ATO 10-Q Quarterly Report March 31, 2010

ATMOS ENERGY CORP

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10-Q 1 d72740e10vq.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 March 31, 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 o No o

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

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

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

Number of shares outstanding of each of the issuer’s classes of common stock, as of April 30, 2010.


Class		Shares Outstanding

No Par Value		93,147,184

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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 5. Other Information
	Item 6. Exhibits
SIGNATURE
EXHIBITS INDEX Item 6
EX-3.1
EX-3.2
EX-12
EX-15
EX-31
EX-32

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation
AEH		Atmos Energy Holdings, Inc.
AEM		Atmos Energy Marketing, LLC
AOCI		Accumulated other comprehensive income
APS		Atmos Pipeline and Storage, LLC
Bcf		Billion cubic feet
FASB		Financial Accounting Standards Board
Fitch		Fitch Ratings, Ltd.
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


	March 31,			September 30,
	2010			2009
	(Unaudited)
	(In thousands, except
	share data)

ASSETS
Property, plant and equipment	$	6,295,260		$	6,086,618
Less accumulated depreciation and amortization		1,704,785			1,647,515

Net property, plant and equipment		4,590,475			4,439,103
Current assets
Cash and cash equivalents		231,153			111,203
Accounts receivable, net		546,356			232,806
Gas stored underground		208,589			352,728
Other current assets		121,261			132,203

Total current assets		1,107,359			828,940
Goodwill and intangible assets		739,750			740,064
Deferred charges and other assets		315,606			335,659

	$	6,753,190		$	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:
March 31, 2010 — 93,146,535 shares;
September 30, 2009 — 92,551,709 shares	$	466		$	463
Additional paid-in capital		1,809,331			1,791,129
Retained earnings		550,259			405,353
Accumulated other comprehensive loss		(21,213	)		(20,184	)

Shareholders’ equity		2,338,843			2,176,761
Long-term debt		2,159,475			2,169,400

Total capitalization		4,498,318			4,346,161
Current liabilities
Accounts payable and accrued liabilities		521,913			207,421
Other current liabilities		432,469			457,319
Short-term debt		—			72,550
Current maturities of long-term debt		10,131			131

Total current liabilities		964,513			737,421
Deferred income taxes		594,269			570,940
Regulatory cost of removal obligation		317,203			321,086
Deferred credits and other liabilities		378,887			368,158

	$	6,753,190		$	6,343,766

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended
	March 31
	2010			2009
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	1,365,988		$	1,230,420
Regulated transmission and storage segment		55,181			59,234
Natural gas marketing segment		692,152			708,658
Pipeline, storage and other segment		9,050			12,272
Intersegment eliminations		(182,105	)		(189,178	)

		1,940,266			1,821,406
Purchased gas cost
Natural gas distribution segment		980,603			863,340
Regulated transmission and storage segment		—			—
Natural gas marketing segment		685,672			685,114
Pipeline, storage and other segment		1,369			1,656
Intersegment eliminations		(181,699	)		(188,755	)

		1,485,945			1,361,355

Gross profit		454,321			460,051
Operating expenses
Operation and maintenance		117,088			121,740
Depreciation and amortization		53,080			53,450
Taxes, other than income		59,613			58,314

Total operating expenses		229,781			233,504

Operating income		224,540			226,547
Miscellaneous income (expense)		49			(1,565	)
Interest charges		39,582			35,533

Income before income taxes		185,007			189,449
Income tax expense		70,881			60,446

Net income	$	114,126		$	129,003

Basic net income per share	$	1.22		$	1.41

Diluted net income per share	$	1.22		$	1.40

Cash dividends per share	$	0.335		$	0.330

Weighted average shares outstanding:
Basic		92,518			90,895

Diluted		92,853			91,192

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Six Months Ended
	March 31
	2010			2009
	(Unaudited)
	(In thousands, except
	per share data)

Operating revenues
Natural gas distribution segment	$	2,168,882		$	2,286,388
Regulated transmission and storage segment		102,041			113,916
Natural gas marketing segment		1,236,423			1,496,153
Pipeline, storage and other segment		20,673			28,720
Intersegment eliminations		(294,901	)		(387,439	)

		3,233,118			3,537,738
Purchased gas cost
Natural gas distribution segment		1,488,870			1,620,924
Regulated transmission and storage segment		—			—
Natural gas marketing segment		1,170,158			1,442,586
Pipeline, storage and other segment		3,002			5,559
Intersegment eliminations		(294,082	)		(386,594	)

		2,367,948			2,682,475

Gross profit		865,170			855,263
Operating expenses
Operation and maintenance		240,950			254,417
Depreciation and amortization		106,919			106,576
Taxes, other than income		102,165			102,451
Asset impairments		—			2,078

Total operating expenses		450,034			465,522

Operating income		415,136			389,741
Miscellaneous expense		(220	)		(1,866	)
Interest charges		78,290			74,524

Income before income taxes		336,626			313,351
Income tax expense		129,170			108,385

Net income	$	207,456		$	204,966

Basic net income per share	$	2.22		$	2.24

Diluted net income per share	$	2.22		$	2.23

Cash dividends per share	$	0.670		$	0.660

Weighted average shares outstanding:
Basic		92,336			90,637

Diluted		92,681			90,935

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended
	March 31
	2010			2009
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities
Net income	$	207,456		$	204,966
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		106,919			106,576
Charged to other accounts		96			21
Deferred income taxes		44,097			97,892
Other		11,759			13,634
Net assets/liabilities from risk management activities		1,234			5,810
Net change in operating assets and liabilities		111,897			185,723

Net cash provided by operating activities		483,458			614,622
Cash Flows From Investing Activities
Capital expenditures		(232,629	)		(221,330	)
Other, net		(946	)		(3,925	)

Net cash used in investing activities		(233,575	)		(225,255	)
Cash Flows From Financing Activities
Net decrease in short-term debt		(75,907	)		(353,468	)
Net proceeds from issuance of long-term debt		—			446,188
Settlement of Treasury lock agreement		—			1,938
Repayment of long-term debt		(66	)		(625	)
Cash dividends paid		(62,550	)		(60,446	)
Issuance of common stock		8,590			12,414

Net cash provided by (used in) financing activities		(129,933	)		46,001

Net increase in cash and cash equivalents		119,950			435,368
Cash and cash equivalents at beginning of period		111,203			46,717

Cash and cash equivalents at end of period	$	231,153		$	482,085

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 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 3 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 six-month period ended March 31, 2010 are not indicative of our results of operations for the full 2010 fiscal year, which ends September 30, 2010. We have evaluated subsequent events from the March 31, 2010 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC).

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

The Company adopted an accounting standard related to fair value disclosures effective January 1, 2010. Effective October 1, 2009, the Company adopted accounting standards related to the measurement of liabilities at fair value, fair value measurements of plan assets of a defined benefit pension or other postretirement plan, the determination of participating securities in the basic earnings per share calculation, business combination accounting and the accounting and reporting for minority interests. 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 six months ended March 31, 2010.

Fair value disclosures — The Financial Accounting Standards Board (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 are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures related to the detailed reconciliation of Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. As a result of adopting this standard, 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 as of March 31, 2010 which is included in Note 4. As of March 31, 2010, we did not have any Level 3 fair value measurements.

Measurement of liabilities at fair value — 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.

Fair value measurements of plan assets of a defined benefit pension or other postretirement plan — The FASB issued guidance which 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.

The determination of participating securities in the basic earnings per share calculation — The FASB issued guidance related to determining whether instruments granted in share-based payment transactions are

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 six months ended March 31, 2009.


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

Basic Earnings Per Share
Basic EPS — as previously reported	$	1.42	$	2.26
Basic EPS — as adjusted	$	1.41	$	2.24
Weighted average shares outstanding — as previously reported		90,895		90,637
Weighted average shares outstanding — as adjusted		90,895		90,637
Diluted Earnings Per Share
Diluted EPS — as previously reported	$	1.41	$	2.24
Diluted EPS — as adjusted	$	1.40	$	2.23
Weighted average shares outstanding — as previously reported		91,567		91,311
Weighted average shares outstanding — as adjusted		91,192		90,935

Business combination accounting — This new pronouncement establishes 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. The provisions of this standard will apply to any acquisitions we complete after October 1, 2009.

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 changes the accounting for transactions with minority interest holders. As of March 31, 2010, Atmos Energy did not have any transactions with minority interest holders.

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 March 31, 2010 and September 30, 2009 included the following:


	March 31,		September 30,
	2010		2009
	(In thousands)

Regulatory assets:
Pension and postretirement benefit costs	$	192,291	$	197,743
Merger and integration costs, net		6,938		7,161
Deferred gas costs		67,132		22,233
Environmental costs		913		866
Rate case costs		3,554		5,923
Deferred franchise fees		507		10,014
Deferred income taxes, net		639		639
Other		5,707		6,218

	$	277,681	$	250,797

Regulatory liabilities:
Deferred gas costs	$	20,583	$	110,754
Deferred franchise fees		4,730		—
Regulatory cost of removal obligation		340,869		335,428
Other		6,358		7,960

	$	372,540	$	454,142

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the components of comprehensive income, net of related tax, for the three-month and six-month periods ended March 31, 2010 and 2009:


	Three Months Ended						Six Months Ended
	March 31						March 31
	2010			2009			2010			2009
				(In thousands)

Net income	$	114,126		$	129,003		$	207,456		$	204,966
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $408 and $(429) for the three months ended March 31, 2010 and 2009 and of $798 and $(3,759) for the six months ended March 31, 2010 and 2009		695			(862	)		1,359			(6,295	)
Other than temporary impairment of investments, net of tax expense of $790 for the six months ended March 31, 2009		—			—			—			1,288
Amortization and unrealized gain on interest rate hedging transactions, net of tax expense of $248 and $1,353 for the three months ended March 31, 2010 and 2009 and $496 and $1,835 for the six months ended March 31, 2010 and 2009		421			1,854			843			2,641
Net unrealized losses on commodity hedging transactions, net of tax benefit of $6,321 and $7,524 for the three months ended March 31, 2010 and 2009 and $2,067 and $21,341 for the six months ended March 31, 2010 and 2009		(9,885	)		(9,771	)		(3,231	)		(32,315	)

Comprehensive income	$	105,357		$	120,224		$	206,427		$	170,285

Accumulated other comprehensive loss, net of tax, as of March 31, 2010 and September 30, 2009 consisted of the following unrealized gains (losses):


	March 31,			September 30,
	2010			2009
	(In thousands)

Accumulated other comprehensive loss:
Unrealized holding gains on investments	$	3,819		$	2,460
Treasury lock agreements		(6,655	)		(7,498	)
Cash flow hedges		(18,377	)		(15,146	)

	$	(21,213	)	$	(20,184	)


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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 52 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 March 31, 2010, AEH had net open positions (including existing storage) of 0.8 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 of these Treasury locks will be recognized by the end of fiscal 2019.

Quantitative Disclosures Related to Financial Instruments

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of March 31, 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 March 31, 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		—		(19,135	)		(1,010	)
	Cash Flow		—		24,905			(700	)
	Not designated		14,800		59,697			380

			14,800		65,467			(1,330	)

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of March 31, 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 $7.2 million and $11.7 million of cash held on deposit in margin accounts as of March 31, 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)

March 31, 2010
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	49,314		$	49,314
Noncurrent commodity contracts	Deferred charges and other assets		—			5,899			5,899
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(51,648	)		(51,648	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(4,893	)		(4,893	)

Total			—			(1,328	)		(1,328	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		281			40,314			40,595
Noncurrent commodity contracts	Deferred charges and other assets		—			4,692			4,692
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(22,016	)		(28,812	)		(50,828	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(639	)		(639	)

Total			(21,735	)		15,555			(6,180	)

Total Financial Instruments		$	(21,735	)	$	14,227		$	(7,508	)


⁽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 six months ended March 31, 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 March 31, 2010 and 2009 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(4.9) million and $4.2 million. For the six months ended March 31, 2010 and 2009 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $40.4 million and $24.6 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 six months ended March 31, 2010 and 2009 is presented below.


	Three Months Ended March 31, 2010
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other			Consolidated
				(In thousands)

Commodity contracts	$	30,926		$	2,535		$	33,461
Fair value adjustment for natural gas inventory designated as the hedged item		(34,969	)		(2,697	)		(37,666	)

Total impact on revenue	$	(4,043	)	$	(162	)	$	(4,205	)

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(512	)	$	—		$	(512	)
Timing ineffectiveness		(3,531	)		(162	)		(3,693	)

	$	(4,043	)	$	(162	)	$	(4,205	)


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

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

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

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

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


	Six Months Ended March 31, 2010
	Natural			Pipeline,
	Gas			Storage and
	Marketing			Other		Consolidated
				(In thousands)

Commodity contracts	$	28,743		$	2,078	$	30,821
Fair value adjustment for natural gas inventory designated as the hedged item		8,343			3,174		11,517

Total impact on revenue	$	37,086		$	5,252	$	42,338

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	(449	)	$	—	$	(449	)
Timing ineffectiveness		37,535			5,252		42,787

	$	37,086		$	5,252	$	42,338

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

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

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

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

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

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 six months ended March 31, 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 March 31, 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	$	—		$	(10,685	)	$	2,129	$	(8,556	)
Loss arising from ineffective portion of commodity contracts		—			(739	)		—		(739	)

Total impact on revenue		—			(11,424	)		2,129		(9,295	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(669	)		—			—		(669	)

Total Impact from Cash Flow Hedges	$	(669	)	$	(11,424	)	$	2,129	$	(9,964	)

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended March 31, 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	$	—		$	(48,585	)	$	16,170	$	(32,415	)
Gain arising from ineffective portion of commodity contracts		—			1,180			—		1,180

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

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


	Six Months Ended March 31, 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	$	—		$	(34,556	)	$	2,883	$	(31,673	)
Loss arising from ineffective portion of commodity contracts		—			(1,957	)		—		(1,957	)

Total impact on revenue		—			(36,513	)		2,883		(33,630	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(1,339	)		—			—		(1,339	)

Total Impact from Cash Flow Hedges	$	(1,339	)	$	(36,513	)	$	2,883	$	(34,969	)


	Six Months Ended March 31, 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	$	—		$	(76,829	)	$	24,139	$	(52,690	)
Gain arising from ineffective portion of commodity contracts		—			5,372			—		5,372

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

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and six months ended March 31, 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						Six Months Ended
	March 31						March 31
	2010			2009			2010			2009
				(In thousands)

Increase (decrease) in fair value:
Treasury lock agreements	$	—		$	1,221		$	—		$	1,221
Forward commodity contracts		(15,104	)		(29,544	)		(22,551	)		(64,659	)
Recognition of losses in earnings due to settlements:
Treasury lock agreements		421			633			843			1,420
Forward commodity contracts		5,219			19,773			19,320			32,344

Total other comprehensive loss from hedging, net of tax ⁽¹⁾	$	(9,464	)	$	(7,917	)	$	(2,388	)	$	(29,674	)


⁽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 into earnings as they are amortized, while deferred losses associated with commodity contracts are recognized into 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 March 31, 2010:


	Treasury
	Lock			Commodity
	Agreements			Contracts			Total
				(In thousands)

Next twelve months	$	(1,687	)	$	(14,830	)	$	(16,517	)
Thereafter		(4,968	)		(3,547	)		(8,515	)

Total ⁽¹⁾	$	(6,655	)	$	(18,377	)	$	(25,032	)


⁽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 six months ended March 31, 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 to our natural gas distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related

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					Six Months Ended
	March 31					March 31
	2010			2009		2010			2009
				(In thousands)

Natural gas marketing commodity contracts	$	(1,811	)	$	10,593	$	12,464		$	6,761
Pipeline, storage and other commodity contracts		(1,175	)		183		(168	)		100

Total impact on revenue	$	(2,986	)	$	10,776	$	12,296		$	6,861


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 six months ended March 31, 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 six months ended March 31, 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 table summarizes, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010. Assets

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.


	Quoted		Significant		Significant
	Prices in		Other		Other
	Active		Observable		Unobservable		Netting and
	Markets		Inputs		Inputs		Cash			March 31,
	(Level 1)		(Level 2) ⁽¹⁾		(Level 3)		Collateral ⁽²⁾			2010
					(In thousands)

Assets:
Financial instruments
Natural gas distribution segment	$	—	$	281	$	—	$	—		$	281
Natural gas marketing segment		31,459		68,760		—		(72,289	)		27,930

Total financial instruments		31,459		69,041		—		(72,289	)		28,211
Hedged portion of gas stored underground
Natural gas marketing segment		73,655		—		—		—			73,655
Pipeline, storage and other segment ⁽³⁾		3,844		—		—		—			3,844

Total gas stored underground		77,499		—		—		—			77,499
Available-for-sale securities		42,558		—		—		—			42,558

Total assets	$	151,516	$	69,041	$	—	$	(72,289	)	$	148,268

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	22,016	$	—	$	—		$	22,016
Natural gas marketing segment		53,387		32,605		—		(79,488	)		6,504

Total liabilities	$	53,387	$	54,621	$	—	$	(79,488	)	$	28,520


⁽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 March 31, 2010, we had $7.2 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 March 31, 2010:


	March 31, 2010
	(In thousands)

Carrying Amount	$	2,172,761
Fair Value	$	2,364,093


5.	Debt

Long-term debt

Long-term debt at March 31, 2010 and September 30, 2009 consisted of the following:


	March 31,			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		(3,155	)		(3,296	)
Current maturities		(10,131	)		(131	)

	$	2,159,475		$	2,169,400

As noted above, our Series A, 1995-2, 6.27% medium term note will mature in December 2010; accordingly, it has 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)

approximately $1.2 billion of working capital funding. At March 31, 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 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 March 31, 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 March 31, 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 March 31, 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.

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At March 31, 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 $20.5 million outstanding under this facility at March 31, 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 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 March 31, 2010, there were no borrowings outstanding under this credit facility. However, at March 31, 2010, AEM letters of credit totaling $42.0 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 $258.0 million at March 31, 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 March 31, 2010, AEM’s ratio of total liabilities to tangible net worth, as defined, was 0.96 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 March 31, 2010, AEM’s net working capital was $240.4 million and its tangible net worth was $254.4 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 was $40.0 million outstanding under this facility at March 31, 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 March 31, 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 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.

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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 March 31, 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, for which vesting is predicated solely on the passage of time granted under the 1998 Long-Term Incentive Plan, 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 standard. Basic and diluted earnings per share for the three and six months ended March 31, 2010 and 2009 are calculated as follows:


	Three Months Ended				Six Months Ended
	March 31				March 31
	2010		2009		2010		2009
	(In thousands, except per share amounts)

Basic Earnings Per Share
Net income	$	114,126	$	129,003	$	207,456	$	204,966
Less: Income allocated to participating securities		1,142		1,183		2,088		1,817

Net income available to common shareholders	$	112,984	$	127,820	$	205,368	$	203,149

Basic weighted average shares outstanding		92,518		90,895		92,336		90,637

Net income per share — Basic	$	1.22	$	1.41	$	2.22	$	2.24

Diluted Earnings Per Share
Net income available to common shareholders	$	112,984	$	127,820	$	205,368	$	203,149
Effect of dilutive stock options and other shares		3		3		5		4

Net income available to common shareholders	$	112,987	$	127,823	$	205,373	$	203,153

Basic weighted average shares outstanding		92,518		90,895		92,336		90,637
Additional dilutive stock options and other shares		335		297		345		298

Diluted weighted average shares outstanding		92,853		91,192		92,681		90,935

Net income per share — Diluted	$	1.22	$	1.40	$	2.22	$	2.23

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2010 as their exercise price was less than the average market price of the common stock during that period. There were approximately 260,000 out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2009.


7.	Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and six months ended March 31, 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 March 31
	Pension Benefits						Other Benefits
	2010			2009			2010			2009
	(In thousands)

Components of net periodic pension cost:
Service cost	$	3,994		$	3,703		$	3,359		$	2,946
Interest cost		6,523			7,554			3,017			3,520
Expected return on assets		(6,320	)		(6,238	)		(615	)		(573	)
Amortization of transition asset		—			—			378			378
Amortization of prior service cost		(194	)		(183	)		(375	)		—
Amortization of actuarial loss		2,823			955			94			—

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


	Six Months Ended March 31
	Pension Benefits						Other Benefits
	2010			2009			2010			2009
	(In thousands)

Components of net periodic pension cost:
Service cost	$	7,987		$	7,406		$	6,719		$	5,892
Interest cost		13,047			15,108			6,035			7,040
Expected return on assets		(12,640	)		(12,476	)		(1,230	)		(1,146	)
Amortization of transition asset		—			—			756			756
Amortization of prior service cost		(387	)		(366	)		(750	)		—
Amortization of actuarial loss		5,645			1,910			187			—

Net periodic pension cost	$	13,652		$	11,582		$	11,717		$	12,542

The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 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	%

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 expect we will be required to contribute less than $5 million to our pension plans by September 15, 2010.

We contributed $5.9 million to our other post-retirement benefit plans during the six months ended March 31, 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		Fair
	Cost		Gain		Loss		Value
	(In thousands)

As of March 31, 2010:
Domestic equity mutual funds	$	29,306	$	5,132	$	—	$	34,438
Foreign equity mutual funds		4,753		927		—		5,680
Money market funds		2,440		—		—		2,440

	$	36,499	$	6,059	$	—	$	42,558

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 six months ended March 31, 2009, we recorded a $2.1 million noncash charge to impair certain available-for-sale investments due to deterioration of the market and the uncertainty of a full recovery. We did not maintain any investments that are in an unrealized loss position at March 31, 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 six months ended March 31, 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 March 31, 2010, AEM was committed to purchase 98.7 Bcf within one year, 8.1 Bcf within one to three years and 2.5 Bcf after three years under indexed contracts. AEM is committed to purchase 2.0 Bcf within one year, 0.9 Bcf within one to three years and 0.1 Bcf after three years under fixed price contracts with prices ranging from $3.64 to $6.36 per Mcf. Purchases under these contracts totaled $538.6 million and $431.5 million for the three months ended March 31, 2010 and 2009 and $892.7 million and $959.0 million for the six months ended March 31, 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 March 31, 2010 are as follows (in thousands):


2010	$	78,356
2011		150,999
2012		86,504
2013		6,564
2014		2,273
Thereafter		—

	$	324,696

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 six months ended March 31, 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 March 31, 2010, rate cases were in progress in our Kansas, Kentucky and Missouri service areas and annual rate filing mechanisms were in progress in our Mid-Tex service area. In addition, there were GRIP filings in progress in our Atmos Pipeline — Texas, Mid-Tex and West Texas divisions along with other rate activity in our Georgia and Louisiana service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments .


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 six months ended March 31, 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 six month periods ended March 31, 2010 and 2009 by segment are presented in the following tables:


	Three Months Ended March 31, 2010
	Natural		Regulated			Natural			Pipeline,
	Gas		Transmission			Gas			Storage and
	Distribution		Storage			Marketing			Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	1,365,736	$	21,643		$	545,985		$	6,902	$	—		$	1,940,266
Intersegment revenues		252		33,538			146,167			2,148		(182,105	)		—

		1,365,988		55,181			692,152			9,050		(182,105	)		1,940,266
Purchased gas cost		980,603		—			685,672			1,369		(181,699	)		1,485,945

Gross profit		385,385		55,181			6,480			7,681		(406	)		454,321
Operating expenses
Operation and maintenance		87,542		20,248			6,531			3,173		(406	)		117,088
Depreciation and amortization		46,748		5,282			424			626		—			53,080
Taxes, other than income		55,531		2,949			747			386		—			59,613

Total operating expenses		189,821		28,479			7,702			4,185		(406	)		229,781

Operating income (loss)		195,564		26,702			(1,222	)		3,496		—			224,540
Miscellaneous income (expense)		776		(20	)		287			980		(1,974	)		49
Interest charges		29,256		7,954			2,820			1,526		(1,974	)		39,582

Income (loss) before income taxes		167,084		18,728			(3,755	)		2,950		—			185,007
Income tax expense (benefit)		64,353		6,658			(1,313	)		1,183		—			70,881

Net income (loss)	$	102,731	$	12,070		$	(2,442	)	$	1,767	$	—		$	114,126

Capital expenditures	$	95,765	$	20,063		$	47		$	1,315	$	—		$	117,190

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

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

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

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

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

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

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

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

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Six Months Ended March 31, 2010
	Natural		Regulated		Natural		Pipeline,
	Gas		Transmission		Gas		Storage and
	Distribution		Storage		Marketing		Other		Eliminations			Consolidated
	(In thousands)

Operating revenues from external parties	$	2,168,422	$	41,485	$	1,006,806	$	16,405	$	—		$	3,233,118
Intersegment revenues		460		60,556		229,617		4,268		(294,901	)		—

		2,168,882		102,041		1,236,423		20,673		(294,901	)		3,233,118
Purchased gas cost		1,488,870		—		1,170,158		3,002		(294,082	)		2,367,948

Gross profit		680,012		102,041		66,265		17,671		(819	)		865,170
Operating expenses
Operation and maintenance		183,575		37,827		15,286		5,081		(819	)		240,950
Depreciation and amortization		94,605		10,224		835		1,255		—			106,919
Taxes, other than income		93,521		6,216		1,682		746		—			102,165

Total operating expenses		371,701		54,267		17,803		7,082		(819	)		450,034

Operating income		308,311		47,774		48,462		10,589		—			415,136
Miscellaneous income (expense)		1,433		23		495		1,433		(3,604	)		(220	)
Interest charges		58,934		15,922		5,198		1,840		(3,604	)		78,290

Income before income taxes		250,810		31,875		43,759		10,182		—			336,626
Income tax expense		96,631		11,351		17,189		3,999		—			129,170

Net income	$	154,179	$	20,524	$	26,570	$	6,183	$	—		$	207,456

Capital expenditures	$	196,227	$	33,822	$	453	$	2,127	$	—		$	232,629

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

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

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

Gross profit		665,464		113,916		53,567		23,161		(845	)		855,263
Operating expenses
Operation and maintenance		186,928		44,664		20,783		3,059		(1,017	)		254,417
Depreciation and amortization		94,680		9,961		797		1,138		—			106,576
Taxes, other than income		95,847		5,360		1,039		205		—			102,451
Asset impairments		1,776		232		56		14		—			2,078

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

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

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

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

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at March 31, 2010 and September 30, 2009 by segment is presented in the following tables:


	March 31, 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	$	3,811,548	$	697,167	$	7,229		$	74,531	$	—		$	4,590,475
Investment in subsidiaries		597,982		—		(2,096	)		—		(595,886	)		—
Current assets
Cash and cash equivalents		53,441		—		173,340			4,372		—			231,153
Assets from risk management activities		281		—		19,017			833		(833	)		19,298
Other current assets		571,092		14,726		278,909			71,287		(79,106	)		856,908
Intercompany receivables		507,490		—		—			176,488		(683,978	)		—

Total current assets		1,132,304		14,726		471,266			252,980		(763,917	)		1,107,359
Intangible assets		—		—		1,147			—		—			1,147
Goodwill		571,592		132,300		24,282			10,429		—			738,603
Noncurrent assets from risk management activities		—		—		8,913			—		—			8,913
Deferred charges and other assets		280,265		8,701		1,164			16,563		—			306,693

	$	6,393,691	$	852,894	$	511,905		$	354,503	$	(1,359,803	)	$	6,753,190

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,338,843	$	191,724	$	107,420		$	298,838	$	(597,982	)	$	2,338,843
Long-term debt		2,159,148		—		—			327		—			2,159,475

Total capitalization		4,497,991		191,724		107,420			299,165		(597,982	)		4,498,318
Current liabilities
Current maturities of long-term debt		10,000		—		—			131		—			10,131
Short-term debt		20,475		—		40,000			—		(60,475	)		—
Liabilities from risk management activities		22,016		—		3,483			—		(833	)		24,666
Other current liabilities		657,020		7,961		239,894			41,376		(16,535	)		929,716
Intercompany payables		—		555,141		128,837			—		(683,978	)		—

Total current liabilities		709,511		563,102		412,214			41,507		(761,821	)		964,513
Deferred income taxes		501,447		93,550		(12,277	)		11,549		—			594,269
Noncurrent liabilities from risk management activities		—		—		3,854			—		—			3,854
Regulatory cost of removal obligation		317,203		—		—			—		—			317,203
Deferred credits and other liabilities		367,539		4,518		694			2,282		—			375,033

	$	6,393,691	$	852,894	$	511,905		$	354,503	$	(1,359,803	)	$	6,753,190

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30, 2009
	Natural		Regulated		Natural			Pipeline,
	Gas		Transmission		Gas			Storage
	Distribution		and Storage		Marketing			and 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 March 31, 2010, the related condensed consolidated statements of income for the three-month and six-month periods ended March 31, 2010 and 2009, and the condensed consolidated statements of cash flows for the six-month periods ended March 31, 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

May 6, 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 3 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 six months ended March 31, 2010.

RESULTS OF OPERATIONS

The second quarter is our most important earnings quarter, where historically, we have earned about 64 percent of our annual net income. For the three months ended March 31, 2010, we reported net income of $114.1 million, or $1.22 per diluted share compared with net income of $129.0 million, or $1.40 per diluted share in the prior-year quarter. During the three months ended March 31, 2010, we experienced a 26 percent increase in consolidated distribution throughput due to colder weather in most of our service areas, which was partially offset by a 20 percent decrease in consolidated throughput in our regulated transmission and storage segment due to reduced demand and basis spreads. In addition, net income for the second quarter includes the positive impact of a state sales tax refund of $4.5 million which contributed $0.05 per diluted share. The results of our nonregulated operations also include noncash, unrealized net losses of $25.5 million, or ($0.27) per diluted share recognized during the quarter.

We reported net income of $207.5 million, or $2.22 per diluted share for the six months ended March 31, 2010 compared with net income of $205.0 million, or $2.23 per diluted share in the prior-year period. Regulated operations contributed 84 percent of our net income during this period with our nonregulated operations contributing the remaining 16 percent. The primary driver in the year-over-year increase in net income was due to our natural gas marketing segment experiencing a significant increase in unrealized margins. The favorable movement in our unrealized margins was primarily the result of the period-over-period timing of storage withdrawal gains and the associated reversal of unrealized gains into realized gains.

During the six months ended March 31, 2010, colder-than-normal-weather during the current year 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 25 percent year-over-year decrease in consolidated throughput in our regulated transmission and storage segment and a three 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 two 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 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.

The following table presents our consolidated financial highlights for the three and six months ended March 31, 2010 and 2009:


	Three Months Ended					Six Months Ended
	March 31					March 31
	2010		2009			2010			2009
	(In thousands, except per share data)

Operating revenues	$	1,940,266	$	1,821,406		$	3,233,118		$	3,537,738
Gross profit		454,321		460,051			865,170			855,263
Operating expenses		229,781		233,504			450,034			465,522
Operating income		224,540		226,547			415,136			389,741
Miscellaneous income (expense)		49		(1,565	)		(220	)		(1,866	)
Interest charges		39,582		35,533			78,290			74,524
Income before income taxes		185,007		189,449			336,626			313,351
Income tax expense		70,881		60,446			129,170			108,385
Net income	$	114,126	$	129,003		$	207,456		$	204,966
Diluted net income per share	$	1.22	$	1.40		$	2.22		$	2.23

Our consolidated net income (loss) during the three and six months ended March 31, 2010 and 2009 was earned in each of our business segments as follows:


	Three Months Ended
	March 31
	2010			2009		Change
	(In thousands)

Natural gas distribution segment	$	102,731		$	101,576	$	1,155
Regulated transmission and storage segment		12,070			19,465		(7,395	)
Natural gas marketing segment		(2,442	)		3,348		(5,790	)
Pipeline, storage and other segment		1,767			4,614		(2,847	)

Net income	$	114,126		$	129,003	$	(14,877	)


	Six Months Ended
	March 31
	2010		2009		Change
	(In thousands)

Natural gas distribution segment	$	154,179	$	151,709	$	2,470
Regulated transmission and storage segment		20,524		27,126		(6,602	)
Natural gas marketing segment		26,570		13,923		12,647
Pipeline, storage and other segment		6,183		12,208		(6,025	)

Net income	$	207,456	$	204,966	$	2,490

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


	Three Months Ended
	March 31
	2010			2009		Change
	(In thousands, except per share data)

Regulated operations	$	114,801		$	121,041	$	(6,240	)
Nonregulated operations		(675	)		7,962		(8,637	)

Consolidated net income	$	114,126		$	129,003	$	(14,877	)

Diluted EPS from regulated operations	$	1.23		$	1.31	$	(0.08	)
Diluted EPS from nonregulated operations		(0.01	)		0.09		(0.10	)

Consolidated diluted EPS	$	1.22		$	1.40	$	(0.18	)


	Six Months Ended
	March 31
	2010		2009		Change
	(In thousands, except per share data)

Regulated operations	$	174,703	$	178,835	$	(4,132	)
Nonregulated operations		32,753		26,131		6,622

Consolidated net income	$	207,456	$	204,966	$	2,490

Diluted EPS from regulated operations	$	1.87	$	1.95	$	(0.08	)
Diluted EPS from nonregulated operations		0.35		0.28		0.07

Consolidated diluted EPS	$	2.22	$	2.23	$	(0.01	)

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 March 31, 2010 compared with Three Months Ended March 31, 2009

Financial and operational highlights for our natural gas distribution segment for the three months ended March 31, 2010 and 2009 are presented below.


	Three Months Ended
	March 31
	2010		2009		Change
	(In thousands, unless otherwise noted)

Gross profit	$	385,385	$	367,080	$	18,305
Operating expenses		189,821		193,352		(3,531	)

Operating income		195,564		173,728		21,836
Miscellaneous income		776		835		(59	)
Interest charges		29,256		28,821		435

Income before income taxes		167,084		145,742		21,342
Income tax expense		64,353		44,166		20,187

Net income	$	102,731	$	101,576	$	1,155

Consolidated natural gas distribution sales volumes — MMcf		158,530		121,560		36,970
Consolidated natural gas distribution transportation volumes — MMcf		39,294		35,061		4,233

Total consolidated natural gas distribution throughput — MMcf		197,824		156,621		41,203

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.48	$	(0.02	)
Consolidated natural gas distribution average cost of gas per Mcf sold	$	6.19	$	7.10	$	(0.91	)

The following table shows our operating income by natural gas distribution division, in order of total customers served, for the three months ended March 31, 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.


	Three Months Ended
	March 31
	2010		2009		Change
	(In thousands)

Mid-Tex	$	79,843	$	80,374	$	(531	)
Kentucky/Mid-States		31,000		27,404		3,596
Louisiana		22,831		19,782		3,049
West Texas		21,400		14,806		6,594
Mississippi		17,852		16,771		1,081
Colorado-Kansas		14,267		13,623		644
Other		8,371		968		7,403

Total	$	195,564	$	173,728	$	21,836

The $18.3 million increase in natural gas distribution gross profit primarily reflects rate adjustments and increased throughput as follows:


	•	$12.7 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana and Mississippi service areas.


	•	$8.7 million increase as a result of a 26 percent increase in consolidated throughput primarily associated with higher residential and commercial consumption and colder weather in most of our service areas.

	•	$4.9 million increase in revenue-related taxes primarily due to higher revenues, on which the tax is calculated.

These increases were partially offset by:


	•	$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.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, decreased $3.5 million, primarily due to the following:


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

	•	$1.4 million decrease due to lower contract labor expense.

These decreases were partially offset by a $4.8 million increase in employee-related expenses.

Additionally, results for the quarter ended March 31, 2009, were favorably impacted by a one-time tax benefit of $10.5 million. The benefit arose in the prior-year quarter after the Company updated tax rates used to record deferred taxes.

Six Months Ended March 31, 2010 compared with Six Months Ended March 31, 2009

Financial and operational highlights for our natural gas distribution segment for the six months ended March 31, 2010 and 2009 are presented below.


	Six Months Ended
	March 31
	2010		2009		Change
	(In thousands, unless otherwise noted)

Gross profit	$	680,012	$	665,464	$	14,548
Operating expenses		371,701		379,231		(7,530	)

Operating income		308,311		286,233		22,078
Miscellaneous income		1,433		3,956		(2,523	)
Interest charges		58,934		61,708		(2,774	)

Income before income taxes		250,810		228,481		22,329
Income tax expense		96,631		76,772		19,859

Net income	$	154,179	$	151,709	$	2,470

Consolidated natural gas distribution sales volumes — MMcf		257,844		213,006		44,838
Consolidated natural gas distribution transportation volumes — MMcf		74,501		69,397		5,104

Total consolidated natural gas distribution throughput — MMcf		332,345		282,403		49,942

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	$	7.61	$	(1.84	)

The following table shows our operating income by natural gas distribution division, in order of total customers served, for the six months ended March 31, 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.


	Six Months Ended
	March 31
	2010		2009		Change
	(In thousands)

Mid-Tex	$	130,224	$	133,052	$	(2,828	)
Kentucky/Mid-States		48,803		46,429		2,374
Louisiana		36,238		34,366		1,872
West Texas		33,157		22,819		10,338
Mississippi		27,654		25,206		2,448
Colorado-Kansas		22,873		22,224		649
Other		9,362		2,137		7,225

Total	$	308,311	$	286,233	$	22,078

The $14.5 million increase in natural gas distribution gross profit primarily reflects rate adjustments and increased throughput as follows:


	•	$22.5 million net increase in rate adjustments, primarily in the West Texas, Mid-Tex, Louisiana and Mississippi service areas.

	•	$11.0 million increase as a result of an 18 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:


	•	$8.3 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.

	•	$2.7 million decrease due to a decrease in revenue-related taxes, primarily due to a decrease in revenues on which the tax is calculated.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income and asset impairments decreased $7.5 million, primarily due to the following:


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


	•	$2.3 million decrease in taxes other than income due to lower franchise fees and state gross receipts taxes.


	•	$2.2 million decrease in contract labor expenses.

	•	$1.8 million decrease due to the absence of an impairment charge for available-for-sale securities recorded in December 2008.

	•	$1.3 million decrease due to lower insurance premiums.

These decreases were partially offset by a $7.6 million increase in employee-related expenses.

Miscellaneous income decreased $2.5 million due to lower interest income. Interest charges decreased $2.8 million primarily due to lower short-term debt balances and interest rates.

Results for the six months ended March 31, 2009, were favorably impacted by the aforementioned one-time tax benefit of $10.5 million related to updated tax rates used to record deferred taxes.

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the six months ended March 31, 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 $19.0 million resulting from ratemaking activity became effective in the six months ended March 31, 2010 as summarized below:


	Annual Increase to
Rate Action	Operating Income
	(In thousands)

Rate case filings	$	9,195
Annual rate filing mechanisms		7,172
Other rate activity		2,630

	$	18,997

Additionally, the following ratemaking efforts were in progress during the second quarter of fiscal 2010 but had not been completed as of March 31, 2010.


			Operating
			Income
Division	Rate Action	Jurisdiction	Requested
			(In thousands)

Atmos Pipeline — Texas	GRIP ⁽¹⁾	RRC ⁽²⁾	$	13,540
Colorado/Kansas	Rate Case	Kansas		6,015
Kentucky/Mid-States	PRP ⁽³⁾	Georgia		764
	Rate Case ⁽⁴⁾	Kentucky		9,486
	Rate Case	Missouri		6,439
Louisiana	RSC ⁽⁵⁾	Louisiana		1,841
	RSC	Louisiana		4,296
Mid-Tex	GRIP ⁽¹⁾⁽⁶⁾	Dallas & RRC		2,985
	Rate Review Mechanism (RRM)	Settled Cities		56,827
West Texas	GRIP ⁽¹⁾	RRC		370

			$	102,563


⁽¹⁾		Gas Reliability Infrastructure Program (GRIP) is a rate adjustment that allows utilities to recover additional invested capital without filing a full rate case.

⁽²⁾		Rate actions for the Atmos Pipeline — Texas Division are under the jurisdiction of the Railroad Commission of Texas (RRC).

⁽³⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽⁴⁾		The Company and Attorney General of the Commonwealth of Kentucky have filed a joint settlement with the Kentucky Commission requesting approval of a settlement in the amount of $5.9 million. Additionally, the settlement recommends moving bad debt recovery related to gas costs from base rates to Gas Cost Adjustment rates for recovery ($0.7 million) and approval of a pipeline replacement program.

⁽⁵⁾		The Louisiana Commission Staff recommended an increase of $1.7 million effective April 1, 2010, which the Commission accepted.

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

Additionally, in April 2010, our West Texas Division filed rate review mechanism filings with the City of Amarillo, City of Lubbock and West Texas Cities group for a combined increase of $6.6 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

Georgia

2,935

3/31/2010

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

9,195


⁽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 Company had no GRIP filings approved as of March 31, 2010. However, on April 20, 2010, the RRC approved an Atmos Pipeline — Texas GRIP filing in the amount of $13.4 million.

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 in our Mid-Tex and West Texas divisions, stable rate filings in the Mississippi Division and a rate

stabilization clause in the Louisiana Division. The following table summarizes filings made under our various annual rate filing mechanisms for the six months ended March 31, 2010.

Additional

Annual

Test Year

Operating

Effective

Division

Jurisdiction

Ended

Income

Date

(In thousands)

2010 Filings:

Mississippi

6/30/2009

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

7,172

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the six months ended March 31, 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 March 31, 2010 compared with Three Months Ended March 31, 2009

Financial and operational highlights for our regulated transmission and storage segment for the three months ended March 31, 2010 and 2009 are presented below.


	Three Months Ended
	March 31
	2010			2009		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	33,214		$	27,061	$	6,153
Third-party transportation		16,335			23,846		(7,511	)
Storage and park and lend services		2,673			2,657		16
Other		2,959			5,670		(2,711	)

Gross profit		55,181			59,234		(4,053	)
Operating expenses		28,479			24,905		3,574

Operating income		26,702			34,329		(7,627	)
Miscellaneous income (expense)		(20	)		283		(303	)
Interest charges		7,954			7,349		605

Income before income taxes		18,728			27,263		(8,535	)
Income tax expense		6,658			7,798		(1,140	)

Net income	$	12,070		$	19,465	$	(7,395	)

Gross pipeline transportation volumes — MMcf		192,441			193,356		(915	)

Consolidated pipeline transportation volumes — MMcf		98,418			123,285		(24,867	)

The $4.1 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


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

	•	$2.8 million decrease due to the absence of excess inventory sales.

	•	$2.6 million decrease in market-based demand fees, priority reservation fees and compression activity associated with lower throughput.

These decreases were partially offset by the following:


	•	$3.2 million increase due to increased through system volumes primarily associated with colder weather in our Mid-Tex service area.

	•	$1.5 million increase associated with our GRIP filings.

Operating expenses increased $3.6 million primarily due to higher levels of pipeline maintenance activities and employee-related expenses.

Six Months Ended March 31, 2010 compared with Six Months Ended March 31, 2009

Financial and operational highlights for our regulated transmission and storage segment for the six months ended March 31, 2010 and 2009 are presented below.


	Six Months Ended
	March 31
	2010		2009		Change
	(In thousands, unless otherwise noted)

Mid-Tex transportation	$	59,925	$	51,413	$	8,512
Third-party transportation		31,577		49,212		(17,635	)
Storage and park and lend services		5,278		5,014		264
Other		5,261		8,277		(3,016	)

Gross profit		102,041		113,916		(11,875	)
Operating expenses		54,267		60,217		(5,950	)

Operating income		47,774		53,699		(5,925	)
Miscellaneous income		23		1,098		(1,075	)
Interest charges		15,922		15,428		494

Income before income taxes		31,875		39,369		(7,494	)
Income tax expense		11,351		12,243		(892	)

Net income	$	20,524	$	27,126	$	(6,602	)

Gross pipeline transportation volumes — MMcf		350,214		385,528		(35,314	)

Consolidated pipeline transportation volumes — MMcf		194,356		259,143		(64,787	)

The $11.9 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$7.5 million decrease due to lower transportation fees on through-system deliveries due to narrower basis spreads.

	•	$3.9 million decrease in market-based demand fees, priority reservation fees and compression activity associated with lower throughput.

	•	$2.8 million decrease due to the absence of excess inventory sales.

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

Operating expenses decreased $6.0 million primarily due to lower levels of pipeline maintenance activities.

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 March 31, 2010 compared with Three Months Ended March 31, 2009

Financial and operational highlights for our natural gas marketing segment for the three months ended March 31, 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
	March 31
	2010			2009			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	17,126		$	23,165		$	(6,039	)
Asset optimization ⁽¹⁾		24,891			(2,073	)		26,964

		42,017			21,092			20,925
Unrealized margins		(35,537	)		2,452			(37,989	)

Gross profit		6,480			23,544			(17,064	)
Operating expenses		7,702			13,165			(5,463	)

Operating income (loss)		(1,222	)		10,379			(11,601	)
Miscellaneous income		287			118			169
Interest charges		2,820			3,461			(641	)

Income (loss) before income taxes		(3,755	)		7,036			(10,791	)
Income tax expense (benefit)		(1,313	)		3,688			(5,001	)

Net income (loss)	$	(2,442	)	$	3,348		$	(5,790	)

Gross natural gas marketing sales volumes — MMcf		123,877			123,066			811

Consolidated natural gas marketing sales volumes — MMcf		104,893			104,973			(80	)

Net physical position (Bcf)		22.7			21.9			0.8


⁽¹⁾		Net of storage fees of $3.5 million and $2.9 million.

AEM’s asset optimization activities contributed 59 percent to total realized margins during the second quarter of fiscal 2010, with the delivered gas business contributing the remaining 41 percent. The $20.9 million increase in realized gross profit reflected:


	•	A $26.9 million increase in asset optimization margins primarily attributable to the timing of the settlement of open positions. During the three months ended March 31, 2010, AEM recognized the gains it had captured from its optimization activities during the first quarter of fiscal 2010. In the prior year, AEM recognized similar gains from its optimization activities during the first quarter of fiscal 2009.

	•	A $6.0 million decrease in realized delivered gas margins due to lower per-unit margins as a result of narrowing basis spreads.

The increase in realized gross profit was more than offset by a $38.0 million decrease in unrealized margins primarily due to the realization during the current quarter of unrealized gains that had been recorded in the first quarter of fiscal 2010.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, decreased $5.5 million primarily due to a decrease in employee and other administrative costs.

Six Months Ended March 31, 2010 compared with Six Months Ended March 31, 2009

Financial and operational highlights for our natural gas marketing segment for the six months ended March 31, 2010 and 2009 are presented below.


	Six Months Ended
	March 31
	2010		2009			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	33,213	$	41,718		$	(8,505	)
Asset optimization ⁽¹⁾		31,320		34,866			(3,546	)

		64,533		76,584			(12,051	)
Unrealized margins		1,732		(23,017	)		24,749

Gross profit		66,265		53,567			12,698
Operating expenses		17,803		22,675			(4,872	)

Operating income		48,462		30,892			17,570
Miscellaneous income		495		419			76
Interest charges		5,198		7,363			(2,165	)

Income before income taxes		43,759		23,948			19,811
Income tax expense		17,189		10,025			7,164

Net income	$	26,570	$	13,923		$	12,647

Gross natural gas marketing sales volumes — MMcf		226,138		233,724			(7,586	)

Consolidated natural gas marketing sales volumes — MMcf		192,122		198,281			(6,159	)

Net physical position (Bcf)		22.7		21.9			0.8


⁽¹⁾		Net of storage fees of $6.0 million and $5.5 million.

AEM’s delivered gas business contributed 51 percent to total realized margins during the six months ended March 31, 2010 with asset optimization activities contributing the remaining 49 percent. The $12.0 million decrease in realized gross profit reflected the following:


	•	$8.5 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 $0.15/Mcf in the current-year period compared with $0.18/Mcf in the prior-year period, while delivered sales volumes were three percent lower in the current-year period when compared with the prior-year period.

	•	$3.5 million decrease in asset optimization margins primarily attributable to lower natural gas volatility in the current-year period which created fewer opportunities to optimize our storage assets.

The decrease in realized gross profit was more than offset by a $24.7 million increase 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 $4.9 million primarily due to a decrease in employee and other administrative costs.

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 March 31, 2010 and 2009.


	March 31
	2010			2009
	(In millions, unless otherwise noted)

Economic value	$	0.6		$	33.4
Associated unrealized (gains) losses		7.5			(2.4	)

Subtotal		8.1			31.0
Related fees ⁽¹⁾		(13.8	)		(16.0	)

Potential gross profit (loss)	$	(5.7	)	$	15.0

Net physical position (Bcf)		22.7			21.9


⁽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 March 31, 2010 and 2009.

During the six months ended March 31, 2010, AEM’s economic value decreased from $28.6 million, or $2.07/Mcf at September 30, 2009 to $0.6 million, or $0.02/Mcf. This compares unfavorably to AEM’s economic value at March 31, 2009 of $33.4 million, or $1.53/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, cash prices continued to fall and weak market fundamentals created limited opportunities to capture economic value. Therefore, AEM injected additional gas into storage. However, as of March 31, 2010, AEM had established just a limited number of positions as it believes future market conditions will create improved opportunities to capture spread values.

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 calculated as of March 31, 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 March 31, 2010 compared with Three Months Ended March 31, 2009

Financial and operational highlights for our pipeline, storage and other segment for the three months ended March 31, 2010 and 2009 are presented below.


	Three Months Ended
	March 31
	2010			2009			Change
	(In thousands)

Asset optimization	$	7,392		$	15,157		$	(7,765	)
Storage and transportation services		3,093			3,312			(219	)
Other		1,200			350			850
Unrealized margins		(4,004	)		(8,203	)		4,199

Gross profit		7,681			10,616			(2,935	)
Operating expenses		4,185			2,591			1,594

Operating income		3,496			8,025			(4,529	)
Miscellaneous income		980			2,060			(1,080	)
Interest charges		1,526			677			849

Income before income taxes		2,950			9,408			(6,458	)
Income tax expense		1,183			4,794			(3,611	)

Net income	$	1,767		$	4,614		$	(2,847	)

Gross profit from our pipeline, storage and other segment decreased $2.9 million primarily due to the following:


	•	$6.5 million decrease in margins earned from utilizing assets subject to APS’ asset management plans due to fewer trading opportunities this year compared to the prior-year period which created a less volatile natural gas market.

	•	$1.8 million decrease in basis gains earned from utilizing leased capacity.

	•	$4.2 million increase in unrealized margins associated with our asset optimization activities.

Operating expenses increased $1.6 million primarily due to legal and other administrative costs.

Six Months Ended March 31, 2010 compared with Six Months Ended March 31, 2009

Financial and operational highlights for our pipeline, storage and other segment for the six months ended March 31, 2010 and 2009 are presented below.


	Six Months Ended
	March 31
	2010		2009			Change
	(In thousands)

Asset optimization	$	7,489	$	20,624		$	(13,135	)
Storage and transportation services		6,427		6,627			(200	)
Other		1,144		1,339			(195	)
Unrealized margins		2,611		(5,429	)		8,040

Gross profit		17,671		23,161			(5,490	)
Operating expenses		7,082		4,416			2,666

Operating income		10,589		18,745			(8,156	)
Miscellaneous income		1,433		4,221			(2,788	)
Interest charges		1,840		1,413			427

Income before income taxes		10,182		21,553			(11,371	)
Income tax expense		3,999		9,345			(5,346	)

Net income	$	6,183	$	12,208		$	(6,025	)

Gross profit from our pipeline, storage and other segment decreased $5.5 million primarily due to the following:


	•	$6.4 million decrease from lower margins earned on storage optimization activities.

	•	$3.7 million decrease in basis gains earned from utilizing leased capacity.

	•	$3.0 million decrease from lower margins earned on asset management plans.

	•	$8.0 million increase in unrealized margins associated with our asset optimization activities.

Operating expenses increased $2.7 million primarily due to the following:


	•	$1.4 million increase in other administrative costs.

	•	$0.7 million increase in employee costs.

	•	$0.3 million increase in property taxes.

Miscellaneous income decreased $2.8 million due to lower interest expense incurred 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.

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 six months ended March 31, 2010 and 2009 are presented below.


	Six Months Ended March 31
	2010			2009			Change
	(In thousands)

Total cash provided by (used in)
Operating activities	$	483,458		$	614,622		$	(131,164	)
Investing activities		(233,575	)		(225,255	)		(8,320	)
Financing activities		(129,933	)		46,001			(175,934	)

Change in cash and cash equivalents		119,950			435,368			(315,418	)
Cash and cash equivalents at beginning of period		111,203			46,717			64,486

Cash and cash equivalents at end of period	$	231,153		$	482,085		$	(250,932	)

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 six months ended March 31, 2010, we generated operating cash flow of $483.5 million from operating activities compared with $614.6 million for the six months ended March 31, 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 $520 million to $535 million. For the six months ended March 31, 2010, capital expenditures were $232.6 million compared with $221.3 million for the six months ended March 31, 2009. The $11.3 million increase in capital expenditures primarily reflects spending for the relocation of our information technology data center to a new facility.

Cash flows from financing activities

For the six months ended March 31, 2010, our financing activities used $129.9 million of cash compared with a cash inflow of $46.0 million in the prior-year period, primarily due to the following:


	•	$446.2 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.

	•	$3.8 million decrease 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.

	•	$2.1 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.

These decreases in financing cash flows were partially offset by a $277.6 million increase due to lower short-term debt repayments. In the current-year period, $75.9 million of short-term debt was repaid, compared with $353.5 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 following table summarizes our share issuances for the six months ended March 31, 2010 and 2009.


	Six Months Ended
	March 31
	2010		2009

Shares issued:
Direct Stock Purchase Plan		103,529		220,361
Retirement Savings Plan and Trust		79,722		330,990
1998 Long-Term Incentive Plan		409,535		579,990
Outside Directors Stock-for-Fee Plan		2,040		1,590

Total shares issued		594,826		1,132,931

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 quarter of fiscal 2010 compared to the second quarter of 2009 caused us to issue fewer shares during the quarter.

Credit Facilities

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

We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. As of March 31, 2010, the amount available to us under our credit facilities, net of outstanding letters of credit, was approximately $1.1 billion. 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.

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. Fitch still maintains a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB+

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 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 March 31, 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 March 31, 2010, September 30, 2009 and March 31, 2009:


	March 31, 2010				September 30, 2009				March 31, 2009
	(In thousands, except percentages)

Short-term debt	$	—	—		$	72,550	1.6	%	$	—	—
Long-term debt		2,169,606	48.1	%		2,169,531	49.1	%		2,569,366	54.1	%
Shareholders’ equity		2,338,843	51.9	%		2,176,761	49.3	%		2,178,494	45.9	%

Total	$	4,508,449	100.0	%	$	4,418,842	100.0	%	$	4,747,860	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 48.1 percent at March 31, 2010, 50.7 percent at September 30, 2009 and 54.1 percent at March 31, 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 six months ended March 31, 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.

Risk Management Activities

We conduct risk management activities through our natural gas distribution, natural gas marketing and pipeline, storage and other segments. In our natural gas distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases.

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

The following table shows the components of the change in fair value of our natural gas distribution segment’s financial instruments for the three and six months ended March 31, 2010 and 2009:


	Three Months Ended						Six Months Ended
	March 31						March 31
	2010			2009			2010			2009
	(In thousands)

Fair value of contracts at beginning of period	$	(17,470	)	$	(51,314	)	$	(14,166	)	$	(63,677	)
Contracts realized/settled		(13,390	)		(47,231	)		(34,418	)		(100,996	)
Fair value of new contracts		(1,288	)		277			(2,236	)		(4,006	)
Other changes in value		10,413			76,405			29,085			146,816

Fair value of contracts at end of period	$	(21,735	)	$	(21,863	)	$	(21,735	)	$	(21,863	)

The fair value of our natural gas distribution segment’s financial instruments at March 31, 2010 is presented below by time period and fair value source:


	Fair Value of Contracts at March 31, 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	$	(21,735	)	$	—	$	—	$	—	$	(21,735	)
Prices based on models and other valuation methods		—			—		—		—		—

Total Fair Value	$	(21,735	)	$	—	$	—	$	—	$	(21,735	)

The following table shows the components of the change in fair value of our natural gas marketing segment’s financial instruments for the three and six months ended March 31, 2010 and 2009:


	Three Months Ended						Six Months Ended
	March 31						March 31
	2010			2009			2010			2009
	(In thousands)

Fair value of contracts at beginning of period	$	32,306		$	(28,598	)	$	26,698		$	16,542
Contracts realized/settled		(22,030	)		6,972			(24,242	)		(13,275	)
Fair value of new contracts		—			—			—			—
Other changes in value		3,951			(11,020	)		11,771			(35,913	)

Fair value of contracts at end of period		14,227			(32,646	)		14,227			(32,646	)
Netting of cash collateral		7,199			79,098			7,199			79,098

Cash collateral and fair value of contracts at period end	$	21,426		$	46,452		$	21,426		$	46,452

The fair value of our natural gas marketing segment’s financial instruments at March 31, 2010 is presented below by time period and fair value source:


	Fair Value of Contracts at March 31, 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	$	9,168	$	5,746	$	(687	)	$	—	$	14,227
Prices based on models and other valuation methods		—		—		—			—		—

Total Fair Value	$	9,168	$	5,746	$	(687	)	$	—	$	14,227

Pension and Postretirement Benefits Obligations

For the six months ended March 31, 2010 and 2009, our total net periodic pension and other benefits cost was $25.4 million and $24.1 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 expect we will be required to contribute less than $5 million to our pension plans by September 15, 2010. The need for this funding reflects the decline in the fair value of the plans’ assets resulting from the unfavorable market conditions experienced during 2008 and 2009. This contribution will increase the level of our plan assets to achieve a desirable PPA funding threshold. With respect to our postretirement medical plans, we anticipate contributing a total of approximately $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 six month periods ended March 31, 2010 and 2009.

Natural Gas Distribution Sales and Statistical Data


	Three Months Ended				Six Months Ended
	March 31				March 31
	2010		2009		2010		2009

METERS IN SERVICE, end of period
Residential		2,937,163		2,937,865		2,937,163		2,937,865
Commercial		272,925		274,449		272,925		274,449
Industrial		2,496		2,212		2,496		2,212
Public authority and other		9,461		9,243		9,461		9,243

Total meters		3,222,045		3,223,769		3,222,045		3,223,769

INVENTORY STORAGE BALANCE — Bcf		24.4		31.9		24.4		31.9
SALES VOLUMES — MMcf ⁽¹⁾
Gas sales volumes
Residential		100,858		74,467		161,404		128,675
Commercial		46,615		36,689		77,105		65,018
Industrial		6,660		5,758		11,979		11,158
Public authority and other		4,397		4,646		7,356		8,155

Total gas sales volumes		158,530		121,560		257,844		213,006
Transportation volumes		40,545		36,169		76,786		71,454

Total throughput		199,075		157,729		334,630		284,460

OPERATING REVENUES (000’s) ⁽¹⁾
Gas sales revenues
Residential	$	897,249	$	785,456	$	1,405,160	$	1,432,556
Commercial		366,260		334,815		585,680		637,509
Industrial		41,777		46,259		72,810		96,414
Public authority and other		32,386		36,991		52,584		68,385

Total gas sales revenues		1,337,672		1,203,521		2,116,234		2,234,864
Transportation revenues		18,219		16,889		34,694		32,655
Other gas revenues		10,097		10,010		17,954		18,869

Total operating revenues	$	1,365,988	$	1,230,420	$	2,168,882	$	2,286,388

Average transportation revenue per Mcf	$	0.45	$	0.47	$	0.45	$	0.46
Average cost of gas per Mcf sold	$	6.19	$	7.10	$	5.77	$	7.61

See footnote following these tables.

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


	Three Months Ended				Six Months Ended
	March 31				March 31
	2010		2009		2010		2009

CUSTOMERS, end of period
Industrial		727		698		727		698
Municipal		62		61		62		61
Other		498		527		498		527

Total		1,287		1,286		1,287		1,286

INVENTORY STORAGE BALANCE — Bcf
Natural gas marketing		20.1		20.4		20.1		20.4
Pipeline, storage and other		1.2		2.0		1.2		2.0

Total		21.3		22.4		21.3		22.4

REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf ⁽¹⁾		192,441		193,356		350,214		385,528
NATURAL GAS MARKETING SALES VOLUMES — MMcf ⁽¹⁾		123,877		123,066		226,138		233,724
OPERATING REVENUES (000’s) ⁽¹⁾
Regulated transmission and storage	$	55,181	$	59,234	$	102,041	$	113,916
Natural gas marketing		692,152		708,658		1,236,423		1,496,153
Pipeline, storage and other		9,050		12,272		20,673		28,720

Total operating revenues	$	756,383	$	780,164	$	1,359,137	$	1,638,789

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 six months ended March 31, 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 March 31, 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 second 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 six months ended March 31, 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 5.	*Other Information*

At the Annual Meeting of Shareholders of Atmos Energy Corporation on February 3, 2010, 81,757,639 votes were cast as follows:


			Votes
	Votes		Withheld/		Votes		Broker
	For		Against		Abstaining		Non-Votes

Class I Director:
Kim R. Cocklin		64,574,447		1,217,145		—		15,966,047
Class III Directors:
Robert W. Best		63,891,229		1,900,363		—		15,966,047
Robert C. Grable		64,932,497		859,095		—		15,966,047
Phillip E. Nichol		64,102,746		1,688,846		—		15,966,047
Charles K. Vaughan		64,210,783		1,580,809		—		15,966,047
Proposal regarding declassification of the Board of Directors		79,072,204		1,757,120		928,315		—
Ratification of the Audit Committee’s engagement of Ernst & Young LLP to serve as the Company’s registered independent public accounting firm for fiscal year 2010		80,853,517		734,364		169,758		—

Mr. Travis W. Bain II, a Class I director and Mr. Thomas J. Garland, a Class III director, retired on February 3, 2010 at the conclusion of the Annual Meeting of Shareholders, in accordance with the Board’s mandatory retirement policy. The remaining directors will continue to serve until the expiration of their terms. The term of the Class I directors, Kim R. Cocklin, Richard W. Douglas, Ruben E. Esquivel and Richard K. Gordon, will expire in 2011. The term of the Class II directors, Richard W. Cardin, Thomas C. Meredith, Nancy K. Quinn, Stephen R. Springer and Richard Ware II, will expire in 2012. The term of the Class III directors, Robert W. Best, Robert C. Grable, Phillip E. Nichol and Charles K. Vaughan will expire in 2013. As a result of the declassification of the Board, which was approved by our shareholders, beginning with the 2011 Annual Meeting of Shareholders, each director elected will serve a one-year term.


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: May 6, 2010

EXHIBITS INDEX
Item 6


				Page Number or
Exhibit				Incorporation by
Number			Description	Reference to

	3	.1	Restated Articles of Incorporation of Atmos Energy Corporation — Texas (As Amended Effective February 3, 2010)
	3	.2	Restated Articles of Incorporation of Atmos Energy Corporation — Virginia (As Amended Effective February 3, 2010)
	12		Computation of ratio of earnings to fixed charges
	15		Letter regarding unaudited interim financial information
	31		Rule 13a-14(a)/15d-14(a) Certifications
	32		Section 1350 Certifications*


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

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 5. Other Information Item 6. Exhibits

Exhibits

EX-3.1 EX-3.2 EX-12 EX-15 EX-31 EX-32

ATO 10-Q Quarter ended March 31, 2010

Exhibits