basis spreads.

	•	$4.3 million decrease in market-based demand fees, priority reservation fees and compression activity associated with lower throughput.

	•	$4.3 million net decrease due to decreased through-system volumes primarily associated with market conditions that resulted in reduced wellhead production and decreased drilling activity, partially offset by increased deliveries to our Mid-Tex Division.

	•	$2.8 million decrease due to the absence of excess inventory sales in the current-year period.

These decreases were partially offset by a $6.1 million increase associated with our GRIP filings.

Operating expenses decreased $3.5 million primarily due to a $7.0 million decrease related to lower levels of pipeline maintenance activities, partially offset by the following:


	•	$1.2 million increase due to higher employee-related expenses.

	•	$1.3 million increase due to higher ad valorem and payroll taxes.

Natural Gas Marketing Segment

Atmos Energy Marketing LLC’s (AEM) primary business is to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. In addition, AEM utilizes proprietary and customer-owned transportation and storage assets to provide 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 (delivered gas business). As a result, AEM’s margins arise from the types of commercial transactions we have structured with our customers and our ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it has access to serve those customers.

AEM also seeks to enhance its gross profit margin by maximizing, through asset optimization activities, the economic value associated with the storage and transportation capacity we own or control in our natural gas distribution and natural gas marketing segments. We attempt to meet this objective by engaging in natural gas storage transactions in which we seek to find and profit through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. This process involves purchasing physical natural gas, storing it in the storage and transportation assets to which AEM has access and selling financial instruments at advantageous prices to lock in a gross profit margin.

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

Due to the nature of these operations, natural gas prices have a significant impact on our natural gas marketing operations. Within our delivered gas business, higher natural gas prices may 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. Higher gas prices, as well as

competitive factors in the industry and general economic conditions may also cause customers to conserve or use alternative energy sources. Within our asset optimization activities, higher gas prices could also lead to increased borrowings under our credit facilities resulting in higher interest expense.

Volatility in natural gas prices also has a significant impact on our natural gas marketing segment. Increased price volatility often has a significant impact on the spreads between market (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads within our asset optimization activities. However, increased volatility impacts the amounts of unrealized margins recorded in our gross profit and could impact the amount of cash required to collateralize our risk management liabilities.

Three Months Ended June 30, 2010 compared with Three Months Ended June 30, 2009

Financial and operational highlights for our natural gas marketing segment for the three months ended June 30, 2010 and 2009 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 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
	June 30
	2010			2009			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	12,550		$	16,598		$	(4,048	)
Asset optimization ⁽¹⁾		8,303			(14,580	)		22,883

		20,853			2,018			18,835
Unrealized margins		(14,548	)		13,004			(27,552	)

Gross profit		6,305			15,022			(8,717	)
Operating expenses		7,467			7,555			(88	)

Operating income (loss)		(1,162	)		7,467			(8,629	)
Miscellaneous income		147			71			76
Interest charges		1,767			4,020			(2,253	)

Income (loss) before income taxes		(2,782	)		3,518			(6,300	)
Income tax expense (benefit)		(683	)		1,419			(2,102	)

Net income (loss)	$	(2,099	)	$	2,099		$	(4,198	)

Gross natural gas marketing sales volumes — MMcf		91,854			103,146			(11,292	)

Consolidated natural gas marketing sales volumes — MMcf		75,014			84,162			(9,148	)

Net physical position (Bcf)		18.4			20.0			(1.6	)


⁽¹⁾		Net of storage fees of $2.7 million and $2.0 million.

AEM’s delivered gas business contributed 60 percent to total realized margins during the third quarter of fiscal 2010, with its asset optimization activities contributing the remaining 40 percent. The $18.8 million increase in realized gross profit reflected:


	•	A $22.9 million increase in asset optimization margins. During the current quarter, spot-to-forward spread values were very narrow due to unfavorable natural gas price fundamentals. As a result, AEM elected to maintain short-term trading positions, and generated incremental realized gains from rolling these positions throughout the quarter. This is in contrast to the prior-year quarter where AEM realized losses on the settlement of financial instruments after it elected to defer storage withdrawals and reset the corresponding financial instruments to capture additional summer/winter spread values.

	•	A $4.0 million decrease in realized delivered gas margins due to lower per-unit margins as a result of narrowing basis spreads combined with decreased delivered gas volumes. Per-unit margins were $0.14/Mcf in the current-year quarter compared with $0.16/Mcf in the prior-year period, while delivered sales volumes were 11 percent lower in the current-year period when compared with the prior-year quarter.

The increase in realized gross profit was more than offset by a $27.6 million decrease in unrealized margins primarily due to the quarter-over-quarter timing of storage withdrawal gains and the associated reversal of unrealized gains into realized gains.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income taxes and asset impairments, decreased $0.1 million primarily due to a decrease in employee and other administrative costs.

Interest charges decreased $2.3 million primarily due to a decrease in intercompany borrowings.

Nine Months Ended June 30, 2010 compared with Nine Months Ended June 30, 2009

Financial and operational highlights for our natural gas marketing segment for the nine months ended June 30, 2010 and 2009 are presented below.


	Nine Months Ended
	June 30
	2010			2009			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	45,763		$	58,316		$	(12,553	)
Asset optimization ⁽¹⁾		39,623			20,286			19,337

		85,386			78,602			6,784
Unrealized margins		(12,816	)		(10,013	)		(2,803	)

Gross profit		72,570			68,589			3,981
Operating expenses		25,270			30,230			(4,960	)

Operating income		47,300			38,359			8,941
Miscellaneous income		642			490			152
Interest charges		6,965			11,383			(4,418	)

Income before income taxes		40,977			27,466			13,511
Income tax expense		16,506			11,444			5,062

Net income	$	24,471		$	16,022		$	8,449

Gross natural gas marketing sales volumes — MMcf		317,992			336,870			(18,878	)

Consolidated natural gas marketing sales volumes — MMcf		267,136			282,443			(15,307	)

Net physical position (Bcf)		18.4			20.0			(1.6	)


⁽¹⁾		Net of storage fees of $8.7 million and $7.5 million.

AEM’s delivered gas business contributed 54 percent of total realized margins during the nine months ended June 30, 2010 with asset optimization activities contributing the remaining 46 percent. The $6.8 million increase in realized gross profit reflected the following:


	•	$19.3 million increase in asset optimization margins primarily associated with realized gains earned from AEM’s trading strategy executed during the fiscal third quarter.

	•	$12.6 million decrease in realized delivered gas margins due to lower per-unit margins as a result of narrowing basis spreads, combined with lower delivered sales volumes. Per-unit margins were $0.14/Mcf in the current-year period compared with $0.17/Mcf in the prior-year period, while delivered sales volumes were five percent lower in the current-year period when compared with the prior-year period.

The increase in realized gross profit was partially offset by a $2.8 million decrease in unrealized margins due to the period-over-period timing of storage withdrawal gains and the associated reversal of unrealized gains into realized gains.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income taxes and asset impairments decreased $5.0 million primarily due to a decrease in employee and other administrative costs.

Interest charges decreased $4.4 million primarily due to a decrease in intercompany borrowings.

Asset Optimization Activities

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 value, 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.

We define potential gross profit as the change in AEM’s gross profit from asset optimization activities in future periods if its optimization efforts are executed as planned. This amount does not include other operating expenses and associated 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 value 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 injections/withdrawals and hedge settlement estimates and historical financial information. This measure is presented because we believe it provides a more comprehensive view to investors of our asset optimization efforts and thus a better understanding of these activities than would be presented by GAAP measures alone. Because there is no assurance that the economic value or potential gross profit will be realized in the future, corresponding future GAAP amounts are not available.

The following table presents AEM’s economic value and its potential gross profit (loss) at June 30, 2010 and 2009.


	June 30
	2010			2009
	(In millions, unless otherwise noted)

Economic value	$	(8.6	)	$	42.0
Associated unrealized (gains) losses		15.7			(16.7	)

Subtotal		7.1			25.3
Related fees ⁽¹⁾		(12.8	)		(15.3	)

Potential gross profit (loss)	$	(5.7	)	$	10.0

Net physical position (Bcf)		18.4			20.0


⁽¹⁾		Related fees represent AEM’s contractual costs to acquire the storage capacity utilized in its asset optimization operations. The fees primarily consist of demand fees and contractual obligations to sell gas below market index prices in exchange for the right to manage and optimize third party storage assets for the positions AEM has entered into as of June 30, 2010 and 2009.

During the nine months ended June 30, 2010, AEM’s economic value decreased from $28.6 million, or $2.07/Mcf at September 30, 2009 to a negative economic value of $8.6 million, or $0.47/Mcf. This compares unfavorably to AEM’s economic value at June 30, 2009 of $42.0 million, or $2.10/Mcf.

Early in the first quarter of fiscal 2010, AEM withdrew gas and realized previously captured spread values. As current cash prices declined during the first fiscal quarter, AEM injected gas and rolled positions into the second fiscal quarter to increase economic value. These positions were settled in the second fiscal quarter and the associated economic value was realized. However, during the year, weak market fundamentals have caused cash prices to remain low and have contracted spot-to-forward spread values, which has limited opportunities to capture economic value. Therefore, during the fiscal third quarter, AEM elected to forego capturing these narrower spread values and maintained a short-term trading position. We anticipate spot-to-forward spread values will expand in the near term and we expect to be able to roll positions and capture greater economic value than what we can capture currently. However, the short-dated nature of AEM’s trading positions combined with current short-term forward prices that are lower than the cost of gas that was injected into storage in prior periods resulted in negative economic value as of June 30, 2010.

The economic value 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 value or the potential gross profit or loss calculated as of June 30, 2010 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.

Pipeline, Storage and Other Segment

Our pipeline, storage and other segment consists primarily of the operations of Atmos Pipeline and Storage, LLC (APS). APS is engaged in nonregulated transmission, storage and natural gas-gathering services. Its primary asset is a proprietary 21 mile pipeline located in New Orleans, Louisiana that is primarily used to aggregate gas supply for our regulated natural gas distribution division in Louisiana, our natural gas marketing segment, and, on a more limited basis, for third parties. APS also 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 additional pipeline capacity to meet customer demand during peak periods.

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 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. APS also seeks to maximize the economic value associated with the storage and transportation capacity it owns or controls by engaging in natural gas storage transactions in which it seeks to find and profit from the pricing differences that occur over time.

Results for this segment are primarily impacted by seasonal weather patterns and, similar to our natural gas marketing segment, 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.

Three Months Ended June 30, 2010 compared with Three Months Ended June 30, 2009

Financial and operational highlights for our pipeline, storage and other segment for the three months ended June 30, 2010 and 2009 are presented below.


	Three Months Ended
	June 30
	2010			2009			Change
	(In thousands)

Asset optimization	$	2,114		$	1,051		$	1,063
Storage and transportation services		3,319			3,470			(151	)
Other		231			737			(506	)
Unrealized margins		(198	)		(1,244	)		1,046

Gross profit		5,466			4,014			1,452
Operating expenses		3,200			2,823			377

Operating income		2,266			1,191			1,075
Miscellaneous income		670			2,319			(1,649	)
Interest charges		451			408			43

Income before income taxes		2,485			3,102			(617	)
Income tax expense		1,103			1,250			(147	)

Net income	$	1,382		$	1,852		$	(470	)

Gross profit from our pipeline, storage and other segment increased $1.5 million primarily due a $1.0 million increase in margins earned from APS’ asset optimization activities due to the quarter-over-quarter timing of realized gains earned from one of APS’ asset management plans and storage optimization activities.

Operating expenses increased $0.4 million primarily due to increased operating costs associated with APS’ gas gathering activities.

Miscellaneous income decreased $1.7 million primarily due to lower intercompany interest income earned by this segment.

Nine Months Ended June 30, 2010 compared with Nine Months Ended June 30, 2009

Financial and operational highlights for our pipeline, storage and other segment for the nine months ended June 30, 2010 and 2009 are presented below.


	Nine Months Ended
	June 30
	2010		2009			Change
	(In thousands)

Asset optimization	$	9,603	$	21,675		$	(12,072	)
Storage and transportation services		9,746		10,097			(351	)
Other		1,375		2,076			(701	)
Unrealized margins		2,413		(6,673	)		9,086

Gross profit		23,137		27,175			(4,038	)
Operating expenses		10,282		7,239			3,043

Operating income		12,855		19,936			(7,081	)
Miscellaneous income		2,103		6,540			(4,437	)
Interest charges		2,291		1,821			470

Income before income taxes		12,667		24,655			(11,988	)
Income tax expense		5,102		10,595			(5,493	)

Net income	$	7,565	$	14,060		$	(6,495	)

Gross profit from our pipeline, storage and other segment decreased $4.0 million primarily due to the following:


	•	$5.5 million decrease from lower margins earned on storage optimization activities.

	•	$4.1 million decrease in basis gains earned from utilizing leased capacity.

	•	$2.6 million decrease from lower margins earned on asset management plans.

	•	$9.1 million increase in unrealized margins associated with our asset optimization activities.

Operating expenses increased $3.0 million primarily due to increased operating costs associated with APS’ gas gathering activities and administrative costs.

Miscellaneous income decreased $4.4 million primarily due to lower intercompany interest income earned by this segment.

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.

Our $350 million unsecured 7.375% Senior Notes will mature in May 2011. We are currently evaluating alternatives to replace this facility and believe we will successfully replace this facility on reasonably economical terms.

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 2010.

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, investing and financing activities for the nine months ended June 30, 2010 and 2009 are presented below.


	Nine Months Ended June 30
	2010			2009			Change
	(In thousands)

Total cash provided by (used in)
Operating activities	$	594,564		$	824,594		$	(230,030	)
Investing activities		(362,787	)		(348,420	)		(14,367	)
Financing activities		(162,597	)		(397,156	)		234,559

Change in cash and cash equivalents		69,180			79,018			(9,838	)
Cash and cash equivalents at beginning of period		111,203			46,717			64,486

Cash and cash equivalents at end of period	$	180,383		$	125,735		$	54,648

Cash flows from operating activities

Period-over-period changes in our operating cash flows are primarily 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 nine months ended June 30, 2010, we generated operating cash flow of $594.6 million from operating activities compared with $824.6 million for the nine months ended June 30, 2009, primarily due to the fluctuation in gas costs. Gas costs, which reached historically high levels during the 2008 injection season, declined sharply when the economy slipped into the recession and have remained relatively stable since that time. Operating cash flow for the fiscal 2010 period reflects the recovery of lower gas costs through purchased gas recovery mechanisms and sales. This is in contrast to the fiscal 2009 period, where operating cash flow was favorably influenced by the recovery of high gas costs during a period of falling prices.

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, rate designs in our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline — Texas Division 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 2010 are expected to range from $525 million to $540 million. For the nine months ended June 30, 2010, capital expenditures were $362.3 million compared with $342.3 million for the nine months ended June 30, 2009. The $20.0 million increase in capital expenditures primarily reflects spending for the relocation of our information technology data center to a new facility and the construction of two service centers.

Cash flows from financing activities

For the nine months ended June 30, 2010, our financing activities used $162.6 million of cash compared with $397.2 million of cash used in the prior-year period, primarily due to lower cash outflows associated with repayment of our long-term and short-term debt instruments as follows:


	•	$407.2 million for long-term debt repayments. In the current-year period, $0.1 million of long-term debt was repaid, compared with $407.3 million in the prior-year period.

	•	$290.4 million for short-term debt repayments. In the current-year period, $76.0 million of short-term debt was repaid, compared with $366.4 million in the prior-year period. The reduction in net borrowings reflects the timing of the use of our line of credit to finance natural gas purchases and working capital.

The lower repayment activity was partially offset by:


	•	$445.6 million decrease in cash inflows due to the absence of proceeds from the issuance of long-term debt that occurred in the prior-year period.

	•	$11.4 million decrease in cash inflows due to a substantial decrease in the number of shares of common stock issued to provide shares for our Retirement Savings Plan due to a change to purchasing such shares on the open market.

	•	$3.0 million additional cash used due to an increase in dividends paid in the current year compared to the prior year.

	•	$1.9 million decrease in cash inflows due to the absence of the settlement of a Treasury lock agreement that occurred in the prior-year period.

The following table summarizes our share issuances for the nine months ended June 30, 2010 and 2009.


	Nine Months Ended
	June 30
	2010		2009

Shares issued:
Direct Stock Purchase Plan		103,529		319,732
Retirement Savings Plan and Trust		79,722		484,111
1998 Long-Term Incentive Plan		375,039		613,314
Outside Directors Stock-for-Fee Plan		2,689		2,294

Total shares issued		560,979		1,419,451

The year-over-year decrease in the number of shares issued primarily reflects the fact that we have started using shares purchased in the open market rather than issuing shares for the Direct Stock Purchase Plan and the Retirement Savings Plan. In addition, we awarded fewer shares under our 1998 Long-Term Incentive Plan due to the Company achieving a lower level of performance relative to the target performance established under the Plan during fiscal 2009 compared to fiscal 2008. Further, a higher average stock price during the second and third quarters of fiscal 2010 compared to the second and third quarters of 2009 enabled us to issue fewer shares during the current year-to-date period.

Share Repurchase Agreement

On, July 1, 2010, we entered into an accelerated share repurchase agreement with Goldman Sachs & Co. under which we repurchased $100 million of our outstanding common stock in order to offset stock grants made under our various employee and director incentive compensation plans.

We paid $100 million to Goldman Sachs & Co. on July 7, 2010 for shares of Atmos Energy common stock in a share forward transaction and received 2,958,580 shares. We will receive the balance of the shares at the conclusion of the repurchase program. The specific number of shares we will ultimately repurchase in

the transaction will be based generally on the average of the daily volume-weighted average share price of our common stock over the duration of the agreement. The agreement is scheduled to end in March 2011, although the termination date may be accelerated. As a result of this transaction, our weighted-average shares outstanding will be reduced over the remaining three months of fiscal 2010. Beginning in our fourth fiscal quarter, the outstanding shares used to calculate our earnings per share will be reduced by the number of shares repurchased as they are delivered to us and the $100 million purchase price will be recorded as a reduction in shareholders’ equity. Assuming a volume-weighted average share price equal to the June 30, 2010 closing share price of $27.04, we expect the repurchase transaction to add from $0.01 to $0.02 to fiscal 2010 earnings per diluted share.

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 June 30, 2010, the amount available to us under our credit facilities, net of outstanding letters of credit, was $951.3 million. These facilities are described in further detail in Note 5 to the unaudited condensed consolidated financial statements.

Shelf Registration

On March 31, 2010, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $1.3 billion in common stock and/or debt securities available for issuance.

We had already received approvals from all requisite state regulatory commissions to issue a total of $1.3 billion in common stock and/or debt securities under the new shelf registration statement, including the carryforward of the $450 million of securities remaining available for issuance under our shelf registration statement filed with the SEC on March 23, 2009. Due to certain restrictions imposed by one state regulatory commission on our ability to issue securities under the new registration statement, we will be able to issue a total of $950 million in debt securities and $350 million in equity 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 March 2010, Moody’s upgraded our rating outlook from stable to positive and affirmed the credit rating on our senior long-term debt at Baa2 and on our commercial paper at P-2. Moody’s stated that the key driver for the upgrade was successful rate case outcomes over the past year. In March 2010, S&P affirmed our senior long-term debt credit rating of BBB+ and our rating outlook as stable. In June 2010, Fitch reaffirmed our senior long-term debt rating of BBB+ and commercial paper ratings of F-2 and upgraded our rating outlook from stable to positive. Fitch cited our effective management of the regulatory process as well as our consistent financial and operational performance as the

primary reasons for the upgrade. Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB+

Baa2

BBB+

Commercial paper

A-2

P-2

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

Debt Covenants

We were in compliance with all of our debt covenants as of June 30, 2010. 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 inclusive of short-term debt and the current portion of long-term debt as of June 30, 2010, September 30, 2009 and June 30, 2009:


	June 30, 2010				September 30, 2009				June 30, 2009
	(In thousands, except percentages)

Short-term debt	$	—	—		$	72,550	1.6	%	$	—	—
Long-term debt		2,169,677	48.4	%		2,169,531	49.1	%		2,169,526	49.7	%
Shareholders’ equity		2,313,730	51.6	%		2,176,761	49.3	%		2,191,520	50.3	%

Total	$	4,483,407	100.0	%	$	4,418,842	100.0	%	$	4,361,046	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 48.4 percent at June 30, 2010, 50.7 percent at September 30, 2009 and 49.7 percent at June 30, 2009. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2010.

As we previously discussed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009, in February 2008, Atmos Pipeline and Storage, LLC, a subsidiary of AEH, announced plans to construct and operate a salt-cavern storage project in Franklin Parish, Louisiana. In March 2010, we entered into an option and acquisition agreement with a third party, which provides the third party with the exclusive option to develop the proposed Fort Necessity salt-dome natural gas storage project. If the option is exercised, we will retain a non-controlling equity position in Fort Necessity and will share in a percentage of the profits. In July

2010, we signed an extension to the option and acquisition agreement which gives the third party until March 2011 to exercise the option to develop the project.

We have been replacing certain steel service lines in our Mid-Tex Division since our acquisition of the natural gas distribution system in 2004. To date, we have replaced approximately 51,000 of these lines. We are committed to replacing the steel service lines on an accelerated schedule to ensure the safety and reliability of our distribution system, and as part of this commitment, we support the objectives of the rulemaking outlined by the Texas Railroad Commission (RRC) for steel service-line replacements statewide. The RRC is not scheduled to consider a formal rulemaking for this program until August 2010. Due to the preliminary status of the rulemaking process, we cannot accurately anticipate the impact this rule would have on the Company or the expected cost of the replacement program.

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 nine months ended June 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2010			2009			2010			2009
				(In thousands)

Fair value of contracts at beginning of period	$	(21,735	)	$	(21,863	)	$	(14,166	)	$	(63,677	)
Contracts realized/settled		(20	)		(844	)		(34,438	)		(101,840	)
Fair value of new contracts		182			(885	)		(2,054	)		(4,891	)
Other changes in value		1,183			1,564			30,268			148,380

Fair value of contracts at end of period	$	(20,390	)	$	(22,028	)	$	(20,390	)	$	(22,028	)

The fair value of our natural gas distribution segment’s financial instruments at June 30, 2010 is presented below by time period and fair value source:


	Fair Value of Contracts at June 30, 2010
	Maturity in Years
	Less								Greater		Total Fair
Source of Fair Value	Than 1			1-3			4-5		Than 5		Value
	(In thousands)

Prices actively quoted	$	(20,161	)	$	(229	)	$	—	$	—	$	(20,390	)
Prices based on models and other valuation methods		—			—			—		—		—

Total Fair Value	$	(20,161	)	$	(229	)	$	—	$	—	$	(20,390	)

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 nine months ended June 30, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	June 30						June 30
	2010			2009			2010			2009
	(In thousands)

Fair value of contracts at beginning of period	$	14,227		$	(32,646	)	$	26,698		$	16,542
Contracts realized/settled		(8,100	)		42,535			(32,342	)		29,260
Fair value of new contracts		—			—			—			—
Other changes in value		(8,337	)		8,555			3,434			(27,358	)

Fair value of contracts at end of period		(2,210	)		18,444			(2,210	)		18,444
Netting of cash collateral		18,017			20,614			18,017			20,614

Cash collateral and fair value of contracts at period end	$	15,807		$	39,058		$	15,807		$	39,058

The fair value of our natural gas marketing segment’s financial instruments at June 30, 2010 is presented below by time period and fair value source:


	Fair Value of Contracts at June 30, 2010
	Maturity in Years
	Less								Greater		Total Fair
Source of Fair Value	Than 1			1-3		4-5			Than 5		Value
	(In thousands)

Prices actively quoted	$	(3,254	)	$	1,984	$	(940	)	$	—	$	(2,210	)
Prices based on models and other valuation methods		—			—		—			—		—

Total Fair Value	$	(3,254	)	$	1,984	$	(940	)	$	—	$	(2,210	)

Pension and Postretirement Benefits Obligations

For the nine months ended June 30, 2010 and 2009, our total net periodic pension and other benefits costs were $38.1 million and $36.2 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.

Our fiscal 2010 costs were determined using a September 30, 2009 measurement date. As of September 30, 2009, interest and corporate bond rates utilized to determine our discount rates, were significantly higher than the interest and corporate bond rates as of September 30, 2008, the measurement date for our fiscal 2009 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2010 pension and benefit costs to 5.52 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 fluctuations in asset values 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. Accordingly, our fiscal 2010 pension and postretirement medical costs were materially the same as in fiscal 2009.

In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2010. Based upon this valuation, we will not be required to make a contribution to our pension plans during the current fiscal year. With respect to our postretirement medical plans, we anticipate contributing a total of approximately $12 million to these plans during fiscal 2010.

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 will be determined by actual investment returns, changes in interest rates, values of assets in the plan 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 nine month periods ended June 30, 2010 and 2009.

Natural Gas Distribution Sales and Statistical Data


	Three Months Ended				Nine Months Ended
	June 30				June 30
	2010		2009		2010		2009

METERS IN SERVICE, end of period
Residential		2,915,031		2,924,160		2,915,031		2,924,160
Commercial		271,745		274,739		271,745		274,739
Industrial		2,420		2,195		2,420		2,195
Public authority and other		10,439		9,231		10,439		9,231

Total meters		3,199,635		3,210,325		3,199,635		3,210,325

INVENTORY STORAGE BALANCE — Bcf		34.7		37.9		34.7		37.9
SALES VOLUMES — MMcf ⁽¹⁾
Gas sales volumes
Residential		17,436		19,043		178,840		147,718
Commercial		13,982		14,398		91,087		79,416
Industrial		3,544		3,921		15,523		15,079
Public authority and other		1,377		2,719		8,733		10,874

Total gas sales volumes		36,339		40,081		294,183		253,087
Transportation volumes		30,311		30,637		107,097		102,091

Total throughput		66,650		70,718		401,280		355,178

OPERATING REVENUES (000’s) ⁽¹⁾
Gas sales revenues
Residential	$	235,693	$	224,629	$	1,640,853	$	1,657,185
Commercial		119,434		106,739		705,114		744,248
Industrial		19,470		21,028		92,280		117,442
Public authority and other		9,160		13,712		61,744		82,097

Total gas sales revenues		383,757		366,108		2,499,991		2,600,972
Transportation revenues		13,896		13,756		48,590		46,411
Other gas revenues		7,618		7,121		25,572		25,990

Total operating revenues	$	405,271	$	386,985	$	2,574,153	$	2,673,373

Average transportation revenue per Mcf	$	0.46	$	0.45	$	0.45	$	0.45
Average cost of gas per Mcf sold	$	5.73	$	4.87	$	5.77	$	7.18

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				Nine Months Ended
	June 30				June 30
	2010		2009		2010		2009

CUSTOMERS, end of period
Industrial		732		706		732		706
Municipal		61		63		61		63
Other		507		505		507		505

Total		1,300		1,274		1,300		1,274

INVENTORY STORAGE BALANCE — Bcf
Natural gas marketing		20.2		23.3		20.2		23.3
Pipeline, storage and other		1.7		2.5		1.7		2.5

Total		21.9		25.8		21.9		25.8

REGULATED TRANSMISSION AND
STORAGE VOLUMES — MMcf ⁽¹⁾		127,861		169,641		478,075		555,169
NATURAL GAS MARKETING SALES
VOLUMES — MMcf ⁽¹⁾		91,854		103,146		317,992		336,870
OPERATING REVENUES (000’s) ⁽¹⁾
Regulated transmission and storage	$	44,957	$	49,345	$	146,998	$	163,261
Natural gas marketing		421,406		453,504		1,657,829		1,949,657
Pipeline, storage and other		8,196		8,226		28,869		36,946

Total operating revenues	$	474,559	$	511,075	$	1,833,696	$	2,149,864

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 fiscal year ended September 30, 2009. During the nine months ended June 30, 2010, 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 June 30, 2010 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 third quarter of the fiscal year ended September 30, 2010 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 nine months ended June 30, 2010, 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, 2009. 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 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 Treasurer

(Duly authorized signatory)

Date: August 5, 2010

EXHIBITS INDEX
Item 6


				Page Number or
Exhibit				Incorporation by
Number			Description	Reference to

	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*
	101	.INS	XBRL Instance Document**
	101	.SCH	XBRL Taxonomy Extension Schema**
	101	.CAL	XBRL Taxonomy Extension Calculation Linkbase**
	101	.LAB	XBRL Taxonomy Extension Labels Linkbase**
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase**


*		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.

**		Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

TABLE OF CONTENTS

Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 6. Exhibits

Exhibits

EX-12 EX-15 EX-31 EX-32

ATO 10-Q Quarter ended June 30, 2010

Exhibits