Edgar Filing: ATMOS ENERGY CORP

Form 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2012

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-10042

Atmos Energy Corporation

(Exact name of registrant as specified in its charter)


Texas and Virginia		75-1743247
(State or other jurisdiction of incorporation or organization)		(IRS employer identification no.)

Three Lincoln Centre, Suite 1800 5430 LBJ Freeway, Dallas, Texas		75240 (Zip code)
(Address of principal executive offices)

(972) 934-9227

(Registrant’s telephone number, including area code)

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

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 þ No ¨

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 ¨		Non-Accelerated Filer ¨		Smaller Reporting Company ¨

(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 ¨ No þ

Number of shares outstanding of each of the issuer’s classes of common stock, as of February 1, 2013.


Class		Shares Outstanding
No Par Value		90,517,509

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
CFTC		Commodity Futures Trading Commission
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, 2012			September 30, 2012
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	7,283,533		$	7,134,470
Less accumulated depreciation and amortization		1,688,239			1,658,866

Net property, plant and equipment		5,595,294			5,475,604
Current assets
Cash and cash equivalents		124,601			64,239
Accounts receivable, net		500,863			234,526
Gas stored underground		274,126			256,415
Other current assets		265,044			272,782

Total current assets		1,164,634			827,962
Goodwill and intangible assets		740,836			740,847
Deferred charges and other assets		463,454			451,262

	$	7,964,218		$	7,495,675

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, 2012 — 90,516,948 shares September 30, 2012 — 90,239,900 shares	$	453		$	451
Additional paid-in capital		1,750,195			1,745,467
Retained earnings		709,438			660,932
Accumulated other comprehensive loss		(36,081	)		(47,607	)

Shareholders’ equity		2,424,005			2,359,243
Long-term debt		1,956,376			1,956,305

Total capitalization		4,380,381			4,315,548
Current liabilities
Accounts payable and accrued liabilities		367,312			215,229
Other current liabilities		446,717			489,665
Short-term debt		830,891			570,929
Current maturities of long-term debt		131			131

Total current liabilities		1,645,051			1,275,954
Deferred income taxes		1,066,273			1,015,083
Regulatory cost of removal obligation		371,608			381,164
Pension and postretirement costs		456,694			457,196
Deferred credits and other liabilities		44,211			50,730

	$	7,964,218		$	7,495,675

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended December 31
	2012			2011
	(Unaudited)
	(In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	666,787		$	676,113
Regulated transmission and storage segment		60,681			56,759
Nonregulated segment		399,894			444,176
Intersegment eliminations		(93,207	)		(93,054	)

		1,034,155			1,083,994
Purchased gas cost
Natural gas distribution segment		387,156			392,518
Regulated transmission and storage segment		—			—
Nonregulated segment		377,435			428,771
Intersegment eliminations		(92,798	)		(92,687	)

		671,793			728,602

Gross profit		362,362			355,392
Operating expenses
Operation and maintenance		106,527			114,644
Depreciation and amortization		59,579			58,366
Taxes, other than income		41,334			42,911

Total operating expenses		207,440			215,921

Operating income		154,922			139,471
Miscellaneous income (expense)		698			(2,016	)
Interest charges		30,522			35,726

Income from continuing operations before income taxes		125,098			101,729
Income tax expense		47,750			39,345

Income from continuing operations		77,348			62,384
Income from discontinued operations, net of tax ($1,728 and $3,516)		3,117			6,123

Net income	$	80,465		$	68,507

Basic earnings per share
Income per share from continuing operations	$	0.85		$	0.68
Income per share from discontinued operations		0.04			0.07

Net income per share — basic	$	0.89		$	0.75

Diluted earnings per share
Income per share from continuing operations	$	0.85		$	0.68
Income per share from discontinued operations		0.03			0.07

Net income per share — diluted	$	0.88		$	0.75

Cash dividends per share	$	0.350		$	0.345

Weighted average shares outstanding:
Basic		90,359			90,254

Diluted		91,309			90,546

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended December 31
	2012			2011
	(Unaudited)
	(In thousands)
Net income	$	80,465		$	68,507
Other comprehensive income (loss), net of tax
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $(220) and $514		(373	)		901
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $7,049 and $(638)		12,264			(1,087	)
Net unrealized losses on commodity cash flow hedges, net of tax of $(233) and $(10,597)		(365	)		(16,575	)

Total other comprehensive income (loss)		11,526			(16,761	)

Total comprehensive income	$	91,991		$	51,746

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended December 31
	2012			2011
	(Unaudited)
	(In thousands)
Cash Flows From Operating Activities
Net income	$	80,465		$	68,507
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization		60,500			60,733
Charged to other accounts		128			78
Deferred income taxes		45,951			40,042
Other		3,242			4,692
Net assets / liabilities from risk management activities		(15,641	)		(8,426	)
Net change in operating assets and liabilities		(144,787	)		(180,917	)

Net cash provided (used) by operating activities		29,858			(15,291	)
Cash Flows From Investing Activities
Capital expenditures		(190,027	)		(154,394	)
Other, net		(1,273	)		(1,080	)

Net cash used in investing activities		(191,300	)		(155,474	)
Cash Flows From Financing Activities
Net increase in short-term debt		256,933			173,905
Repayment of long-term debt		—			(2,303	)
Cash dividends paid		(31,992	)		(31,517	)
Repurchase of common stock		—			(12,535	)
Repurchase of equity awards		(3,124	)		(3,120	)
Issuance of common stock		(13	)		76

Net cash provided by financing activities		221,804			124,506

Net increase (decrease) in cash and cash equivalents		60,362			(46,259	)
Cash and cash equivalents at beginning of period		64,239			131,419

Cash and cash equivalents at end of period	$	124,601		$	85,160

See accompanying notes to condensed consolidated financial statements

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 31, 2012

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”), headquartered in Dallas, Texas, is engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. For the fiscal year ended September 30, 2012, our regulated businesses comprised over 95 percent of our consolidated net income.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions which cover service areas located in nine states. In addition, we transport natural gas for others through our distribution system. In August 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, representing approximately 64,000 customers. After the closing of this transaction, which we currently anticipate will occur during the third quarter of fiscal 2013, we will operate in eight states. 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 regulated 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 through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy and third parties.

We operate the Company through the following three segments:

•

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

•

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

•

the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other 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, 2012. 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, 2012. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2012 are not indicative of our results of operations for the full 2013 fiscal year, which ends September 30, 2013.

We have evaluated subsequent events from the December 31, 2012 balance sheet date through the date these financial statements were filed with the Securities and Exchange Commission (SEC). Except as discussed in Note 3, Note 6 and Note 9, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Significant accounting policies

Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012.

Due to the pending sale of our distribution operations in our Georgia service area, the financial results for this service area are shown in discontinued operations. Accordingly, certain prior-year amounts have been reclassified to conform with the current-year presentation.

Due to accounting guidance that became effective for us on October 1, 2012, we have begun presenting the components of other comprehensive income and total comprehensive income in a separate condensed consolidated statement of comprehensive income immediately following the condensed consolidated statement of income. During the three months ended December 31, 2012, there were no other significant changes to our accounting policies.

Regulatory assets and liabilities

Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.

Significant regulatory assets and liabilities as of December 31, 2012 and September 30, 2012 included the following:


	December 31, 2012		September 30, 2012
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	295,277	$	296,160
Merger and integration costs, net		5,628		5,754
Deferred gas costs		28,351		31,359
Regulatory cost of removal asset		10,401		10,500
Rate case costs		5,726		4,661
Deferred franchise fees		819		2,714
Texas Rule 8.209⁽²⁾		9,734		5,370
APT annual adjustment mechanism		3,973		4,539
Other		6,973		7,262

	$	366,882	$	368,319

Regulatory liabilities:
Deferred gas costs	$	8,290	$	23,072
Regulatory cost of removal obligation		450,968		459,688
Other		5,534		5,637

	$	464,792	$	488,397

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

⁽¹⁾

Includes $11.5 million and $7.6 million of pension and post-retirement expense deferred in our Texas service areas pursuant to the Texas Gas Utility Regulatory Act.

⁽²⁾

Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing) at which time investment and costs would be recovered through base rates.

The amounts above do not include regulatory assets and liabilities related to our Georgia service area, which are classified as assets held for sale as discussed in Note 5.

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.

Accumulated Other Comprehensive Income

Accumulated other comprehensive loss, net of tax, as of December 31, 2012 and September 30, 2012 consisted of the following unrealized gains (losses):


	December 31, 2012			September 30, 2012
	(In thousands)
Accumulated other comprehensive loss:
Unrealized holding gains on available-for-sale securities	$	5,288		$	5,661
Interest rate agreements		(32,009	)		(44,273	)
Commodity cash flow hedges		(9,360	)		(8,995	)

	$	(36,081	)	$	(47,607	)

3. Financial Instruments

We use financial instruments to mitigate commodity price risk and 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 consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. 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 and nonregulated segments. 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 effects 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

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 2012-2013 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 33 percent, or 22.6 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

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 costs 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 costs when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.

Nonregulated Commodity Risk Management Activities

Our nonregulated operations aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. To provide these services, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.

As a result of these activities, our nonregulated segment is 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. Future contracts provide the right, but not the obligation, to buy or sell the commodity at a fixed price. 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 nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 60 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in asset optimization activities in our nonregulated segment.

Our nonregulated operations also 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 for accounting purposes.

Interest Rate Risk Management Activities

We have periodically managed interest rate risk by entering into financial instruments to fix the Treasury yield component of the interest cost associated with anticipated financings. Prior to fiscal 2012, we used Treasury locks to mitigate interest rate risk; however, beginning in the fourth quarter of fiscal 2012 we started utilizing interest rate swaps and forward starting interest rate swaps to manage this risk.

In August 2011, we entered into three Treasury lock agreements to fix the Treasury yield component of the interest cost associated with $350 million of a total $500 million of senior notes that were issued on January 11,

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2013. This offering is discussed in Note 6. We designated these Treasury locks as cash flow hedges. The Treasury locks were settled on January 8, 2013 with the payment of $66.7 million to the counterparties due to a decrease in the 30-year Treasury lock rates between inception of the Treasury locks and settlement. Because the Treasury locks were effective, the $66.7 million unrealized loss was recorded as a component of accumulated other comprehensive income and will be recognized as a component of interest expense over the 30-year life of the senior notes.

In the fourth quarter of fiscal 2012, we entered into an interest rate swap to fix the LIBOR component of our $260 million short-term financing facility that terminated on December 27, 2012. We recorded an immaterial loss upon settlement of the swap, which was recorded as a component of interest expense as we did not designate the interest rate swap as a hedge.

In October 2012, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017, which we designated as cash flow hedges at the time the agreements were executed. Accordingly, unrealized gains and losses associated with the forward starting interest rate swaps will be recorded as a component of accumulated other comprehensive income (loss). When the forward starting interest rate swaps settle, the realized gain or loss will be recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest expense over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred will be reported as a component of interest expense.

In prior years, we entered into Treasury lock agreements to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes. The gains and losses realized upon settlement of these Treasury locks were recorded as a component of accumulated other comprehensive income (loss) when they were settled and are being recognized as a component of interest expense over the life of the associated notes from the date of settlement. As of December 31, 2012, the remaining amortization periods for the settled Treasury locks extend through fiscal 2041.

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, 2012, 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, 2012, we had net long/(short) commodity contracts outstanding in the following quantities:


Contract Type	Hedge Designation	Natural Gas Distribution		Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value		—		(26,450	)
	Cash Flow		—		28,718
	Not designated		12,479		55,915

			12,479		58,183

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Impact of 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, 2012 and September 30, 2012. 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 $16.6 million and $23.7 million of cash held on deposit as of December 31, 2012 and September 30, 2012 to collateralize certain financial instruments. Therefore, these gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not be equal to the amounts presented on our condensed consolidated balance sheet, nor will they be equal to the fair value information presented for our financial instruments in Note 4.


	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
December 31, 2012:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	20,103		$	20,103
Noncurrent commodity contracts	Deferred charges and other assets		10,849			699			11,548
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(77,078	)		(17,995	)		(95,073	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(4,084	)		(4,084	)

Total			(66,229	)		(1,277	)		(67,506	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets		1,773			94,168			95,941
Noncurrent commodity contracts	Deferred charges and other assets		761			59,791			60,552
Liability Financial Instruments
Current commodity contracts	Other current liabilities⁽¹⁾		(502	)		(94,978	)		(95,480	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(59,266	)		(59,266	)

Total			2,032			(285	)		1,747

Total Financial Instruments		$	(64,197)		$	(1,562	)	$	(65,759	)

⁽¹⁾

Other current liabilities not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management liabilities that were classified as assets held for sale at December 31, 2012.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Balance Sheet Location	Natural Gas Distribution			Nonregulated			Total
					(In thousands)
September 30, 2012:
Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets	$	—		$	19,301		$	19,301
Noncurrent commodity contracts	Deferred charges and other assets		—			1,923			1,923
Liability Financial Instruments
Current commodity contracts	Other current liabilities		(85,040	)		(23,787	)		(108,827	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(4,999	)		(4,999	)

Total			(85,040	)		(7,562	)		(92,602	)
Not Designated As Hedges:
Asset Financial Instruments
Current commodity contracts	Other current assets⁽¹⁾		7,082			98,393			105,475
Noncurrent commodity contracts	Deferred charges and other assets		2,283			60,932			63,215
Liability Financial Instruments
Current commodity contracts	Other current liabilities⁽²⁾		(585	)		(99,824	)		(100,409	)
Noncurrent commodity contracts	Deferred credits and other liabilities		—			(67,062	)		(67,062	)

Total			8,780			(7,561	)		1,219

Total Financial Instruments		$	(76,260)		$	(15,123	)	$	(91,383	)

⁽¹⁾

Other current assets not designated as hedges in our natural gas distribution segment include $0.1 million related to risk management assets that were classified as assets held for sale at September 30, 2012.

⁽²⁾

Other current liabilities not designated as hedges in our natural gas distribution segment include $0.3 million related to risk management liabilities that were classified as assets held for sale at September 30, 2012.

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our nonregulated segment 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, 2012 and 2011 we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $16.1 million and $8.4 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value Hedges

The impact of our nonregulated 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, 2012 and 2011 is presented below.


	Three Months Ended December 31
	2012			2011
	(In thousands)
Commodity contracts	$	7,314		$	24,064
Fair value adjustment for natural gas inventory designated as the hedged item		8,818			(15,249	)

Total decrease in purchased gas cost	$	16,132		$	8,815

The decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(241	)	$	841
Timing ineffectiveness		16,373			7,974

	$	16,132		$	8,815

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 purchased gas cost.

To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market. We did not record a writedown for nonqualifying natural gas inventory for the three months ended December 31, 2012. During the three months ended December 31, 2011, we recorded a $1.7 million charge to write down nonqualifying natural gas inventory to market.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2012 and 2011 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.


	Three Months Ended December 31, 2012
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	$	—		$	(5,160	)	$	(5,160	)
Loss arising from ineffective portion of commodity contracts		—			(19	)		(19	)

Total impact on purchased gas cost		—			(5,179	)		(5,179	)
Loss on settled interest rate agreements reclassified from AOCI into interest expense		(502	)		—			(502	)

Total Impact from Cash Flow Hedges	$	(502	)	$	(5,179	)	$	(5,681	)


	Three Months Ended December 31, 2011
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI into purchased gas cost for effective portion of commodity contracts	$	—		$	(11,642	)	$	(11,642	)
Loss arising from ineffective portion of commodity contracts		—			(430	)		(430	)

Total impact on purchased gas cost		—			(12,072	)		(12,072	)
Loss on settled interest rate agreements reclassified from AOCI into interest expense		(502	)		—			(502	)

Total Impact from Cash Flow Hedges	$	(502	)	$	(12,072	)	$	(12,574	)

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, 2012 and 2011. 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
	2012			2011
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	11,945		$	(1,403	)
Forward commodity contracts		(3,513	)		(23,678	)
Recognition of losses in earnings due to settlements:
Interest rate agreements		319			316
Forward commodity contracts		3,148			7,103

Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	11,899		$	(17,662	)

⁽¹⁾

Utilizing an income tax rate ranging from 37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with our Treasury lock and interest rate swap agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred gains (losses) associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2012. However, the table below does not include the expected recognition in earnings of our outstanding Treasury lock and interest rate swap agreements as those instruments have not yet settled.


	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
Next twelve months	$	(1,276	)	$	(7,342	)	$	(8,618	)
Thereafter		11,322			(2,018	)		9,304

Total⁽¹⁾	$	10,046		$	(9,360	)	$	686

⁽¹⁾

Utilizing an income tax rate ranging from 37 percent to 39 percent comprised of the effective rates in each taxing jurisdiction.

Impact of Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statement for the three months ended December 31, 2012 and 2011 was a decrease in revenue of $0.1 million and $2.2 million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

As discussed above, financial instruments used in our natural gas distribution segment are not designated as hedges. However, there is no earnings impact on our natural gas distribution segment as a result of the use of

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

4. Fair Value Measurements

We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the first quarter of fiscal 2013, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 9 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2012.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2012 and September 30, 2012. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.


	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral⁽²⁾			December 31, 2012
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	13,383	$	—	$	—		$	13,383
Nonregulated segment		1,043		173,718		—		(156,904	)		17,857

Total financial instruments		1,043		187,101		—		(156,904	)		31,240

Hedged portion of gas stored underground		87,401		—		—		—			87,401
Available-for-sale securities
Money market funds		—		801		—		—			801
Registered investment companies		39,499		—		—		—			39,499
Bonds		—		23,565		—		—			23,565

Total available-for-sale securities		39,499		24,366		—		—			63,865

Total assets	$	127,943	$	211,467	$	—	$	(156,904	)	$	182,506

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	77,580	$	—	$	—		$	77,580
Nonregulated segment		1,261		175,062		—		(173,463	)		2,860

Total liabilities	$	1,261	$	252,642	$	—	$	(173,463	)	$	80,440

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral⁽³⁾			September 30, 2012
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	9,365	$	—	$	—		$	9,365
Nonregulated segment		714		179,835		—		(162,776	)		17,773

Total financial instruments		714		189,200		—		(162,776	)		27,138

Hedged portion of gas stored underground		67,192		—		—		—			67,192
Available-for-sale securities
Money market funds		—		1,634		—		—			1,634
Registered investment companies		40,212		—		—		—			40,212
Bonds		—		22,552		—		—			22,552

Total available-for-sale securities		40,212		24,186		—		—			64,398

Total assets	$	108,118	$	213,386	$	—	$	(162,776	)	$	158,728

Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	85,625	$	—	$	—		$	85,625
Nonregulated segment		4,563		191,109		—		(186,451	)		9,221

Total liabilities	$	4,563	$	276,734	$	—	$	(186,451	)	$	94,846

⁽¹⁾

Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

⁽²⁾

This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of December 31, 2012, we had $16.6 million of cash held in margin accounts to collateralize certain financial instruments, which amount is classified as current risk management assets.

⁽³⁾

This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2012 we had $23.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $5.9 million was used to offset current risk management liabilities under master netting arrangements and the remaining $17.8 million is classified as current risk management assets.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Available-for-sale securities are comprised of the following:


	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of December 31, 2012
Domestic equity mutual funds	$	25,645	$	7,209	$	—		$	32,854
Foreign equity mutual funds		5,568		1,077		—			6,645
Bonds		23,387		180		(2	)		23,565
Money market funds		801		—		—			801

	$	55,401	$	8,466	$	(2	)	$	63,865

As of September 30, 2012
Domestic equity mutual funds	$	25,779	$	8,183	$	—		$	33,962
Foreign equity mutual funds		5,568		682		—			6,250
Bonds		22,358		196		(2	)		22,552
Money market funds		1,634		—		—			1,634

	$	55,339	$	9,061	$	(2	)	$	64,398

At December 31, 2012 and September 30, 2012, our available-for-sale securities included $40.3 million and $41.8 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2012, we maintained investments in bonds that have contractual maturity dates ranging from January 2013 through July 2016.

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.

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, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of December 31, 2012:


	December 31, 2012
	(In thousands)
Carrying Amount	$	1,960,131
Fair Value	$	2,403,501

5. Discontinued Operations

On August 8, 2012, we entered into a definitive agreement to sell substantially all of our natural gas distribution assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $141 million. The agreement contains terms and conditions customary

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for transactions of this type, including typical adjustments to the purchase price at closing, if applicable. The closing of the transaction is subject to the satisfaction of customary conditions including the receipt of applicable regulatory approvals. We currently anticipate the transaction will close during the third quarter of fiscal 2013.

As required under generally accepted accounting principles, the operating results of our discontinued operations have been aggregated and reported on the consolidated statements of income as income from discontinued operations, net of income tax. For the three months ended December 31, 2012, net income for discontinued operations includes the operating results of our Georgia operations. For the three months ended December 31, 2011, net income from discontinued operations includes the operating results of our Georgia operations and the operating results of our Missouri, Illinois and Iowa operations that were sold on August 1, 2012. Expenses related to general corporate overhead and interest expense allocated to the operations of these service areas are not included in discontinued operations.

The tables below set forth selected financial and operational information related to net assets and operating results related to discontinued operations. Additionally, assets and liabilities related to our Georgia operations are classified as “held for sale” in other current assets and liabilities in our consolidated balance sheets at December 31, 2012 and September 30, 2012. Prior period revenues and expenses associated with these assets have been reclassified into discontinued operations. This reclassification had no impact on previously reported net income.

The following table presents statement of income data related to discontinued operations.


	Three Months Ended December 31
	2012		2011
	(In thousands)
Operating revenues	$	16,284	$	40,630
Purchased gas cost		8,967		24,640

Gross profit		7,317		15,990
Operating expenses		2,820		6,728

Operating income		4,497		9,262
Other nonoperating income		348		377

Income from discontinued operations before income taxes		4,845		9,639
Income tax expense		1,728		3,516

Net income	$	3,117	$	6,123

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents balance sheet data related to assets held for sale.


	December 31, 2012		September 30, 2012
	(In thousands)
Net plant, property & equipment	$	141,850	$	142,865
Gas stored underground		5,320		4,688
Other current assets		11,605		6,931
Deferred charges and other assets		45		87

Assets held for sale	$	158,820	$	154,571

Accounts payable and accrued liabilities	$	3,705	$	2,114
Other current liabilities		3,265		3,776
Regulatory cost of removal obligation		3,525		3,257
Deferred credits and other liabilities		417		2,426

Liabilities held for sale	$	10,912	$	11,573

6. Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. Except as discussed below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2012.

Long-term debt

Long-term debt at December 31, 2012 and September 30, 2012 consisted of the following:


	December 31, 2012		September 30, 2012
	(In thousands)
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
Unsecured 5.50% Senior Notes, due 2041		400,000		400,000
Medium term notes
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		131		131

Total long-term debt		1,960,131		1,960,131
Less:
Original issue discount on unsecured senior notes and debentures		3,624		3,695
Current maturities		131		131

	$	1,956,376	$	1,956,305

Our $250 million Unsecured 5.125% Senior Notes were originally scheduled to mature in January 2013. On August 28, 2012 we redeemed these notes with proceeds received through the issuance of commercial paper. On

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 27, 2012, we entered into a $260 million short-term financing facility that was scheduled to mature on February 1, 2013 to repay the commercial paper borrowings utilized to redeem the Unsecured 5.125% Senior Notes. The short-term facility was repaid with the proceeds received through the issuance of 30-year unsecured senior notes on January 11, 2013, as discussed below.

We issued $500 million Unsecured 4.15% Senior Notes on January 11, 2013. The effective interest rate of these notes is 4.64 percent, after giving effect to offering costs and the settlement of the associated Treasury locks discussed in Note 3. Of the net proceeds of approximately $494 million, $260 million was used to repay our short-term financing facility. The remaining $234 million of net proceeds was used to partially repay our commercial paper borrowings and for general corporate purposes.

Short-term debt

Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. 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 currently finance our short-term borrowing requirements through a combination of a $750 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. On December 7, 2012, we amended the terms of our former $750 million unsecured credit facility to increase the borrowing capacity to $950 million, with an accordion feature, which, if utilized, would increase the borrowing capacity to $1.2 billion. The amendment also permits us to obtain same-day funding on base rate loans. There were no other material changes to the credit facility. These facilities provide approximately $1.0 billion of working capital funding. At December 31, 2012 and September 30, 2012, there was $570.9 million and $310.9 million outstanding under our commercial paper program. We also use intercompany credit facilities to supplement the funding provided by these third-party committed credit facilities.

Regulated Operations

We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $989 million of working capital funding, including a five-year $950 million unsecured facility, a $25 million unsecured facility and a $14 million revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $14 million revolving credit facility was $2.5 million at December 31, 2012.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) 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 our use of this facility through December 31, 2013.

Nonregulated Operations

Prior to December 5, 2012, Atmos Energy Marketing, LLC (AEM), which is wholly-owned by AEH, had a three-year $200 million committed revolving credit facility, expiring in December 2014, with a syndicate of third-party lenders with an accordion feature that could increase AEM’s borrowing capacity to $500 million. The credit facility was primarily used to issue letters of credit and, on a less frequent basis, to borrow funds for gas purchases and other working capital needs. This facility was collateralized by substantially all of the assets of AEM and was guaranteed by AEH. AEM terminated the committed revolving credit facility on December 5, 2012, primarily in order to reduce external credit expense. AEM incurred no penalties in connection with the

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

termination. This facility was replaced with two $25 million, 364-day bilateral credit facilities, one of which is a committed facility. These facilities will be used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $40.0 million at December 31, 2012.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the greater of (i) the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM’s borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2013.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. At December 31, 2012, $900 million remained available for issuance under the shelf until it expires on March 31, 2013. However, with the issuance of $500 million of long-term debt on January 11, 2013, as described above, our remaining availability has been reduced to $400 million. We intend to file a new shelf registration statement with the SEC for $1.75 billion prior to the expiration of the current shelf registration statement.

Debt Covenants

The availability of funds under our regulated 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, 2012, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 55 percent. In addition, both the interest margin 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 financial covenants, our credit facilities and public debt 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.

We were in compliance with all of our debt covenants as of December 31, 2012. 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.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Earnings Per Share

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. The Company’s non-vested 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. Basic and diluted earnings per share for the three months ended December 31, 2012 and 2011 are calculated as follows:


	Three Months Ended December 31
	2012		2011
	(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	77,348	$	62,384
Less: Income from continuing operations allocated to participating securities		260		650

Income from continuing operations available to common shareholders	$	77,088	$	61,734

Basic weighted average shares outstanding		90,359		90,254

Income from continuing operations per share — Basic	$	0.85	$	0.68

Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	3,117	$	6,123
Less: Income from discontinued operations allocated to participating securities		10		64

Income from discontinued operations available to common shareholders	$	3,107	$	6,059

Basic weighted average shares outstanding		90,359		90,254

Income from discontinued operations per share — Basic	$	0.04	$	0.07

Net income per share — Basic	$	0.89	$	0.75

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended December 31
	2012		2011
	(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	77,088	$	61,734
Effect of dilutive stock options and other shares		2		1

Income from continuing operations available to common shareholders	$	77,090	$	61,735

Basic weighted average shares outstanding		90,359		90,254
Additional dilutive stock options and other shares		950		292

Diluted weighted average shares outstanding		91,309		90,546

Income from continuing operations per share — Diluted	$	0.85	$	0.68

Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	3,107	$	6,059
Effect of dilutive stock options and other shares		—		—

Income from discontinued operations available to common shareholders	$	3,107	$	6,059

Basic weighted average shares outstanding		90,359		90,254
Additional dilutive stock options and other shares		950		292

Diluted weighted average shares outstanding		91,309		90,546

Income from discontinued operations per share — Diluted	$	0.03	$	0.07

Net income per share — Diluted	$	0.88	$	0.75

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, 2012 and 2011 as their exercise price was less than the average market price of the common stock during that period.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. 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, 2012 and 2011 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
	2012			2011			2012			2011
	(In thousands)
Components of net periodic pension cost:
Service cost	$	5,202		$	4,298		$	4,700		$	4,088
Interest cost		6,025			6,677			3,241			3,465
Expected return on assets		(5,739	)		(5,368	)		(997	)		(652	)
Amortization of transition asset		—			—			270			378
Amortization of prior service cost		(35	)		(35	)		(362	)		(362	)
Amortization of actuarial loss		5,561			4,142			1,049			662

Net periodic pension cost	$	11,014		$	9,714		$	7,901		$	7,579

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2012 and 2011 are as follows:


	Pension Benefits						Other Benefits
	2012			2011			2012			2011
Discount rate		4.04	%		5.05	%		4.04	%		5.05	%
Rate of compensation increase		3.50	%		3.50	%		N/A			N/A
Expected return on plan assets		7.75	%		7.75	%		4.70	%		4.70	%

The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. We contributed $6.2 million to our pension plans during the three months ended December 31, 2012. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2013. We expect to contribute a total of between $30 million and $40 million to our pension plans during fiscal 2013.

We contributed $6.2 million to our other post-retirement benefit plans during the three months ended December 31, 2012. We expect to contribute a total of between $25 million and $30 million to these plans during fiscal 2013.

9. Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 13 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2012.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Since September 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.

Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.

During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.

A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals (Court), appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court on January 16, 2012, with our reply brief being filed with the Court on March 19, 2012. Oral arguments were held in the case on August 27, 2012.

In an opinion handed down on January 25, 2013, the Kentucky Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.

The landowners and investors/working interest owners may seek discretionary review from the Supreme Court of Kentucky. The decision of the Court of Appeals will not become final until that process is completed. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter and we will continue to maintain this amount in legal reserves until the appellate process in this case has been completed. We continue to believe that the final outcome will not have a material adverse effect on our financial condition, results of operations or cash flows.

In addition, in a related development, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

process and related costs are ongoing. This lawsuit is based upon the indemnification provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Since that time, we have continued to be engaged in discovery activities in this case.

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

Purchase Commitments

AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2012, AEH was committed to purchase 67.2 Bcf within one year, 25.1 Bcf within one to three years and 26.5 Bcf after three years under indexed contracts. AEH is committed to purchase 3.7 Bcf within one year and less than 0.1 Bcf within one to three years under fixed price contracts with prices ranging from $2.98 to $6.36 per Mcf. Purchases under these contracts totaled $289.5 million and $312.1 million for the three months ended December 31, 2012 and 2011.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of December 31, 2012 are as follows (in thousands):


2013	$	174,615
2014		73,682
2015		—
2016		—
2017		—
Thereafter		—

	$	248,297

Our nonregulated segment maintains 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, 2012. There were no material changes to the estimated storage and transportation fees for the quarter ended December 31, 2012.

Regulatory Matters

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (CFTC) to establish rules and regulations for implementation of many of the provisions of the Dodd-Frank Act. Although the CFTC and SEC have issued a

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

number of rules and regulations, we expect additional rules and regulations to be adopted, which should provide additional clarity regarding the extent of the impact of this legislation on us. The costs of participating in financial markets for hedging certain risks inherent in our business have been increased as a result of the new legislation and related rules and regulations. We also anticipate additional reporting and disclosure obligations will be imposed through the adoption of additional rules and regulations.

As of December 31, 2012, rate proceedings were in progress in our Kansas, Colorado, Louisiana and Georgia service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

10. Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the three months ended December 31, 2012, there were no material changes in our concentration of credit risk.

11. Segment Information

As discussed in Note 1 above, we operate the Company through the following three segments:

•

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

•

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

•

The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other 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, 2012. 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, 2012 and 2011 by segment are presented in the following tables:


	Three Months Ended December 31, 2012
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	665,549		$	18,699		$	349,907	$	—		$	1,034,155
Intersegment revenues		1,238			41,982			49,987		(93,207	)		—

		666,787			60,681			399,894		(93,207	)		1,034,155
Purchased gas cost		387,156			—			377,435		(92,798	)		671,793

Gross profit		279,631			60,681			22,459		(409	)		362,362
Operating expenses
Operation and maintenance		83,736			16,320			6,882		(411	)		106,527
Depreciation and amortization		50,060			8,390			1,129		—			59,579
Taxes, other than income		36,751			3,949			634		—			41,334

Total operating expenses		170,547			28,659			8,645		(411	)		207,440

Operating income		109,084			32,022			13,814		2			154,922
Miscellaneous income (expense)		(131	)		(127	)		1,667		(711	)		698
Interest charges		23,563			6,871			797		(709	)		30,522

Income from continuing operations before income taxes		85,390			25,024			14,684		—			125,098
Income tax expense		32,297			8,919			6,534		—			47,750

Income from continuing operations		53,093			16,105			8,150		—			77,348
Income from discontinued operations, net of tax		3,117			—			—		—			3,117

Net income	$	56,210		$	16,105		$	8,150	$	—		$	80,465

Capital expenditures	$	145,871		$	43,831		$	325	$	—		$	190,027

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months Ended December 31, 2011
	Natural Gas Distribution			Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	675,889		$	19,440		$	388,665	$	—		$	1,083,994
Intersegment revenues		224			37,319			55,511		(93,054	)		—

		676,113			56,759			444,176		(93,054	)		1,083,994
Purchased gas cost		392,518			—			428,771		(92,687	)		728,602

Gross profit		283,595			56,759			15,405		(367	)		355,392
Operating expenses
Operation and maintenance		91,996			16,965			6,051		(368	)		114,644
Depreciation and amortization		49,982			7,651			733		—			58,366
Taxes, other than income		38,192			3,784			935		—			42,911

Total operating expenses		180,170			28,400			7,719		(368	)		215,921

Operating income		103,425			28,359			7,686		1			139,471
Miscellaneous income (expense)		(1,897	)		(280	)		36		125			(2,016	)
Interest charges		28,139			7,209			252		126			35,726

Income from continuing operations before income taxes		73,389			20,870			7,470		—			101,729
Income tax expense		28,888			7,456			3,001		—			39,345

Income from continuing operations		44,501			13,414			4,469		—			62,384
Income from discontinued operations, net of tax		6,123			—			—		—			6,123

Net income	$	50,624		$	13,414		$	4,469	$	—		$	68,507

Capital expenditures	$	128,733		$	24,120		$	1,541	$	—		$	154,394

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Balance sheet information at December 31, 2012 and September 30, 2012 by segment is presented in the following tables.


	December 31, 2012
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,523,922	$	1,007,904	$	63,468		$	—		$	5,595,294
Investment in subsidiaries		771,387		—		(2,096	)		(769,291	)		—
Current assets
Cash and cash equivalents		77,136		—		47,465			—			124,601
Assets from risk management activities		1,773		—		17,857			—			19,630
Other current assets		770,366		14,632		471,582			(236,177	)		1,020,403
Intercompany receivables		624,637		—		—			(624,637	)		—

Total current assets		1,473,912		14,632		536,904			(860,814	)		1,164,634
Intangible assets		—		—		153			—			153
Goodwill		573,550		132,422		34,711			—			740,683
Noncurrent assets from risk management activities		11,610		—		—			—			11,610
Deferred charges and other assets		429,252		15,787		6,805			—			451,844

	$	7,783,633	$	1,170,745	$	639,945		$	(1,630,105	)	$	7,964,218

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,424,005	$	344,266	$	427,121		$	(771,387	)	$	2,424,005
Long-term debt		1,956,376		—		—			—			1,956,376

Total capitalization		4,380,381		344,266		427,121			(771,387	)		4,380,381
Current liabilities
Current maturities of long-term debt		—		—		131			—			131
Short-term debt		1,045,180		—		—			(214,289	)		830,891
Liabilities from risk management activities		77,500		—		—			—			77,500
Other current liabilities		590,710		13,470		152,141			(19,792	)		736,529
Intercompany payables		—		573,006		51,631			(624,637	)		—

Total current liabilities		1,713,390		586,476		203,903			(858,718	)		1,645,051
Deferred income taxes		823,073		238,285		4,915			—			1,066,273
Noncurrent liabilities from risk management activities		—		—		2,860			—			2,860
Regulatory cost of removal obligation		371,608		—		—			—			371,608
Deferred credits and other liabilities		495,181		1,718		1,146			—			498,045

	$	7,783,633	$	1,170,745	$	639,945		$	(1,630,105	)	$	7,964,218

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	September 30, 2012
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,432,017	$	979,443	$	64,144		$	—		$	5,475,604
Investment in subsidiaries		747,496		—		(2,096	)		(745,400	)		—
Current assets
Cash and cash equivalents		12,787		—		51,452			—			64,239
Assets from risk management activities		6,934		—		17,773			—			24,707
Other current assets		546,187		11,788		404,097			(223,056	)		739,016
Intercompany receivables		636,557		—		—			(636,557	)		—

Total current assets		1,202,465		11,788		473,322			(859,613	)		827,962
Intangible assets		—		—		164			—			164
Goodwill		573,550		132,422		34,711			—			740,683
Noncurrent assets from risk management activities		2,283		—		—			—			2,283
Deferred charges and other assets		417,893		24,353		6,733			—			448,979

	$	7,375,704	$	1,148,006	$	576,978		$	(1,605,013	)	$	7,495,675

CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,359,243	$	328,161	$	419,335		$	(747,496	)	$	2,359,243
Long-term debt		1,956,305		—		—			—			1,956,305

Total capitalization		4,315,548		328,161		419,335			(747,496	)		4,315,548
Current liabilities
Current maturities of long-term debt		—		—		131			—			131
Short-term debt		782,719		—		—			(211,790	)		570,929
Liabilities from risk management activities		85,366		—		15			—			85,381
Other current liabilities		526,089		12,478		90,116			(9,170	)		619,513
Intercompany payables		—		584,578		51,979			(636,557	)		—

Total current liabilities		1,394,174		597,056		142,241			(857,517	)		1,275,954
Deferred income taxes		789,288		220,647		5,148			—			1,015,083
Noncurrent liabilities from risk management activities		—		—		9,206			—			9,206
Regulatory cost of removal obligation		381,164		—		—			—			381,164
Deferred credits and other liabilities		495,530		2,142		1,048			—			498,720

	$	7,375,704	$	1,148,006	$	576,978		$	(1,605,013	)	$	7,495,675

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 and subsidiaries as of December 31, 2012, the related condensed consolidated statements of income and comprehensive income for the three-month periods ended December 31, 2012 and 2011, and the condensed consolidated statements of cash flows for the three-month periods ended December 31, 2012 and 2011. 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 and subsidiaries as of September 30, 2012, 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 12, 2012, 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, 2012, 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 7, 2013

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, 2012.

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 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 along with increased costs of health care benefits; 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; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the concentration of our distribution, pipeline and storage operations in Texas; adverse weather conditions; the effects of inflation and changes in the availability and price of natural gas; the capital-intensive nature of our gas distribution business; increased competition from energy suppliers and alternative forms of energy; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; 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 its subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which cover service areas located in nine states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems. In August 2012, we announced that we had entered into a definitive agreement to sell our natural gas distribution operations in Georgia, representing approximately 64,000 customers. After the closing of this transaction, which we currently anticipate will occur during the third quarter of fiscal 2013, we will operate in eight states.

Through our nonregulated businesses, we provide natural gas management and transportation 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.

As discussed in Note 11, we operate the Company through the following three segments:

•

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

•

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

•

the nonregulated segment, which includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other 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, 2012 and include the following:

•

Regulation

•

Unbilled revenue

•

Financial instruments and hedging activities

•

Fair value measurements

•

Impairment assessments

•

Pension and other postretirement plans

•

Contingencies

Our critical accounting policies are reviewed periodically by the Audit Committee. There were no significant changes to these critical accounting policies during the three months ended December 31, 2012.

RESULTS OF OPERATIONS

We reported net income of $80.5 million, or $0.88 per diluted share for the three months ended December 31, 2012 compared with net income of $68.5 million, or $0.75 per diluted share in the prior-year quarter. Regulated operations contributed 90 percent of our net income during this period with our nonregulated operations contributing the remaining ten percent. Excluding the impact of unrealized margins, diluted earnings per share increased $0.13 compared with the prior-year quarter. The $0.13 per diluted share increase primarily reflects recent rate increases approved in our regulated transmission and storage segment and improved asset optimization margins in our nonregulated segment, coupled with an $8.1 million decrease in operating and maintenance expense and a $5.2 million decrease in interest expense due primarily from interest capitalized related to Rule 8.209 spending in the current quarter and the early redemption of the 5.125% $250 million senior notes due January 2013, with funds borrowed under a $260 million short-term debt facility in August 2012.

Due to the pending sale of our Georgia service area, the results of operations for this service area are shown in discontinued operations for both periods presented. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these three service areas was completed in August 2012. During the current-year quarter, discontinued operations generated net income of $3.1 million, or $0.03 per diluted share, compared with net income of $6.1 million, or $0.07 per diluted share in the prior-year quarter. Continuing operations in the current quarter generated net income of $77.3 million, or $0.85 per diluted share, compared with net income of $62.4 million, or $0.68 per diluted share in the prior-year quarter.

During the first quarter of fiscal 2013, we completed seven regulatory proceedings, which should result in a $63.7 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase to the base customer charge and a decrease in the commodity charge applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second quarters to be lower than in previous periods with operating income earned during the third and fourth quarters to be higher than in previous periods. Accordingly, we anticipate our fiscal 2013 period-over-period results will reflect the impact of these rate design changes.

We also took several steps during the first quarter and early part of the second quarter to further strengthen our balance sheet and borrowing capability. In December 2012, we amended our $750 million revolving credit agreement primarily to (i) increase our borrowing capacity to $950 million while retaining the accordion feature that would allow an increase in borrowing capacity up to $1.2 billion and (ii) to permit same-day funding on base rate loans. We also terminated Atmos Energy Marketing’s $200 million committed and secured credit facility and replaced this facility with two $25 million 364-day bilateral facilities, which should result in a decrease in external credit expense incurred in our nonregulated operations. After giving effect to these changes, we have over $1 billion of working capital funding from four committed revolving credit facilities and one noncommitted revolving credit facility.

On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which replaced, on a long-term basis, our $250 million 5.125% 10-year unsecured senior notes we redeemed in August 2012. The net proceeds of approximately $494 million were used to repay $260 million outstanding under the short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes.

The following table presents our consolidated financial highlights for the three months ended December 31, 2012 and 2011:


	Three Months Ended December 31
	2012		2011
	(In thousands, except per share data)
Operating revenues	$	1,034,155	$	1,083,994
Gross profit		362,362		355,392
Operating expenses		207,440		215,921
Operating income		154,922		139,471
Miscellaneous income (expense)		698		(2,016	)
Interest charges		30,522		35,726
Income from continuing operations before income taxes		125,098		101,729
Income tax expense		47,750		39,345
Income from continuing operations		77,348		62,384
Income from discontinued operations, net of tax		3,117		6,123
Net income	$	80,465	$	68,507
Diluted net income per share from continuing operations	$	0.85	$	0.68
Diluted net income per share from discontinued operations		0.03		0.07
Diluted net income per share	$	0.88	$	0.75

Our consolidated net income during the three months ended December 31, 2012 and 2011 was earned in each of our business segments as follows:


	Three Months Ended December 31
	2012		2011		Change
	(In thousands)
Natural gas distribution segment	$	56,210	$	50,624	$	5,586
Regulated transmission and storage segment		16,105		13,414		2,691
Nonregulated segment		8,150		4,469		3,681

Net income	$	80,465	$	68,507	$	11,958

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


	Three Months Ended December 31
	2012		2011		Change
	(In thousands, except per share data)
Regulated operations	$	69,198	$	57,915	$	11,283
Nonregulated operations		8,150		4,469		3,681

Net income from continuing operations		77,348		62,384		14,964
Net income from discontinued operations		3,117		6,123		(3,006	)

Net income	$	80,465	$	68,507	$	11,958

Diluted EPS from continuing regulated operations	$	0.76	$	0.63	$	0.13
Diluted EPS from nonregulated operations		0.09		0.05		0.04

Diluted EPS from continuing operations		0.85		0.68		0.17
Diluted EPS from discontinued operations		0.03		0.07		(0.04	)

Consolidated diluted EPS	$	0.88	$	0.75	$	0.13

Three Months Ended December 31, 2012 compared with Three Months Ended December 31, 2011

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 96 percent of our residential and commercial meters in the following states for the following time periods:


Georgia, Kansas, West Texas		October — May
Kentucky, Mississippi, Tennessee, Mid-Tex		November — April
Louisiana		December — March
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 a 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 does include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.

As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which 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. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.

In August 2012, we announced that we had entered into a definitive agreement to sell substantially all of our natural gas distribution operations in Georgia. Prior-year results also reflect our Illinois, Iowa and Missouri service areas in discontinued operations. The sale of these service areas was completed in August 2012. The results of these operations have been separately reported in the following tables as discontinued operations and exclude general corporate overhead and interest expense that would normally be allocated to these operations.

During the first quarter of fiscal 2013, we completed seven regulatory proceedings, which should result in a $63.7 million increase in annual operating income. The majority of this rate increase related to our Mid-Tex Division, where rates became effective January 1, 2013. The rate design approved in our Mid-Tex Division and West Texas Division regulatory proceedings includes an increase in the base customer charge and a decrease in the commodity charged applied to customer consumption. The effect of this change in rate design allows the Company’s rates to be more closely aligned with utility industry standard rate design. In addition, we anticipate these divisions will earn their operating income more ratably over the fiscal year as we are now less dependent on customer consumption. Therefore, we anticipate operating income earned during the first and second quarters to be lower than in previous periods while operating income earned during the third and fourth quarters to be higher than in previous periods. Accordingly, we anticipate our 2013 period-over-period results will reflect the impact of these rate design changes.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas distribution segment for the three months ended December 31, 2012 and 2011 are presented below.


	Three Months Ended December 31
	2012			2011			Change
	(In thousands, unless otherwise noted)
Gross profit	$	279,631		$	283,595		$	(3,964	)
Operating expenses		170,547			180,170			(9,623	)

Operating income		109,084			103,425			5,659
Miscellaneous expense		(131	)		(1,897	)		1,766
Interest charges		23,563			28,139			(4,576	)

Income from continuing operations before income taxes		85,390			73,389			12,001
Income tax expense		32,297			28,888			3,409

Income from continuing operations		53,093			44,501			8,592
Income from discontinued operations, net of tax		3,117			6,123			(3,006	)

Net income	$	56,210		$	50,624		$	5,586

Consolidated natural gas distribution sales volumes from continuing operations — MMcf		78,753			83,367			(4,614	)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf		32,889			32,277			612

Consolidated natural gas distribution throughput from continuing operations — MMcf		111,642			115,644			(4,002	)
Consolidated natural gas distribution throughput from discontinued operations — MMcf		2,057			6,104			(4,047	)

Total consolidated natural gas distribution throughput — MMcf		113,699			121,748			(8,049	)

Consolidated natural gas distribution average transportation revenue per Mcf	$	0.47		$	0.45		$	0.02
Consolidated natural gas distribution average cost of gas per Mcf sold	$	4.93		$	4.78		$	0.15

The $4.0 million decrease in natural gas distribution gross profit primarily reflects the following:

•

$4.6 million net decrease in rate adjustments, primarily in the Mid-Tex Division due to the rate design approved in our most recent Mid-Tex rate case, which includes an increase in the base customer charge and a decrease in the commodity charge applied to customer consumption.

•

$2.7 million decrease in revenue related taxes in our Mid-Tex and West Texas Divisions, primarily due to lower revenues on which the tax is calculated.

These decreases were partially offset by a $2.4 million increase from colder weather, primarily in the Mid-Tex service area.

Operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, decreased $9.6 million, primarily due to the following:

•

$2.8 million decrease in legal costs, primarily due to the absence of prior-year settlement costs.

•

$1.9 million decrease in franchise fees due to lower revenue on which the tax is calculated.

•

$1.7 million decrease due to the establishment of regulatory assets for pension and postretirement costs.

•

$1.0 million decrease in operating expenses due to increased capital spending.

Interest charges decreased $4.6 million, primarily from interest capitalized related to Rule 8.209 spending in the current quarter and the early redemption of the 5.125% $250 million senior notes due January 2013, with funds borrowed under a $260 million short-term debt facility in August 2012.

The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the three months ended December 31, 2012 and 2011. 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
	2012		2011			Change
	(In thousands)
Mid-Tex	$	45,577	$	48,449		$	(2,872	)
Kentucky/Mid-States		15,705		11,382			4,323
Louisiana		16,885		15,201			1,684
West Texas		9,578		10,675			(1,097	)
Mississippi		11,613		10,132			1,481
Colorado-Kansas		8,744		8,179			565
Other		982		(593	)		1,575

Total	$	109,084	$	103,425		$	5,659

Recent Ratemaking Developments

Significant ratemaking developments that occurred during the three months ended December 31, 2012 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 final order from a commission or other governmental authority.

Annual net operating income increases totaling $63.7 million resulting from ratemaking activity became effective in the quarter ended December 31, 2012 as summarized below:


Rate Action	Annual Increase to Operating Income
	(In thousands)
Rate case filings	$	56,700
Infrastructure programs		3,605
Annual rate filing mechanisms		3,441

	$	63,746

Additionally, the following ratemaking efforts were in progress during the first quarter of fiscal 2013 but had not been completed as of December 31, 2012.


Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Ad Valorem⁽¹⁾	Kansas	$	1,322
Colorado-Kansas	GSRS⁽²⁾	Kansas		681
Colorado-Kansas	Infrastructure Replacement	Colorado		871
Louisiana	Rate Stabilization Clause	TransLa		2,730
Kentucky/Mid-States	Georgia Rate Adjustment Mechanism⁽³⁾	Georgia		1,079

			$	6,683

⁽¹⁾

The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service area’s base rates. The commission issued a final order on January 16, 2013 for an increase in operating income of $1.3 million.

⁽²⁾

The Gas System Reliability Surcharge (GSRS) filing relates to a collection of qualified infrastructure in Kansas. The Commission issued a final order on January 9, 2013 for an increase in operating income of $0.6 million.

⁽³⁾

On January 31, 2013, the Georgia commission approved a $0.7 million increase in operating revenues effective February 1, 2013.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return for our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. The following table summarizes the rate cases that were completed during the three months ended December 31, 2012.

Division

State

Increase in
Annual Operating
Income

Effective
Date

(In thousands)

2013 Rate Case Filings:

Mid-Tex

Texas

42,601

12/04/2012

Kentucky/Mid-States

Tennessee

7,530

11/08/2012

West Texas

Texas

6,569

10/01/2012

Total 2013 Rate Case Filings

56,700

Infrastructure Programs

Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow our regulated divisions the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. We currently have infrastructure programs in Texas, Georgia, Kentucky and Virginia. The following table summarizes our infrastructure program filings with effective dates during the three months ended December 31, 2012.


Division	Period End		Incremental Net Utility Plant Investment		Increase in Annual Operating Income		Effective Date
			(In thousands)		(In thousands)
2013 Infrastructure Programs:
Kentucky/Mid-States — Georgia		09/2011	$	6,519	$	1,079		10/01/2012
Kentucky/Mid-States — Kentucky		09/2013		19,296		2,425		10/01/2012
Kentucky/Mid-States — Virginia		09/2013		756		101		10/01/2012

Total 2013 Infrastructure Programs			$	26,571	$	3,605

Annual Rate Filing Mechanism

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, Georgia and Mississippi service areas and in a portion of our Mid-Tex Division. These mechanisms are referred to as the Dallas annual rate review (DARR) in our Mid-Tex Division, stable rate filings in the Mississippi Division, Georgia rate adjustment mechanism in our Kentucky/Mid-States Division and a rate stabilization clause in the Louisiana Division. We expect to initiate discussions regarding a new rate review mechanism processes in our West Texas and Mid-Tex Divisions in fiscal 2013. The following annual rate filing mechanism was completed during the three months ended December 31, 2012.

Division

Jurisdiction

Test Year
Ended

Additional
Annual
Operating
Income

Effective
Date

(In thousands)

2013 Filings:

Mississippi

6/30/2012

3,441

11/1/2012

Total 2013 Filings

3,441

Other Ratemaking Activity

There was no other ratemaking activity completed during the three months ended December 31, 2012.

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 arrangements, lending and sales of excess gas.

Our regulated transmission and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Mid-Tex service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve could influence customers to transport gas through our pipeline to capture arbitrage gains.

The results of Atmos Pipeline–Texas Division are also significantly impacted by the natural gas requirements of the Mid-Tex Division because it is the primary supplier of natural gas for our 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, 2012 and 2011 are presented below.


	Three Months Ended December 31
	2012			2011			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	40,785		$	37,343		$	3,442
Third-party transportation		14,549			14,939			(390	)
Storage and park and lend services		1,510			1,806			(296	)
Other		3,837			2,671			1,166

Gross profit		60,681			56,759			3,922
Operating expenses		28,659			28,400			259

Operating income		32,022			28,359			3,663
Miscellaneous expense		(127	)		(280	)		153
Interest charges		6,871			7,209			(338	)

Income before income taxes		25,024			20,870			4,154
Income tax expense		8,919			7,456			1,463

Net income	$	16,105		$	13,414		$	2,691

Gross pipeline transportation volumes — MMcf		161,484			160,829			655

Consolidated pipeline transportation volumes — MMcf		108,743			105,037			3,706

The $3.9 million increase in regulated transmission and storage gross profit was primarily a result of the GRIP filing approved by the RRC during fiscal 2012. During the third fiscal quarter of fiscal 2012, the RRC approved the Atmos Pipeline–Texas GRIP filing with an annual operating income increase of $14.7 million that went into effect in April 2012.

The GRIP filing approved in fiscal 2012 increased quarter-over-quarter gross profit by $3.7 million. In addition, excess retention gas sales increased gross profit by $0.7 million. Partially offsetting these increases was a decrease of $0.6 million due to decreased priority reservation and demand fees.

Nonregulated Segment

Our nonregulated activities are conducted through Atmos Energy Holdings, Inc. (AEH), which is a wholly-owned subsidiary of Atmos Energy Corporation and operates primarily in the Midwest and Southeast areas of the United States.

AEH’s primary business is to deliver gas and provide related services by aggregating and purchasing gas supply, arranging transportation and storage logistics and ultimately delivering gas to customers at competitive prices. These activities are reflected as gas delivery and related services in the table below.

AEH also earns storage and transportation margins from (i) utilizing its proprietary 21-mile pipeline located in New Orleans, Louisiana to aggregate gas supply for our regulated natural gas distribution division in Louisiana, its gas delivery activities and, on a more limited basis, for third parties and (ii) managing proprietary storage in Kentucky and Louisiana to supplement the natural gas needs of our natural gas distribution divisions during

peak periods. Most of these margins are generated through demand fees established under contracts with certain of our natural gas distribution divisions that are renewed periodically and subject to regulatory oversight. These activities are reflected as storage and transportation services in the table below.

AEH utilizes customer-owned or contracted storage capacity to serve its customers. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments in an effort to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Margins earned from these activities and the related storage demand fees are reported as asset optimization margins. Certain of these arrangements are with regulated affiliates, which have been approved by applicable state regulatory commissions.

Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of gas and demand fees paid to contract for storage capacity to offer more competitive pricing to those customers.

Further, natural gas market conditions, most notably the price of natural gas and the level of price volatility affect our nonregulated businesses. Natural gas prices and the level of volatility are influenced by a number of factors including, but not limited to, general economic conditions, the demand for natural gas in different parts of the country, the level of domestic natural gas production and the level of natural gas inventory levels.

Natural gas prices can influence:

•

The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources. Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy sources to natural gas.

•

Collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment.

•

The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this segment.

Natural gas price volatility can also influence our nonregulated business in the following ways:

•

Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost alternative among the natural gas supplies, transportation and markets to which we have access.

•

Price volatility also influences the spreads between the current (spot) prices and forward natural gas prices, which creates opportunities to earn higher arbitrage spreads.

•

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.

Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. 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 generally 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.

Review of Financial and Operating Results

Financial and operational highlights for our nonregulated segment for the three months ended December 31, 2012 and 2011 are presented below.


	Three Months Ended December 31
	2012			2011			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	10,070		$	11,113		$	(1,043	)
Storage and transportation services		3,521			3,189			332
Other		1,013			1,017			(4	)

		14,604			15,319			(715	)
Asset optimization⁽¹⁾		(15,123	)		(21,594	)		6,471

Total realized margins		(519	)		(6,275	)		5,756
Unrealized margins		22,978			21,680			1,298

Gross profit		22,459			15,405			7,054
Operating expenses		8,645			7,719			926

Operating income		13,814			7,686			6,128
Miscellaneous income		1,667			36			1,631
Interest charges		797			252			545

Income before income taxes		14,684			7,470			7,214
Income tax expense		6,534			3,001			3,533

Net income	$	8,150		$	4,469		$	3,681

Gross nonregulated delivered gas sales volumes — MMcf		99,009			106,462			(7,453	)

Consolidated nonregulated delivered gas sales volumes — MMcf		84,718			90,870			(6,152	)

Net physical position (Bcf)		25.8			35.6			(9.8	)

⁽¹⁾

Net of storage fees of $5.9 million and $4.7 million.

Results for our nonregulated operations during the first fiscal quarter were adversely influenced by continued unfavorable natural gas market conditions. Historically high natural gas storage levels primarily resulting from strong domestic natural gas production caused natural gas prices to remain relatively low during the first fiscal quarter. Further, unseasonably warm weather reduced the demand for natural gas.

We anticipate these natural gas market conditions will continue for the foreseeable future. As a result, we anticipate that basis differentials will remain compressed and spot-to-forward price volatility will remain relatively low. Accordingly, although we anticipate continuing to profit on a fiscal-year basis from our nonregulated activities, we anticipate per-unit margins from our delivered gas activities and margins earned from our asset optimization activities will be more consistent with the reduced margins we realized in fiscal 2012 than in previous years.

Realized margins for gas delivery, storage and transportation services and other services were $14.6 million during the three months ended December 31, 2012 compared with $15.3 million for the prior-year quarter. The decrease primarily reflects a seven percent decrease in consolidated sales volumes, which was largely attributable to warmer weather. Gas delivery per-unit margins remained consistent with prior-year per-unit margins at $0.10/Mcf.

Asset optimization margins increased $6.5 million from the prior-year quarter, primarily due to smaller losses incurred from the settlement of financial positions, partially offset by higher storage demand fees.

Realized asset optimization margins for the prior-year quarter also included a $1.7 million charge to write down to market certain natural gas inventory that no longer qualified for fair value hedge accounting.

Operating expenses increased $0.9 million, primarily due to higher contract labor costs.

Miscellaneous income increased $1.6 million primarily due to a gain realized from the sale of a distributed electric generation plant and related assets.

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 regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. We also evaluate the levels of committed borrowing capacity that we require. As discussed below, we currently have over $1 billion of capacity from our short-term facilities.

On January 11, 2013, we issued $500 million of 4.15% 30-year unsecured senior notes, which, in effect, replaced our $250 million 5.125% 30-year unsecured senior notes we redeemed in August 2012, on a long-term basis. The net proceeds of approximately $494 million were used to repay $260 million outstanding under our short-term financing facility used to redeem our 5.125% senior notes and to partially repay commercial paper borrowings and for general corporate purposes, as discussed in Note 6.

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 2013.

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, 2012 and 2011 are presented below.


	Three Months Ended December 31
	2012			2011			2012 vs. 2011
	(In thousands)
Total cash provided by (used in)
Operating activities	$	29,858		$	(15,291	)	$	45,149
Investing activities		(191,300	)		(155,474	)		(35,826	)
Financing activities		221,804			124,506			97,298

Change in cash and cash equivalents		60,362			(46,259	)		106,621
Cash and cash equivalents at beginning of period		64,239			131,419			(67,180	)

Cash and cash equivalents at end of period	$	124,601		$	85,160		$	39,441

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.

The $45.1 million increase in operating cash flows primarily reflects the timing of customer collections and vendor payments as well as the effect of a decrease in the amount of cash used to inject gas into storage, primarily in the company’s nonregulated segment.

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 enhance the safety and reliability of the systems used 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 regulatory strategy, we are focusing our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, our Mid-Tex, Louisiana, Mississippi and West Texas natural gas distribution divisions and our Atmos Pipeline–Texas Division have rate tariffs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

Capital expenditures for fiscal 2013 are expected to range from $770 million to $790 million. For the three months ended December 31, 2012, capital expenditures were $190.0 million compared with $154.4 million for the three months ended December 31, 2011. The $35.6 million increase in capital expenditures primarily reflects infrastructure spending incurred under RRC Rule 8.209 in the Mid-Tex Division of our natural gas distribution segment and for the Line W and Line WX pipeline expansion projects in our regulated transmission and storage segment.

Cash flows from financing activities

The $97.3 million increase in financing cash flows was primarily due to the following:

•

$83.0 million additional cash provided from short-term debt borrowings.

•

$12.5 million increase in cash flows due to the absence of prior-year common stock repurchases as part of our share repurchase program.

•

$2.3 million increase in cash flows due to lower repayments of long-term debt. In the current-year quarter, we did not repay any long-term debt compared to $2.3 million repaid in the prior-year quarter.

The following table summarizes our share issuances for the three months ended December 31, 2012 and 2011.


	Three Months Ended December 31
	2012		2011
Shares issued:
1998 Long-Term Incentive Plan		364,415		197,503
Outside Directors Stock-for-Fee Plan		564		618

Total shares issued		364,979		198,121

The quarter-over-quarter increase in the number of shares issued primarily reflects the type of awards that were issued from the 1998 Long-Term Incentive Plan in each period. In the current-year period, employees were issued restricted stock units, for which we issued new shares. In the prior-year period, employees were issued restricted stock awards, which were held in trust and did not require the issuance of new shares. For the three months ended December 31, 2012 and 2011, we cancelled and retired 87,931 and 99,555 shares attributable to

federal withholdings on equity awards. For the three months ended December 31, 2011, we repurchased and retired 387,991 shares through our 2011 share repurchase program.

Credit Facilities

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

We finance our short-term borrowing requirements through a combination of a $750.0 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1.0 billion of working capital funding. As of December 31, 2012, the amount available to us under our credit facilities, net of outstanding letters of credit, was $446.6 million.

Shelf Registration

We have an effective shelf registration statement with the Securities and Exchange Commission (SEC) that permits us to issue a total of $1.3 billion in common stock and/or debt securities. The shelf registration statement has been approved by all requisite state regulatory commissions. At December 31, 2012, $900 million remained available for issuance under the shelf until it expires on March 31, 2013. However, with the issuance of $500 million of long-term debt on January 11, 2013, as described in Note 6, our remaining availability has been reduced to $400 million. We intend to file a new shelf registration statement with the SEC for $1.75 billion prior to the expiration of the current shelf registration statement.

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, 2012, all three ratings agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:

S&P

Moody’s

Fitch

Unsecured senior long-term debt

BBB+

Baa1

A-

Commercial paper

A-2

P-2

F-2

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

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for 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, 2012. Our debt covenants are described in greater detail in Note 6 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, 2012, September 30, 2012 and December 31, 2011:


	December 31, 2012				September 30, 2012				December 31, 2011
	(In thousands, except percentages)
Short-term debt⁽¹⁾	$	830,891	15.9	%	$	570,929	11.7	%	$	389,985	8.0	%
Long-term debt		1,956,507	37.6	%		1,956,436	40.0	%		2,206,324	45.4	%
Shareholders’ equity		2,424,005	46.5	%		2,359,243	48.3	%		2,267,762	46.6	%

Total	$	5,211,403	100.0	%	$	4,886,608	100.0	%	$	4,864,071	100.0	%

⁽¹⁾

Short-term debt at December 31, 2012 and September 30, 2012 included $260 million outstanding related to a short-term facility we used to redeem our $250 million 5.125% Senior notes in August 2012. The balance outstanding under this short-term facility was repaid in January 2013.

Total debt as a percentage of total capitalization, including short-term debt, was 53.5 percent at December 31, 2012, 51.7 percent at September 30, 2012 and 53.4 percent at December 31, 2011. Our ratio of total debt to capitalization is typically greater during the winter heating season as we incur short-term debt to fund natural gas purchases and meet our working capital requirements. We intend to maintain our debt to capitalization ratio in a target range of 50 to 55 percent.

Contractual Obligations and Commercial Commitments

Our significant commercial commitments are described in Note 9 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, 2012.

Risk Management Activities

We conduct risk management activities through our natural gas distribution and nonregulated 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 nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial 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, 2012 and 2011:


	Three Months Ended December 31
	2012			2011
	(In thousands)
Fair value of contracts at beginning of period	$	(76,260	)	$	(79,277	)
Contracts realized/settled		2,834			(17,729	)
Fair value of new contracts		331			(555	)
Other changes in value		8,898			11,732

Fair value of contracts at end of period	$	(64,197	)	$	(85,829	)

The fair value of our natural gas distribution segment’s financial instruments at December 31, 2012 is presented below by time period and fair value source:


	Fair Value of Contracts at December 31, 2012
	Maturity in Years
Source of Fair Value	Less Than 1			1-3		4-5		Greater Than 5		Total Fair Value
	(In thousands)
Prices actively quoted	$	(75,807	)	$	11,610	$	—	$	—	$	(64,197	)
Prices based on models and other valuation methods		—			—		—		—		—

Total Fair Value	$	(75,807	)	$	11,610	$	—	$	—	$	(64,197	)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three months ended December 31, 2012 and 2011:


	Three Months Ended December 31
	2012			2011
	(In thousands)
Fair value of contracts at beginning of period	$	(15,123	)	$	(25,050	)
Contracts realized/settled		12,736			17,449
Fair value of new contracts		—			—
Other changes in value		825			(7,662	)

Fair value of contracts at end of period		(1,562	)		(15,263	)
Netting of cash collateral		16,559			22,084

Cash collateral and fair value of contracts at period end	$	14,997		$	6,821

The fair value of our nonregulated segment’s financial instruments at December 31, 2012 is presented below by time period and fair value source:


	Fair Value of Contracts at December 31, 2012
	Maturity in Years
Source of Fair Value	Less Than 1		1-3			4-5			Greater Than 5			Total Fair Value
	(In thousands)
Prices actively quoted	$	1,298	$	(2,842	)	$	(5	)	$	(13	)	$	(1,562	)
Prices based on models and other valuation methods		—		—			—			—			—

Total Fair Value	$	1,298	$	(2,842	)	$	(5	)	$	(13	)	$	(1,562	)

Pension and Postretirement Benefits Obligations

For the three months ended December 31, 2012 and 2011, our total net periodic pension and other benefits cost was $18.9 million and $17.3 million. Those costs relating to our natural gas distribution operations are generally 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 2013 costs were determined using a September 30, 2012 measurement date. As of September 30, 2012, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2011, the measurement date for our fiscal 2012 net periodic cost. Accordingly, we decreased our discount rate used to determine our fiscal 2013 pension and benefit costs to

4.04 percent. The expected return on our pension plan assets remained at 7.75 percent, based on historical experience and the current market projection of the target asset allocation. Accordingly, our fiscal 2013 pension and postretirement medical costs for the quarter ended December 31, 2012 were higher than the prior-year quarter.

The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. Based upon the most recent evaluation, we anticipate contributing a total of between $30 million and $40 million to our defined benefit plans in fiscal 2013. Further, we will consider whether an additional voluntary contribution is prudent to maintain certain PPA funding thresholds. With respect to our postretirement medical plans, we anticipate contributing a total of between $25 million and $30 million to these plans during fiscal 2013.

The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans 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 plans and changes in the demographic composition of the participants in the plans.

OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our natural gas distribution, regulated transmission and storage and nonregulated segments for the three-month periods ended December 31, 2012 and 2011.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations


	Three Months Ended December 31
	2012		2011
METERS IN SERVICE, end of period
Residential		2,805,013		2,788,455
Commercial		256,030		253,846
Industrial		2,127		2,236
Public authority and other		10,169		10,215

Total meters		3,073,339		3,054,752

INVENTORY STORAGE BALANCE — Bcf⁽¹⁾		54.8		58.1
SALES VOLUMES — MMcf⁽²⁾
Gas sales volumes
Residential		46,323		49,469
Commercial		25,256		26,223
Industrial		4,555		5,057
Public authority and other		2,619		2,618

Total gas sales volumes		78,753		83,367
Transportation volumes		34,022		33,412

Total throughput		112,775		116,779

OPERATING REVENUES (000’s)⁽²⁾
Gas sales revenues
Residential	$	422,721	$	427,310
Commercial		184,931		186,079
Industrial		21,456		24,229
Public authority and other		15,680		17,373

Total gas sales revenues		644,788		654,991
Transportation revenues		15,441		14,292
Other gas revenues		6,558		6,830

Total operating revenues	$	666,787	$	676,113

Average transportation revenue per Mcf⁽¹⁾	$	0.46	$	0.44
Average cost of gas per Mcf sold⁽¹⁾	$	4.93	$	4.78

See footnote following these tables.

Natural Gas Distribution Sales and Statistical Data — Discontinued Operations


	Three Months Ended December 31
	2012		2011
Meters in service, end of period		63,959		148,256
Sales volumes — MMcf
Total gas sales volumes		1,542		3,952
Transportation volumes		515		2,152

Total throughput		2,057		6,104

Operating revenues (000’s)	$	16,284	$	40,630

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data


	Three Months Ended December 31
	2012		2011
CUSTOMERS, end of period
Industrial		732		771
Municipal		128		69
Other		423		516

Total		1,283		1,356

NONREGULATED INVENTORY STORAGE
BALANCE — Bcf		26.9		27.9
REGULATED TRANSMISSION AND STORAGE
VOLUMES — MMcf ⁽²⁾		161,484		160,829
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf⁽²⁾		99,009		106,462
OPERATING REVENUES (000’s) ⁽²⁾
Regulated transmission and storage	$	60,681	$	56,759
Nonregulated		399,894		444,176

Total operating revenues	$	460,575	$	500,935

Note to preceding tables:

(1)

Statistics are shown on a consolidated basis.

(2)

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

RECENT ACCOUNTING DEVELOPMENTS

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. During the three months ended December 31, 2012, 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, 2012 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, 2013 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, 2012, except as noted in Note 9 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 13 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2012. 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/ BRET J. ECKERT
		Bret J. Eckert Senior Vice President and Chief Financial Officer (Duly authorized signatory)

Date: February 7, 2013

EXHIBITS INDEX

Item 6


Exhibit Number	Description	Page Number or Incorporation by Reference to
12	Computation of ratio of earnings to fixed charges
15	Letter regarding unaudited interim financial information
31	Rule 13a-14(a)/15d-14(a) Certifications
32	Section 1350 Certifications*
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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