ATO 10-Q Quarterly Report Dec. 31, 2009

ATMOS ENERGY CORP

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10-Q 1 d70859e10vq.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 December 31, 2009
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)


Texas and Virginia (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 corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).* Yes o No o

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

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


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

(Do not check if a smaller reporting company)

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

Number of shares outstanding of each of the issuer’s classes of common stock, as of January 28, 2010.


Class		Shares Outstanding

No Par Value		93,054,189

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 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 6. Exhibits
SIGNATURE
EXHIBITS INDEX Item 6
EX-12
EX-15
EX-31
EX-32

GLOSSARY OF KEY TERMS


AEC		Atmos Energy Corporation
AEH		Atmos Energy Holdings, Inc.
AEM		Atmos Energy Marketing, LLC
AOCI		Accumulated other comprehensive income
APS		Atmos Pipeline and Storage, LLC
Bcf		Billion cubic feet
FASB		Financial Accounting Standards Board
Fitch		Fitch Ratings, Ltd.
GAAP		Generally Accepted Accounting Principles
GRIP		Gas Reliability Infrastructure Program
GSRS		Gas System Reliability Surcharge
ISRS		Infrastructure System Replacement Surcharge
LPSC		Louisiana Public Service Commission
Mcf		Thousand cubic feet
MMcf		Million cubic feet
MPSC		Mississippi Public Service Commission
Moody’s		Moody’s Investors Services, Inc.
NYMEX		New York Mercantile Exchange, Inc.
PPA		Pension Protection Act of 2006
PRP		Pipeline Replacement Program
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


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

ASSETS
Property, plant and equipment	$	6,196,043		$	6,086,618
Less accumulated depreciation and amortization		1,672,855			1,647,515

Net property, plant and equipment		4,523,188			4,439,103
Current assets
Cash and cash equivalents		174,829			111,203
Accounts receivable, net		597,012			232,806
Gas stored underground		399,582			352,728
Other current assets		115,155			132,203

Total current assets		1,286,578			828,940
Goodwill and intangible assets		739,907			740,064
Deferred charges and other assets		325,751			335,659

	$	6,875,424		$	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:
December 31, 2009 — 92,970,838 shares;
September 30, 2009 — 92,551,709 shares	$	465		$	463
Additional paid-in capital		1,802,606			1,791,129
Retained earnings		467,449			405,353
Accumulated other comprehensive loss		(12,444	)		(20,184	)

Shareholders’ equity		2,258,076			2,176,761
Long-term debt		2,159,470			2,169,400

Total capitalization		4,417,546			4,346,161
Current liabilities
Accounts payable and accrued liabilities		578,805			207,421
Other current liabilities		413,754			457,319
Short-term debt		179,712			72,550
Current maturities of long-term debt		10,131			131

Total current liabilities		1,182,402			737,421
Deferred income taxes		588,423			570,940
Regulatory cost of removal obligation		314,126			321,086
Deferred credits and other liabilities		372,927			368,158

	$	6,875,424		$	6,343,766

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


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

Operating revenues
Natural gas distribution segment	$	802,894		$	1,055,968
Regulated transmission and storage segment		46,860			54,682
Natural gas marketing segment		544,271			787,495
Pipeline, storage and other segment		11,623			16,448
Intersegment eliminations		(112,796	)		(198,261	)

		1,292,852			1,716,332
Purchased gas cost
Natural gas distribution segment		508,267			757,584
Regulated transmission and storage segment		—			—
Natural gas marketing segment		484,486			757,472
Pipeline, storage and other segment		1,633			3,903
Intersegment eliminations		(112,383	)		(197,839	)

		882,003			1,321,120

Gross profit		410,849			395,212
Operating expenses
Operation and maintenance		123,862			132,677
Depreciation and amortization		53,839			53,126
Taxes, other than income		42,552			44,137
Asset impairments		—			2,078

Total operating expenses		220,253			232,018

Operating income		190,596			163,194
Miscellaneous expense		(269	)		(301	)
Interest charges		38,708			38,991

Income before income taxes		151,619			123,902
Income tax expense		58,289			47,939

Net income	$	93,330		$	75,963

Basic net income per share	$	1.00		$	0.83

Diluted net income per share	$	1.00		$	0.83

Cash dividends per share	$	0.335		$	0.330

Weighted average shares outstanding:
Basic		92,152			90,471

Diluted		92,509			90,769

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended
	December 31
	2009			2008
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities
Net income	$	93,330		$	75,963
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		53,839			53,126
Charged to other accounts		36			8
Deferred income taxes		12,832			27,175
Other		4,382			7,683
Net assets/liabilities from risk management activities		(26,891	)		9,213
Net change in operating assets and liabilities		(42,372	)		(22,453	)

Net cash provided by operating activities		95,156			150,715
Cash Flows From Investing Activities
Capital expenditures		(115,439	)		(107,367	)
Other, net		(1,873	)		(1,210	)

Net cash used in investing activities		(117,312	)		(108,577	)
Cash Flows From Financing Activities
Net increase in short-term debt		111,335			5,312
Repayment of long-term debt		—			(278	)
Cash dividends paid		(31,234	)		(30,165	)
Issuance of common stock		5,681			6,075

Net cash provided by (used in) financing activities		85,782			(19,056	)

Net increase in cash and cash equivalents		63,626			23,082
Cash and cash equivalents at beginning of period		111,203			46,717

Cash and cash equivalents at end of period	$	174,829		$	69,799

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2009


1.	Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. 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 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.


2.	Unaudited Interim 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 three-month period ended December 31, 2009 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 December 31, 2009 balance sheet date through the date these financial statements were filed with the Securities and Exchange

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Commission (SEC). 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.

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 three months ended December 31, 2009.

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 Financial Accounting Standards Board (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 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 months ended December 31, 2008.


	Three Months Ended
	December 31, 2008
	(In thousands, except
	per share amounts)

Basic Earnings Per Share
Basic EPS — as previously reported	$	0.84
Basic EPS — as adjusted	$	0.83
Weighted average shares outstanding — as previously reported		90,471
Weighted average shares outstanding — as adjusted		90,471
Diluted Earnings Per Share
Diluted EPS — as previously reported	$	0.83
Diluted EPS — as adjusted	$	0.83
Weighted average shares outstanding — as previously reported		91,066
Weighted average shares outstanding — as adjusted		90,769

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 December 31, 2009, 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 be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities, and the regulatory cost of removal obligation is reported separately.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant regulatory assets and liabilities as of December 31, 2009 and September 30, 2009 included the following:


	December 31,		September 30,
	2009		2009
	(In thousands)

Regulatory assets:
Pension and postretirement benefit costs	$	195,015	$	197,743
Merger and integration costs, net		7,049		7,161
Deferred gas costs		53,818		22,233
Environmental costs		988		866
Rate case costs		4,137		5,923
Deferred franchise fees		6,893		10,014
Deferred income taxes, net		639		639
Other		6,323		6,218

	$	274,862	$	250,797


Regulatory liabilities:
Deferred gas costs	$	36,826	$	110,754
Regulatory cost of removal obligation		336,315		335,428
Other		7,890		7,960

	$	381,031	$	454,142

Currently 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 applicable state regulatory commissions.

Comprehensive income

The following table presents the components of comprehensive income, net of related tax, for the three-month periods ended December 31, 2009 and 2008:


	Three Months Ended
	December 31
	2009		2008
	(In thousands)

Net income	$	93,330	$	75,963
Unrealized holding gains (losses) on investments, net of tax expense (benefit) of $390 and $(3,330) for the three months ended December 31, 2009 and 2008		664		(5,433	)
Other than temporary impairment of investments, net of tax expense of $790 for the three months ended December 31, 2008		—		1,288
Amortization of interest rate hedging transactions, net of tax expense of $248 and $482 for the three months ended December 31, 2009 and 2008		422		787
Net unrealized gains (losses) on commodity hedging transactions, net of tax expense (benefit) of $4,254 and $(13,817) for the three months ended December 31, 2009 and 2008		6,654		(22,544	)

Comprehensive income	$	101,070	$	50,061

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	December 31,			September 30,
	2009			2009
	(In thousands)

Accumulated other comprehensive loss:
Unrealized holding gains on investments	$	3,124		$	2,460
Treasury lock agreements		(7,076	)		(7,498	)
Cash flow hedges		(8,492	)		(15,146	)

	$	(12,444	)	$	(20,184	)


3.	Financial Instruments

We currently use financial instruments to mitigate commodity price risk in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. 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. During the first quarter there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas distribution, natural gas marketing and pipeline, storage and other segments. However, our pipeline, storage and other segment uses financial instruments acquired from Atmos Energy Marketing, LLC (AEM) on the same terms that AEM received from an independent counterparty. On a consolidated basis, these financial instruments are reported in the natural gas marketing segment. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.

Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated 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 anticipate hedging approximately 29 percent, or 26.9 Bcf of the 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 55 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 December 31, 2009, AEH had net open positions (including existing storage) of 0.5 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 through fiscal 2019.

Quantitative Disclosures Related to Financial Instruments

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

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


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

Commodity contracts	Fair Value		—		(17,318	)		(2,420	)
	Cash Flow		—		27,127			(4,660	)
	Not designated		22,182		44,903			450

			22,182		54,712			(6,630	)

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 December 31, 2009 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 $1.3 million of cash due on margin as of December 31, 2009 and $11.7 million of cash held on deposit in margin accounts as of 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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)

December 31, 2009:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	37,258		$	37,258
Noncurrent commodity contracts	Deferred charges and other assets		—			5,920			5,920
Liability Financial Instruments
Current commodity contracts	Other current liabilities		—			(36,276	)		(36,276	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(2,053	)		(2,053	)

Total			—			4,849			4,849
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		849			39,230			40,079
Noncurrent commodity contracts	Deferred charges and other assets		105			7,764			7,869
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(17,076	)		(18,157	)		(35,233	)
Noncurrent commodity contracts	Deferred credits and other liabilities		(1,348	)		(1,380	)		(2,728	)

Total			(17,470	)		27,457			9,987

Total Financial Instruments		$	(17,470	)	$	32,306		$	14,836


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


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

September 30, 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Impact of Financial Instruments on the Income Statement

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

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 December 31, 2009 and 2008 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $45.3 million and $20.4 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

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 months ended December 31, 2009 and 2008 is presented below.


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

Commodity contracts	$	(2,182	)	$	(457	)	$	(2,639	)
Fair value adjustment for natural gas inventory designated as the hedged item		43,312			5,871			49,183

Total impact on revenue	$	41,130		$	5,414		$	46,544

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	64		$	—		$	64
Timing ineffectiveness		41,066			5,414			46,480

	$	41,130		$	5,414		$	46,544


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

Commodity contracts	$	25,683		$	3,939		$	29,622
Fair value adjustment for natural gas inventory designated as the hedged item		(11,860	)		(1,553	)		(13,413	)

Total impact on revenue	$	13,823		$	2,386		$	16,209

The impact on revenue is comprised of the following:
Basis ineffectiveness	$	1,952		$	—		$	1,952
Timing ineffectiveness		11,871			2,386			14,257

	$	13,823		$	2,386		$	16,209

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 months ended December 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized or will realize when the underlying physical and financial transactions are settled.


	Three Months Ended December 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	$	—		$	(23,337	)	$	220	$	(23,117	)
Loss arising from ineffective portion of commodity contracts		—			(1,218	)		—		(1,218	)

Total impact on revenue		—			(24,555	)		220		(24,335	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(670	)		—			—		(670	)

Total Impact from Cash Flow Hedges	$	(670	)	$	(24,555	)	$	220	$	(25,005	)


	Three Months Ended December 31, 2008
	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	$	—		$	(28,244	)	$	7,968	$	(20,276	)
Loss arising from ineffective portion of commodity contracts		—			4,192			—		4,192

Total impact on revenue		—			(24,052	)		7,968		(16,084	)
Loss on settled Treasury lock agreements reclassified from AOCI into interest expense		(1,269	)		—			—		(1,269	)

Total Impact from Cash Flow Hedges	$	(1,269	)	$	(24,052	)	$	7,968	$	(17,353	)

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 months ended December 31, 2009 and 2008. 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
	December 31
	2009			2008
	(In thousands)

Decrease in fair value:
Forward commodity contracts	$	(7,447	)	$	(35,115	)
Recognition of losses in earnings due to settlements:
Treasury lock agreements		422			787
Forward commodity contracts		14,101			12,571

Total other comprehensive income (loss) from hedging, net of tax ⁽¹⁾	$	7,076		$	(21,757	)


⁽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 December 31, 2009:


	Treasury
	Lock			Commodity
	Agreements			Contracts			Total
	(In thousands)

Next twelve months	$	(1,687	)	$	(6,887	)	$	(8,574	)
Thereafter		(5,389	)		(1,605	)		(6,994	)

Total ⁽¹⁾	$	(7,076	)	$	(8,492	)	$	(15,568	)


⁽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 months ended December 31, 2009 and 2008 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized or will realize when the underlying physical and financial transactions are settled.

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended
	December 31
	2009		2008
	(In thousands)

Natural gas marketing commodity contracts	$	14,275	$	(3,832	)
Pipeline, storage and other commodity contracts		1,007		(83	)

Total impact on revenue	$	15,282	$	(3,915	)


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 and 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 first quarter of fiscal 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 for certain assets including 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 months ended December 31, 2009.

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 be disclosed in our Annual Report on Form 10-K for the fiscal 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 December 31, 2009. 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			December 31,
	(Level 1)		(Level 2)		(Level 3)		Collateral ⁽¹⁾			2009
	(In thousands)

Assets:
Financial instruments
Natural gas distribution segment	$	—	$	954	$	—	$	—		$	954
Natural gas marketing segment		17,209		72,963		—		(56,568	)		33,604

Total financial instruments		17,209		73,917		—		(56,568	)		34,558
Hedged portion of gas stored underground
Natural gas marketing segment		99,690		—		—		—			99,690
Pipeline, storage and other segment ⁽²⁾		12,529		—		—		—			12,529

Total gas stored underground		112,219		—		—		—			112,219
Available-for-sale securities		42,184		—		—		—			42,184

Total assets	$	171,612	$	73,917	$	—	$	(56,568	)	$	188,961

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	18,424	$	—	$	—		$	18,424
Natural gas marketing segment		38,332		19,534		—		(55,253	)		2,613

Total liabilities	$	38,332	$	37,958	$	—	$	(55,253	)	$	21,037


⁽¹⁾		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 December 31, 2009, we had $1.3 million of cash due on margin accounts used to collateralize certain financial instruments which has been reflected as a reduction to our financial instrument assets.

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

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 December 31, 2009:


	December 31, 2009
	(In thousands)

Carrying Amount	$	2,172,827
Fair Value	$	2,310,405

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Debt

Long-term debt

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


	December 31,			September 30,
	2009			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		524			524

Total long-term debt		2,172,827			2,172,827
Less:
Original issue discount on unsecured senior notes and debentures		(3,226	)		(3,296	)
Current maturities		(10,131	)		(131	)

	$	2,159,470		$	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.

We finance our short-term borrowing requirements through a combination of a $566.7 million commercial paper program and four committed revolving credit facilities with third-party lenders that provide approximately $1.2 billion of working capital funding. At December 31, 2009, there was a total of $179.7 million outstanding under our commercial paper program. At September 30, 2009, there was a total of $72.6 million outstanding under our commercial paper program. As of December 31, 2009, our commercial paper had maturities of less than two weeks with an interest rate of 0.27 percent. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities. These facilities are described in greater detail below.

Regulated Operations

We fund our regulated operations as needed, primarily through a $566.7 million commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$800 million of working capital funding. The first facility is a five-year unsecured facility, expiring December 2011, that bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from 0.30 percent to 0.75 percent, based on the Company’s credit ratings. This credit facility serves as a backup liquidity facility for our commercial paper program. At December 31, 2009, there were no borrowings under this facility, but we had $179.7 million of commercial paper outstanding leaving $387.0 million available.

The second facility is a $200 million unsecured 364-day facility that expires in October 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 December 31, 2009, 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 December 31, 2009, there were no borrowings outstanding under this facility.

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 December 31, 2009, our total-debt-to-total-capitalization ratio, as defined, was 54 percent. In addition, both the interest margin over the Eurodollar rate and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.

In addition to these third-party facilities, 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 or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved the facility through December 31, 2010. There was $35.5 million outstanding under this facility at December 31, 2009.

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 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2009, there were no borrowings outstanding under this credit facility. However, at December 31, 2009, AEM letters of credit totaling $38.0 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 $250.8 million at December 31, 2009.

AEM is required by the financial covenants in this facility to maintain a ratio of total liabilities to tangible net worth that does not exceed a maximum of 5 to 1. At December 31, 2009, 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 December 31, 2009, AEM’s net working capital was $246.7 million and its tangible net worth was $257.9 million.

To supplement borrowings under this facility, AEM has a $200 million intercompany demand credit facility with AEH, which bears interest at the greater of (i) the one-month LIBOR rate plus 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Amounts outstanding under this facility are subordinated to AEM’s committed credit facility. There was $45.0 million in borrowings outstanding under this facility at December 31, 2009.

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 2.00 percent or (ii) the rate for AEM’s offshore borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved the new facility through December 31, 2010. There were no borrowings outstanding under this facility at December 31, 2009.

Shelf Registration

On March 23, 2009, we filed a registration statement with the SEC to issue, from time to time, up to $900 million in common stock and/or debt securities available for issuance.

As of December 31, 2009, we had $450 million of availability remaining under the registration statement. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $200 million of equity securities and $250 million of debt securities.

As of February 2, 2010, we had received approvals from all requisite state regulatory commissions to issue a total of $1.3 billion in common stock and/or debt securities under a 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. We expect to file a registration statement with the SEC to register such securities as soon as practicable.

Debt Covenants

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

Additionally, our public debt indentures relating to our senior notes and debentures, as well as our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 December 31, 2009. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.


6.	Earnings Per Share

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 due to the retrospective adoption of this standard. Basic and diluted earnings per share for the three months ended December 31, 2009 and 2008 are calculated as follows:


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

Basic Earnings Per Share
Net income	$	93,330	$	75,963
Less: Income allocated to participating securities		1,037		708

Net income available to common shareholders	$	92,293	$	75,255

Basic weighted average shares outstanding		92,152		90,471

Net income per share — Basic	$	1.00	$	0.83

Diluted Earnings Per Share
Net income available to common shareholders	$	92,293	$	75,255
Effect of dilutive stock options and other shares		3		1

Net income available to common shareholders	$	92,296	$	75,256

Basic weighted average shares outstanding		92,152		90,471
Additional dilutive stock options and other shares		357		298

Diluted weighted average shares outstanding		92,509		90,769

Net income per share — Diluted	$	1.00	$	0.83

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2009 as their exercise price was less than the average market price of the common stock during that period. There were approximately 231,000 out-of-the-money stock

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

options excluded from the computation of diluted earnings per share for the three months ended December 31, 2008.


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 months ended December 31, 2009 and 2008 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 December 31
	Pension Benefits						Other Benefits
	2009			2008			2009			2008
	(In thousands)

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

Net periodic pension cost	$	6,826		$	5,791		$	5,859		$	6,271

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


	Pension Benefits						Other Benefits
	2009			2008			2009			2008

Discount rate		5.52	%		7.57	%		5.52	%		7.57	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected return on plan assets		8.25	%		8.25	%		5.00	%		5.00	%

The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2010. Based upon this valuation, we expect we will be required to contribute less than $30 million to our pension plans by September 15, 2010.

We contributed $3.2 million to our other post-retirement benefit plans during the three months ended December 31, 2009. We expect to contribute a total of approximately $13 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 December 31, 2009:
Domestic equity mutual funds	$	26,333	$	4,052	$	—	$	30,385
Foreign equity mutual funds		4,081		953		—		5,034
Money market funds		6,765		—		—		6,765

	$	37,179	$	5,005	$	—	$	42,184

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

The following table presents interest and dividends on available-for-sale securities for the three months ended December 31, 2009 and 2008:


	Three Months Ended
	December 31
	2009		2008
	(In thousands)

Interest	$	3	$	—
Dividends		101		167

Total interest and dividends	$	104	$	167

The following table presents realized losses on available-for-sale securities for the three months ended December 31, 2009 and 2008. The gross realized investment losses exclude losses from other-than-temporary impairment:


	Three Months Ended
	December 31
	2009		2008
	(In thousands)

Gross realized investment gains	$	—	$	—
Gross realized investment losses		—		(81	)

Net realized losses	$	—	$	(81	)

During the three months ended December 31, 2008, 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 December 31, 2009.


8.	Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 12 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30,

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2009, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2009. We continue to believe that the final outcome of such litigation and environmental-related matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

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

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 December 31, 2009, AEM was committed to purchase 94.7 Bcf within one year, 12.3 Bcf within one to three years and 1.9 Bcf after three years under indexed contracts. AEM is committed to purchase 3.7 Bcf within one year, 0.6 Bcf within one to three years and 0.2 Bcf after three years under fixed price contracts with prices ranging from $4.57 to $6.43 per Mcf. Purchases under these contracts totaled $354.1 million and $527.5 million for the three months ended December 31, 2009 and 2008.

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

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


2010	$	202,676
2011		7,491
2012		7,256
2013		7,481
2014		2,540
Thereafter		—

	$	227,444

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 quarter ended December 31, 2009.

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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 December 31, 2009, rate cases were in progress in our City of Dallas, Colorado, Kentucky, Missouri and Georgia service areas and annual rate filing mechanisms were in progress in our Louisiana service area. 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 three months ended December 31, 2009, 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 the Atmos Pipeline — Texas Division.

	•	The natural gas marketing segment , which includes a variety of nonregulated natural gas management services.

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

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 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 month periods ended December 31, 2009 and 2008 by segment are presented in the following tables:


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

Operating revenues from external parties	$	802,686	$	19,842	$	460,821	$	9,503	$	—		$	1,292,852
Intersegment revenues		208		27,018		83,450		2,120		(112,796	)		—

		802,894		46,860		544,271		11,623		(112,796	)		1,292,852
Purchased gas cost		508,267		—		484,486		1,633		(112,383	)		882,003

Gross profit		294,627		46,860		59,785		9,990		(413	)		410,849
Operating expenses
Operation and maintenance		96,033		17,579		8,755		1,908		(413	)		123,862
Depreciation and amortization		47,857		4,942		411		629		—			53,839
Taxes, other than income		37,990		3,267		935		360		—			42,552

Total operating expenses		181,880		25,788		10,101		2,897		(413	)		220,253

Operating income		112,747		21,072		49,684		7,093		—			190,596
Miscellaneous income (expense)		657		43		208		453		(1,630	)		(269	)
Interest charges		29,678		7,968		2,378		314		(1,630	)		38,708

Income before income taxes		83,726		13,147		47,514		7,232		—			151,619
Income tax expense		32,278		4,693		18,502		2,816		—			58,289

Net income	$	51,448	$	8,454	$	29,012	$	4,416	$	—		$	93,330

Capital expenditures	$	100,462	$	13,759	$	406	$	812	$	—		$	115,439

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

Operating revenues from external parties	$	1,055,772	$	30,222	$	616,844	$	13,494	$	—		$	1,716,332
Intersegment revenues		196		24,460		170,651		2,954		(198,261	)		—

		1,055,968		54,682		787,495		16,448		(198,261	)		1,716,332
Purchased gas cost		757,584		—		757,472		3,903		(197,839	)		1,321,120

Gross profit		298,384		54,682		30,023		12,545		(422	)		395,212
Operating expenses
Operation and maintenance		96,218		27,337		8,460		1,170		(508	)		132,677
Depreciation and amortization		47,139		4,955		401		631		—			53,126
Taxes, other than income		40,746		2,788		593		10		—			44,137
Asset impairments		1,776		232		56		14		—			2,078

Total operating expenses		185,879		35,312		9,510		1,825		(508	)		232,018

Operating income		112,505		19,370		20,513		10,720		86			163,194
Miscellaneous income (expense)		3,121		815		301		2,161		(6,699	)		(301	)
Interest charges		32,887		8,079		3,902		736		(6,613	)		38,991

Income before income taxes		82,739		12,106		16,912		12,145		—			123,902
Income tax expense		32,606		4,445		6,337		4,551		—			47,939

Net income	$	50,133	$	7,661	$	10,575	$	7,594	$	—		$	75,963

Capital expenditures	$	89,003	$	5,060	$	29	$	13,275	$	—		$	107,367

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


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

ASSETS
Property, plant and equipment, net	$	3,758,014	$	681,993	$	7,354		$	75,827	$	—		$	4,523,188
Investment in subsidiaries		596,473		—		(2,096	)		—		(594,377	)		—
Current assets
Cash and cash equivalents		33,718		—		140,654			457		—			174,829
Assets from risk management activities		849		—		22,033			3,337		(3,337	)		22,882
Other current assets		744,761		16,511		331,107			102,735		(106,247	)		1,088,867
Intercompany receivables		522,405		—		—			144,092		(666,497	)		—

Total current assets		1,301,733		16,511		493,794			250,621		(776,081	)		1,286,578
Intangible assets		—		—		1,304			—		—			1,304
Goodwill		571,592		132,300		24,282			10,429		—			738,603
Noncurrent assets from risk management activities		105		—		11,571			—		—			11,676
Deferred charges and other assets		289,106		6,476		1,024			17,469		—			314,075

	$	6,517,023	$	837,280	$	537,233		$	354,346	$	(1,370,458	)	$	6,875,424

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,258,076	$	179,654	$	119,019		$	297,800	$	(596,473	)	$	2,258,076
Long-term debt		2,159,077		—		—			393		—			2,159,470

Total capitalization		4,417,153		179,654		119,019			298,193		(596,473	)		4,417,546
Current liabilities
Current maturities of long-term debt		10,000		—		—			131		—			10,131
Short-term debt		215,162		—		45,000			—		(80,450	)		179,712
Liabilities from risk management activities		17,076		—		4,628			3		(3,337	)		18,370
Other current liabilities		689,643		10,379		256,627			41,241		(23,701	)		974,189
Intercompany payables		—		550,047		116,450			—		(666,497	)		—

Total current liabilities		931,881		560,426		422,705			41,375		(773,985	)		1,182,402
Deferred income taxes		489,899		92,932		(6,422	)		12,014		—			588,423
Noncurrent liabilities from risk management activities		1,348		—		1,319			—		—			2,667
Regulatory cost of removal obligation		314,126		—		—			—		—			314,126
Deferred credits and other liabilities		362,616		4,268		612			2,764		—			370,260

	$	6,517,023	$	837,280	$	537,233		$	354,346	$	(1,370,458	)	$	6,875,424

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30, 2009
	Natural		Transmission		Natural			Pipeline,
	Gas		and		Gas			Storage
	Distribution		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 December 31, 2009, the related condensed consolidated statements of income for the three-month periods ended December 31, 2009 and 2008, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2009 and 2008. These financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation as of September 30, 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

February 3, 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 possible impact of future additional regulatory and financial risks associated with global warming and climate change; 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 three months ended December 31, 2009.

RESULTS OF OPERATIONS

We reported net income of $93.3 million, or $1.00 per diluted share for the three months ended December 31, 2009 compared with net income of $76.0 million, or $0.83 per diluted share in the prior-year quarter. Regulated operations contributed 64 percent of our net income during this period with our nonregulated operations contributing the remaining 36 percent. The primary driver in the 23 percent quarter-over-quarter increase in net income was due to our natural gas marketing segment experiencing a significant increase in unrealized margins primarily through our asset optimization activities. The favorable movement in our unrealized margins was primarily the result of two factors. First, we experienced a narrowing of spreads between current cash prices and forward natural gas prices. Secondly, we elected to defer storage withdrawal gains and roll the associated financial instruments from the current quarter to future months in order to maximize our overall economic value that should ultimately be realized. As a result, gains that are typically realized during the first quarter remained unrealized as of December 31, 2009.

During the quarter, we also experienced the ongoing impact of challenging economic times. This was reflected in declines in the demand for natural gas as a result of idle production and plant closures, which contributed to a 29 percent quarter-over-quarter decrease in consolidated throughput in our regulated transmission and storage segment and a seven percent quarter-over-quarter decrease in consolidated sales volumes in our natural gas marketing segment. However, colder than normal weather during the current quarter, which resulted in increased throughput of seven percent, and recent improvements in rate designs in our natural gas distribution segment partially offset these declines.

During the quarter we continued to successfully access the capital markets. 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. These facilities should help ensure we have sufficient liquidity to fund our working capital needs.

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


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

Operating revenues	$	1,292,852		$	1,716,332
Gross profit		410,849			395,212
Operating expenses		220,253			232,018
Operating income		190,596			163,194
Miscellaneous expense		(269	)		(301	)
Interest charges		38,708			38,991
Income before income taxes		151,619			123,902
Income tax expense		58,289			47,939
Net income	$	93,330		$	75,963
Diluted net income per share	$	1.00		$	0.83

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


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

Natural gas distribution segment	$	51,448	$	50,133	$	1,315
Regulated transmission and storage segment		8,454		7,661		793
Natural gas marketing segment		29,012		10,575		18,437
Pipeline, storage and other segment		4,416		7,594		(3,178	)

Net income	$	93,330	$	75,963	$	17,367

The following table reflects our consolidated net income and diluted earnings per share in our regulated and nonregulated operations:


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

Regulated operations	$	59,902	$	57,794	$	2,108
Nonregulated operations		33,428		18,169		15,259

Consolidated net income	$	93,330	$	75,963	$	17,367

Diluted EPS from regulated operations	$	0.64	$	0.63	$	0.01
Diluted EPS from nonregulated operations		0.36		0.20		0.16

Consolidated diluted EPS	$	1.00	$	0.83	$	0.17

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

Natural Gas Distribution Segment

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

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

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


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

Our natural gas distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas 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.

Review of Financial and Operating Results

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


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

Gross profit	$	294,627	$	298,384	$	(3,757	)
Operating expenses		181,880		185,879		(3,999	)

Operating income		112,747		112,505		242
Miscellaneous income		657		3,121		(2,464	)
Interest charges		29,678		32,887		(3,209	)

Income before income taxes		83,726		82,739		987
Income tax expense		32,278		32,606		(328	)

Net income	$	51,448	$	50,133	$	1,315

Consolidated natural gas distribution sales volumes — MMcf		99,314		91,446		7,868
Consolidated natural gas distribution transportation volumes — MMcf		35,207		34,336		871

Total consolidated natural gas distribution throughput — MMcf		134,521		125,782		8,739

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.45	$	0.01
Consolidated natural gas distribution average cost of gas per Mcf sold	$	5.12	$	8.28	$	(3.16	)

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


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

Mid-Tex	$	50,381	$	52,678	$	(2,297	)
Kentucky/Mid-States		17,803		19,025		(1,222	)
Louisiana		13,407		14,584		(1,177	)
West Texas		11,757		8,013		3,744
Mississippi		9,802		8,435		1,367
Colorado-Kansas		8,606		8,601		5
Other		991		1,169		(178	)

Total	$	112,747	$	112,505	$	242

The $3.8 million decrease in natural gas distribution gross profit primarily reflects a prior-year quarter event that did not recur in the current year as well as revenue taxes as follows:


	•	$8.0 million decrease due to a prior year non-recurring update to our estimate for gas delivered to customers but not yet billed to reflect changes in base rates in several of our jurisdictions.

	•	$7.6 million decrease due to lower revenue-related taxes primarily as a result of lower-priced natural gas, partially offset by the associated franchise and state gross receipts tax expense recorded as a component of taxes other than income discussed below.

These decreases were partially offset by:


	•	$9.8 million net increase in rate adjustments, primarily in West Texas, Louisiana, Mid-Tex and Mississippi.

	•	$2.2 million increase as a result of a seven percent increase in consolidated throughput primarily associated with higher residential and commercial consumption and colder weather in most of our service areas.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense, taxes, other than income and asset impairments decreased $4.0 million, primarily due to the following:


	•	$2.8 million decrease in taxes other than income due to lower franchise fees and state gross receipts taxes.

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

	•	$0.8 million decrease in allowance for doubtful accounts due to a 38 percent quarter-over-quarter decline in the average cost of gas.

These decreases were partially offset by a $1.5 million increase in employee-related expenses.

Miscellaneous income decreased $2.5 million due to lower interest income. Interest charges decreased $3.2 million primarily due to lower short-term debt balances and interest rates.

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the three months ended December 31, 2009 are discussed below. The amounts described below represent the operating income that was requested or received

in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling.

Annual net operating income increases totaling $10.2 million resulting from ratemaking activity became effective in the quarter ended December 31, 2009 as summarized below:


	Annual Increase to
Rate Action	Operating Income
	(In thousands)

Rate case filings	$	1,397
Annual rate filing mechanisms		7,172
Other rate activity		1,675

	$	10,244

Additionally, the following ratemaking efforts were in progress during the first quarter of fiscal 2010 but had not been completed as of December 31, 2009.


			Operating
			Income
Division	Rate Action	Jurisdiction	Requested
			(In thousands)

Mid-Tex	Rate Case ⁽¹⁾	Dallas & Environs	$	7,743
Colorado/Kansas	Rate Case ⁽²⁾	Colorado		3,834
	Ad Valorem True Up ⁽³⁾	Kansas		392
KY/Mid-States	Rate Case	Kentucky		9,486
	Rate Case	Missouri		6,439
	Rate Case	Georgia		3,776
	ISRS(4)	Missouri		597
Louisiana	RSC	Louisiana		1,841

			$	34,108


⁽¹⁾		In January 2010, we resolved our pending rate case for the City of Dallas and Eviron’s. Initiated in November 2008 and subsequently amended, the case sought an increase of $8.8 million for City of Dallas and Environs customers. In its final order, the Railroad Commission of Texas approved a $3.0 million increase in operating income earned from these customers based on a 10.4 percent return on equity. Net of the GRIP 2008 rates that should 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.

⁽²⁾		The Commission approved an increase of $1.9 million and new rates were implemented beginning in January 2010.

⁽³⁾		In December 2009, our Colorado/Kansas Division filed an Ad Valorem True-up filing for $0.4 million. The Commission approved the increase of $0.4 million and new rates were implemented beginning in January 2010.

⁽⁴⁾		Infrastructure System Replacement Surcharge (ISRS) relates to maintenance capital investments made since the previous rate case.

Additionally, in January 2010, our Colorado/Kansas Division filed a rate case in Kansas requesting an increase in operating income of $6.0 million.

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

Virginia

1,397

11/23/2009

Total 2010 Rate Case Filings

1,397

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 quarter ended December 31, 2009.

Additional

Annual

Test Year

Operating

Effective

Division

Jurisdiction

Ended

Income

Date

(In thousands)

2010 Filings:

West Texas

Lubbock

12/31/2008

2,704

10/1/2009

West Texas

Amarillo

12/31/2008

1,285

10/1/2009

Mississippi

6/30/2009

3,183

12/15/2009

Total 2010 Filings

7,172

The following table summarizes other ratemaking activity during the quarter ended December 31, 2009:

Increase in

Operating

Effective

Division

Jurisdiction

Rate Activity

Income

Date

(In thousands)

2010 Other Rate Activity:

Kentucky/Mid-States

Georgia

PRP Surcharge ⁽¹⁾

909

10/1/2009

Colorado-Kansas

Kansas

GSRS ⁽²⁾

766

12/12/2009

Total 2010 Other Rate Activity

1,675


⁽¹⁾		The Pipeline Replacement Program (PRP) surcharge relates to a long-term cast iron replacement program.

⁽²⁾		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.

Review of Financial and Operating Results

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


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

Mid-Tex transportation	$	26,711	$	24,352	$	2,359
Third-party transportation		15,242		25,366		(10,124	)
Storage and park and lend services		2,605		2,357		248
Other		2,302		2,607		(305	)

Gross profit		46,860		54,682		(7,822	)
Operating expenses		25,788		35,312		(9,524	)

Operating income		21,072		19,370		1,702
Miscellaneous income		43		815		(772	)
Interest charges		7,968		8,079		(111	)

Income before income taxes		13,147		12,106		1,041
Income tax expense		4,693		4,445		248

Net income	$	8,454	$	7,661	$	793

Gross pipeline transportation volumes — MMcf		157,773		192,172		(34,399	)

Consolidated pipeline transportation volumes — MMcf		95,938		135,858		(39,920	)

The $7.8 million decrease in regulated transmission and storage gross profit was attributable primarily to the following factors:


	•	$4.2 million decrease due to a 29 percent decline in system throughput resulting from lower production and drilling activity due to lower prices and demand.

	•	$3.9 million decrease resulting from lower transportation fees on through-system deliveries due to narrower basis spreads.

	•	$1.3 million decrease in market-based demand fees and compression activity associated with lower demand throughput.

These decreases were partially offset by a $1.5 million increase associated with our GRIP filings.

Operating expenses decreased $9.5 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 hedge and to attempt to insulate and protect the economic value within its asset optimization activities. Changes in fair value associated with these financial instruments are recognized as a component of unrealized margins until they are settled.

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 the 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.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the three months ended December 31, 2009 and 2008 are presented below. Gross profit margin consists primarily of margins earned

from the delivery of gas and related services requested by our customers and margins earned from asset optimization activities, which are derived from the utilization of our proprietary and managed third-party storage and transportation assets to capture favorable arbitrage spreads through natural gas trading activities.

Unrealized margins represent the unrealized gains or losses on our net physical gas position and the related financial instruments used to manage commodity price risk as described above. These margins fluctuate based upon changes in the spreads between the physical 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
	December 31
	2009		2008			Change
	(In thousands, unless otherwise noted)

Realized margins
Delivered gas	$	16,087	$	18,553		$	(2,466	)
Asset optimization ⁽¹⁾		6,429		36,939			(30,510	)

		22,516		55,492			(32,976	)
Unrealized margins		37,269		(25,469	)		62,738

Gross profit		59,785		30,023			29,762
Operating expenses		10,101		9,510			591

Operating income		49,684		20,513			29,171
Miscellaneous income		208		301			(93	)
Interest charges		2,378		3,902			(1,524	)

Income before income taxes		47,514		16,912			30,602
Income tax expense		18,502		6,337			12,165

Net income	$	29,012	$	10,575		$	18,437

Gross natural gas marketing sales volumes — MMcf		102,261		110,658			(8,397	)

Consolidated natural gas marketing sales volumes — MMcf		87,229		93,308			(6,079	)

Net physical position (Bcf)		17.4		16.3			1.1


⁽¹⁾		Net of storage fees of $2.5 million and $2.6 million.

AEM’s delivered gas business contributed 71 percent to total realized margins during the first quarter of fiscal 2010 with asset optimization activities contributing the remaining 29 percent. The $33.0 million decrease in realized gross profit reflected:


	•	A $30.5 million decrease in asset optimization margins primarily attributable to the timing of the settlement of open positions. During the current period, AEM elected to defer storage withdrawals and roll the associated financial instruments from the current quarter to forward months. In the prior-year quarter, AEM recognized the gains that it had captured from its optimization activities during late fiscal 2008.

	•	A $2.5 million decrease in realized delivered gas margins due to an eight percent decrease in gross sales volumes as a result of the current economic climate. Per-unit margins were $0.16/Mcf in the current-year quarter compared with $0.17/Mcf in the prior-year quarter.

The decrease in realized gross profit was more than offset by a $62.7 million increase in unrealized margins due to the narrowing of spreads between current cash prices and forward natural gas prices and our

election to defer storage withdrawal gains during the current quarter. As a result of this election, realized gains that we typically earn during the first quarter remain unrealized. A significant portion of the unrealized gain is anticipated to be realized during the second fiscal quarter of 2010.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income taxes, increased $0.6 million primarily due to an increase 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 these measures to be non-GAAP financial measures as they are calculated using both forward-looking storage injections/withdrawals and hedge settlement estimates and historical financial information. These measures are presented because we believe they provide 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. There are no forward-looking GAAP financial measures that are available, which are directly comparable to either of the forward-looking non-GAAP financial measures, economic value or potential gross profit, to which such forward-looking non-GAAP financial measures may be reconciled.

The following table presents AEM’s economic value and its potential gross profit (loss) at December 31, 2009 and 2008.


	December 31
	2009			2008
	(In millions, unless otherwise noted)

Economic value	$	22.7		$	20.7
Associated unrealized (gains) losses		(24.8	)		(4.8	)

Subtotal		(2.1	)		15.9
Related fees ⁽¹⁾		(13.1	)		(11.6	)

Potential gross profit (loss)	$	(15.2	)	$	4.3

Net physical position (Bcf)		17.4			16.3


⁽¹⁾		Related fees represent AEM’s contractual costs to acquire the storage capacity utilized in its asset optimization activities. 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 December 31, 2009 and 2008.

During the quarter ended December 31, 2009, AEM’s economic value decreased from $28.6 million, or $2.07/Mcf at September 30, 2009 to $22.7 million, or $1.30/Mcf. This compares favorably to AEM’s economic value at December 31, 2008 of $20.7 million, or $1.27/Mcf.

Early in the quarter, AEM withdrew gas and realized previously captured spreads. However, as current cash prices declined during the quarter, AEM started to inject gas and rolled positions primarily into the second fiscal quarter to increase economic value that it can realize in future periods. As a result of this activity, AEM was a net injector of gas during the quarter. We anticipate the majority of the economic value and corresponding reversal of unrealized mark to market gains will occur in the second fiscal quarter.

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 December 31, 2009 will be fully realized in the future nor can we predict in what time periods such realization may occur. Further, if we experience operational or other issues which limit our ability to optimally manage our stored gas positions, our earnings could be adversely impacted.

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 we seek 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.

Review of Financial and Operating Results

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


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

Asset optimization	$	97		$	5,467	$	(5,370	)
Storage and transportation services ⁽¹⁾		3,448			3,315		133
Other		(170	)		989		(1,159	)
Unrealized margins		6,615			2,774		3,841

Gross profit		9,990			12,545		(2,555	)
Operating expenses		2,897			1,825		1,072

Operating income		7,093			10,720		(3,627	)
Miscellaneous income		453			2,161		(1,708	)
Interest charges		314			736		(422	)

Income before income taxes		7,232			12,145		(4,913	)
Income tax expense		2,816			4,551		(1,735	)

Net income	$	4,416		$	7,594	$	(3,178	)


⁽¹⁾		Net of storage and demand fees of $0.6 million and $0.8 million.

Gross profit from our pipeline, storage and other segment decreased $2.6 million primarily due to the following:


	•	$3.6 million decrease in margins earned from utilizing assets subject to Atmos Pipeline and Storage’s asset management plans.

	•	$1.9 million decrease in basis gains earned from utilizing leased capacity.

	•	$3.8 million increase in unrealized margins associated with our asset optimization activities.

Operating expenses increased $1.1 million primarily due to the following:


	•	$0.7 million increase in employee costs.

	•	$0.3 million increase in property taxes.

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 three months ended December 31, 2009 and 2008 are presented below.


	Three Months Ended December 31
	2009			2008			2009 vs. 2008
	(In thousands)

Total cash provided by (used in)
Operating activities	$	95,156		$	150,715		$	(55,559	)
Investing activities		(117,312	)		(108,577	)		(8,735	)
Financing activities		85,782			(19,056	)		104,838

Change in cash and cash equivalents		63,626			23,082			40,544
Cash and cash equivalents at beginning of period		111,203			46,717			64,486

Cash and cash equivalents at end of period	$	174,829		$	69,799		$	105,030

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 three months ended December 31, 2009, we generated operating cash flow of $95.2 million from operating activities compared with $150.7 million for the three months ended December 31, 2008, primarily

due to the fluctuation in gas costs. Gas costs, which reached unusually 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 first quarter reflects the recovery of lower gas costs through purchased gas recovery mechanisms and sales. This is in contrast to the fiscal 2009 first quarter, 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 three months ended December 31, 2009, capital expenditures were $115.4 million compared with $107.4 million for the three months ended December 31, 2008. The $8.0 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 three months ended December 31, 2009, our financing activities provided $85.8 million in cash flow compared with using $19.1 million of cash in the prior-year period, primarily due to the following:


	•	$106.0 million additional cash provided by a period-over-period increase in short-term debt, partially offset by

	•	$1.1 million additional cash used due to an increase in dividends paid in the current year compared to the prior year.

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


	Three Months Ended
	December 31
	2009		2008

Shares issued:
Direct Stock Purchase Plan		79,087		108,582
Retirement Savings Plan and Trust		79,722		155,195
1998 Long-Term Incentive Plan		259,550		520,124
Outside Directors Stock-for-Fee Plan		770		911

Total shares issued		419,129		784,812

The quarter-over-quarter decrease in the number of shares issued primarily reflects the reduced level of shares awarded 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 first quarter of fiscal 2010 compared to the first 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.

Shelf Registration

On March 23, 2009, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $900 million in common stock and/or debt securities. As of December 31, 2009, we had $450 million of availability remaining under the registration statement. However, due to certain restrictions placed by one state regulatory commission on our ability to issue securities under the registration statement, we now have remaining and available for issuance a total of approximately $200 million of equity securities and $250 million of subordinated debt securities.

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings, Ltd. (Fitch). As of December 31, 2009, all three rating agencies maintained a stable outlook. None of our ratings are currently under review. 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 adverse global financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating

for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated 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 December 31, 2009. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Capitalization

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of December 31, 2009, September 30, 2009 and December 31, 2008:


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

Short-term debt	$	179,712	3.9	%	$	72,550	1.6	%	$	360,833	7.9	%
Long-term debt		2,169,601	47.1	%		2,169,531	49.1	%		2,120,427	46.5	%
Shareholders’ equity		2,258,076	49.0	%		2,176,761	49.3	%		2,078,076	45.6	%

Total	$	4,607,389	100.0	%	$	4,418,842	100.0	%	$	4,559,336	100.0	%

Total debt as a percentage of total capitalization, including short-term debt, was 51.0 percent at December 31, 2009, 50.7 percent at September 30, 2009 and 54.4 percent at December 31, 2008. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Retirement Savings Plan and, if necessary, access to the equity capital markets.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 8 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the three months ended December 31, 2009.

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. During the quarter, we commenced negotiations to enter into a joint venture with a third party to develop the project. We expect such negotiations to be completed by the end of the second quarter of this fiscal year.

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 months ended December 31, 2009 and 2008:


	Three Months Ended
	December 31
	2009			2008
	(In thousands)

Fair value of contracts at beginning of period	$	(14,166	)	$	(63,677	)
Contracts realized/settled		(21,029	)		(53,766	)
Fair value of new contracts		(947	)		(4,282	)
Other changes in value		18,672			70,411

Fair value of contracts at end of period	$	(17,470	)	$	(51,314	)

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


	Fair Value of Contracts at December 31, 2009
	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	$	(16,227	)	$	(1,243	)	$	—	$	—	$	(17,470	)
Prices based on models and other valuation methods		—			—			—		—		—

Total Fair Value	$	(16,227	)	$	(1,243	)	$	—	$	—	$	(17,470	)

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


	Three Months Ended
	December 31
	2009			2008
	(In thousands)

Fair value of contracts at beginning of period	$	26,698		$	16,542
Contracts realized/settled		(2,212	)		(20,247	)
Fair value of new contracts		—			—
Other changes in value		7,820			(24,893	)

Fair value of contracts at end of period		32,306			(28,598	)
Netting of cash collateral		(1,315	)		75,825

Cash collateral and fair value of contracts at period end	$	30,991		$	47,227

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


	Fair Value of Contracts at December 31, 2009
	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	$	22,055	$	10,251	$	—	$	—	$	32,306
Prices based on models and other valuation methods		—		—		—		—		—

Total Fair Value	$	22,055	$	10,251	$	—	$	—	$	32,306

Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2009 and 2008, our total net periodic pension and other benefits cost was $12.7 million and $12.1 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 assets are “smoothed” for purposes of determining net periodic pension cost. Accordingly, asset gains and losses are recognized over time as a component of net periodic pension and benefit costs for our Pension Account Plan, our largest funded plan. 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 $30 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 $13 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-month periods ended December 31, 2009 and 2008.

Natural Gas Distribution Sales and Statistical Data


	Three Months Ended
	December 31
	2009		2008

METERS IN SERVICE, end of period
Residential		2,925,028		2,929,319
Commercial		271,713		273,590
Industrial		2,539		2,232
Public authority and other		9,251		9,236

Total meters		3,208,531		3,214,377

INVENTORY STORAGE BALANCE — Bcf		57.6		58.2
SALES VOLUMES — MMcf ⁽¹⁾
Gas sales volumes
Residential		60,546		54,208
Commercial		30,490		28,329
Industrial		5,319		5,400
Public authority and other		2,959		3,509

Total gas sales volumes		99,314		91,446
Transportation volumes		36,241		35,285

Total throughput		135,555		126,731

OPERATING REVENUES (000’s) ⁽¹⁾
Gas sales revenues
Residential	$	507,911	$	647,100
Commercial		219,420		302,694
Industrial		31,033		50,155
Public authority and other		20,198		31,394

Total gas sales revenues		778,562		1,031,343
Transportation revenues		16,475		15,766
Other gas revenues		7,857		8,859

Total operating revenues	$	802,894	$	1,055,968

Average transportation revenue per Mcf	$	0.45	$	0.45
Average cost of gas per Mcf sold	$	5.12	$	8.28

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
	December 31
	2009		2008

CUSTOMERS, end of period
Industrial		717		703
Municipal		63		59
Other		502		490

Total		1,282		1,252

INVENTORY STORAGE BALANCE — Bcf
Natural gas marketing		19.2		15.8
Pipeline, storage and other		3.2		2.5

Total		22.4		18.3

REGULATED TRANSMISSION AND STORAGE VOLUMES — MMcf ⁽¹⁾		157,773		192,172
NATURAL GAS MARKETING SALES VOLUMES — MMcf ⁽¹⁾		102,261		110,658
OPERATING REVENUES (000’s) ⁽¹⁾
Regulated transmission and storage	$	46,860	$	54,682
Natural gas marketing		544,271		787,495
Pipeline, storage and other		11,623		16,448

Total operating revenues	$	602,754	$	858,625

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 three months ended December 31, 2009, there were no material changes in our quantitative and qualitative disclosures about market risk.


Item 4.	*Controls and Procedures*

Management’s Evaluation of Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the first 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 three months ended December 31, 2009, except as noted in Note 8 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 12 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2009. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.


Item 6.	*Exhibits*

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

SIGNATURE

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

Atmos Energy Corporation

(Registrant)


	By:	/s/ Fred E. Meisenheimer

Fred E. Meisenheimer

Senior Vice President, Chief Financial Officer

and Treasurer

(Duly authorized signatory)

Date: February 3, 2010

EXHIBITS INDEX
Item 6


				Page Number or
Exhibit				Incorporation by
Number			Description	Reference to

	10	.1	Revolving Credit Agreement (364 Day Facility), dated as of October 22, 2009, among Atmos Energy Corporation, the Lenders from time to time parties thereto, SunTrust Bank as Administrative Agent, Wells Fargo Bank, N.A. as Syndication Agent, and Bank of America, N.A. and U.S. Bank National Association as Co-Documentation Agents	Exhibit 10.1 to Form 8-K dated October 22, 2009 (File No. 1-10042)
	10	.2	Fourth Amended and Restated Credit Agreement, dated as of December 10, 2009 among Atmos Energy Marketing, LLC, a Delaware limited liability company, BNP Paribas, a bank organized under the laws of France, as administrative agent, collateral agent, as an issuing bank and as a bank, Fortis Bank SA/NV, New York Branch, a bank organized under the laws of Belgium, as documentation agent, as an issuing bank and as a bank, Société Générale, as syndication agent, as an issuing bank and as a bank and the other financial institutions which may become parties thereto	Exhibit 10.1 to Form 8-K dated December 10, 2009 (File No. 1-10042)
	10	.3	Second Amended and Restated Intercreditor Agreement, dated as of December 10, 2009 (as amended, supplemented and otherwise modified from time to time, the “Agreement”), among BNP PARIBAS, a bank organized under the laws of France, in its capacity as Collateral Agent (together with its successors and assigns in such capacity, the “Agent”) for the Banks hereinafter referred to, and each bank and other financial institution which is now or hereafter a party to this Agreement in its capacity as a Bank and, as applicable, as a Swap Bank (collectively, the “Swap Banks”) and as a Physical Trade Bank (collectively, the “Physical Trade Banks”)	Exhibit 10.2 to Form 8-K dated December 10, 2009 (File No. 1-10042)
	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 6. Exhibits

Exhibits

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

ATO 10-Q Quarter ended Dec. 31, 2009

Exhibits