Atmos Energy - 10-Q quarterly report FY2014 Q3

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2014



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

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 August 1, 2014.



Class		Shares Outstanding
No Par Value		100,351,676

GLOSSARY OF KEY TERMS




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



	June 30, 2014		September 30, 2013
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	8,217,954	$	7,722,019
Less accumulated depreciation and amortization	1,756,504		1,691,364
Net property, plant and equipment	6,461,450		6,030,655
Current assets
Cash and cash equivalents	51,421		66,199
Accounts receivable, net	388,874		301,992
Gas stored underground	207,458		244,741
Other current assets	126,890		64,201
Total current assets	774,643		677,133
Goodwill	741,363		741,363
Deferred charges and other assets	379,733		485,117
	$	8,357,189	$	7,934,268
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2014 — 100,346,468 shares; September 30, 2013 — 90,640,211 shares	$	502	$	453
Additional paid-in capital	2,172,307		1,765,811
Retained earnings	932,576		775,267
Accumulated other comprehensive income	11,300		38,878
Shareholders’ equity	3,116,685		2,580,409
Long-term debt	1,955,907		2,455,671
Total capitalization	5,072,592		5,036,080
Current liabilities
Accounts payable and accrued liabilities	312,671		241,611
Other current liabilities	343,026		368,891
Short-term debt	—		367,984
Current maturities of long-term debt	500,000		—
Total current liabilities	1,155,697		978,486
Deferred income taxes	1,341,294		1,164,053
Regulatory cost of removal obligation	391,785		359,299
Pension and postretirement liabilities	347,344		358,787
Deferred credits and other liabilities	48,477		37,563
	$	8,357,189	$	7,934,268

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended June 30
	2014			2013
	(Unaudited) (In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	517,707		$	467,144
Regulated transmission and storage segment	87,189			74,041
Nonregulated segment	465,033			421,808
Intersegment eliminations	(127,211		)	(105,058		)
	942,718			857,935
Purchased gas cost
Natural gas distribution segment	260,042			227,649
Regulated transmission and storage segment	—			—
Nonregulated segment	450,220			418,548
Intersegment eliminations	(127,077		)	(104,759		)
	583,185			541,438
Gross profit	359,533			316,497
Operating expenses
Operation and maintenance	125,559			121,258
Depreciation and amortization	63,955			58,129
Taxes, other than income	63,414			50,714
Total operating expenses	252,928			230,101
Operating income	106,605			86,396
Miscellaneous expense	(374		)	(467		)
Interest charges	31,840			32,741
Income from continuing operations before income taxes	74,391			53,188
Income tax expense	28,670			19,714
Income from continuing operations	45,721			33,474
Gain on sale of discontinued operations, net of tax ($0 and $2,909)	—			5,294
Net income	$	45,721		$	38,768
Basic earnings per share
Income per share from continuing operations	$	0.45		$	0.37
Income per share from discontinued operations	—			0.06
Net income per share — basic	$	0.45		$	0.43
Diluted earnings per share
Income per share from continuing operations	$	0.45		$	0.36
Income per share from discontinued operations	—			0.06
Net income per share — diluted	$	0.45		$	0.42
Cash dividends per share	$	0.37		$	0.35
Weighted average shares outstanding:
Basic	100,267			90,603
Diluted	101,150			91,550

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME





	Nine Months Ended June 30
	2014			2013
	(Unaudited) (In thousands, except per share data)
Operating revenues
Natural gas distribution segment	$	2,652,532		$	2,039,107
Regulated transmission and storage segment	232,145			196,570
Nonregulated segment	1,670,437			1,250,650
Intersegment eliminations	(392,926		)	(285,241		)
	4,162,188			3,201,086
Purchased gas cost
Natural gas distribution segment	1,710,508			1,172,975
Regulated transmission and storage segment	—			—
Nonregulated segment	1,599,469			1,200,624
Intersegment eliminations	(392,556		)	(284,123		)
	2,917,421			2,089,476
Gross profit	1,244,767			1,111,610
Operating expenses
Operation and maintenance	365,991			338,871
Depreciation and amortization	185,731			174,888
Taxes, other than income	165,640			146,355
Total operating expenses	717,362			660,114
Operating income	527,405			451,496
Miscellaneous income (expense)	(4,022		)	1,943
Interest charges	95,556			96,594
Income from continuing operations before income taxes	427,827			356,845
Income tax expense	161,723			133,683
Income from continuing operations	266,104			223,162
Income from discontinued operations, net of tax ($0 and $3,986)	—			7,202
Gain on sale of discontinued operations, net of tax ($0 and $2,909)	—			5,294
Net income	$	266,104		$	235,658
Basic earnings per share
Income per share from continuing operations	$	2.78		$	2.46
Income per share from discontinued operations	—			0.14
Net income per share — basic	$	2.78		$	2.60
Diluted earnings per share
Income per share from continuing operations	$	2.76		$	2.43
Income per share from discontinued operations	—			0.14
Net income per share — diluted	$	2.76		$	2.57
Cash dividends per share	$	1.11		$	1.05
Weighted average shares outstanding:
Basic	95,455			90,497
Diluted	96,339			91,445

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended June 30						Nine Months Ended June 30
	2014			2013			2014			2013
	(Unaudited) (In thousands)
Net income	$	45,721		$	38,768		$	266,104		$	235,658
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $216, $(202), $1,518 and $(532)	377			(348		)	2,519			(921		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(13,472), $17,865, $(21,005) and $38,427	(23,440		)	31,079			(36,545		)	66,852
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(1,580), $(2,243), $4,122 and $3,174	(2,471		)	(3,508		)	6,448			4,965
Total other comprehensive income (loss)	(25,534		)	27,223			(27,578		)	70,896
Total comprehensive income	$	20,187		$	65,991		$	238,526		$	306,554

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended June 30
	2014			2013
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	266,104		$	235,658
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of discontinued operations	—			(8,203		)
Depreciation and amortization:
Charged to depreciation and amortization	185,731			176,737
Charged to other accounts	669			446
Deferred income taxes	150,457			130,365
Other	21,587			14,460
Net assets / liabilities from risk management activities	3,158			(6,386		)
Net change in operating assets and liabilities	2,504			(33,502		)
Net cash provided by operating activities	630,210			509,575
Cash Flows From Investing Activities
Capital expenditures	(552,600		)	(582,473		)
Proceeds from the sale of discontinued operations	—			153,023
Other, net	(620		)	(3,139		)
Net cash used in investing activities	(553,220		)	(432,589		)
Cash Flows From Financing Activities
Net decrease in short-term debt	(366,602		)	(435,084		)
Net proceeds from equity offering	390,205			—
Net proceeds from issuance of long-term debt	—			493,793
Settlement of Treasury lock agreements	—			(66,626		)
Repayment of long-term debt	—			(131		)
Cash dividends paid	(108,806		)	(96,060		)
Repurchase of equity awards	(8,717		)	(5,146		)
Issuance of common stock	2,152			8
Net cash used in financing activities	(91,768		)	(109,246		)
Net decrease in cash and cash equivalents	(14,778		)	(32,260		)
Cash and cash equivalents at beginning of period	66,199			64,239
Cash and cash equivalents at end of period	$	51,421		$	31,979

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2014

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and transmission and storage businesses as well as certain other nonregulated businesses. For the fiscal year ended September 30, 2013, our regulated businesses generated approximately 95 percent of our consolidated net income.

Through our natural gas distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated natural gas distribution divisions, which at June 30, 2014, covered service areas located in eight states. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers. In addition, we transport natural gas for others through our distribution system. Our regulated businesses also include our regulated pipeline and storage operations, which include the transportation of natural gas to our North Texas 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.

2. Unaudited Financial Information

These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. 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, 2013. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2014 are not indicative of our results of operations for the full 2014 fiscal year, which ends September 30, 2014.

Except for the forward starting interest rate swap entered into in July 2014 as noted in Note 8, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

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, 2013.

During the second quarter of fiscal 2014, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

Due to the April 1, 2013 sale of our Georgia distribution operations, prior year financial results for this service area are shown in discontinued operations.

Disclosure requirements for offsetting arrangements for financial instruments became effective for us beginning on October 1, 2013. We have presented these disclosures in Note 8. In connection with the adoption of this standard, prior-year risk management assets and liabilities have been reclassified to conform with the current-year presentation. The adoption of this standard and reclassification did not have an impact on our financial position, results of operations or cash flows.

In April 2014, the Financial Accounting Standards Board (FASB) issued updated guidance for discontinued operations that limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have a major effect on an entity’s operations and financial results and requires additional disclosures related to discontinued operations. This standard will become effective for us beginning on October 1, 2015. The adoption of this guidance is not expected to impact our financial position, results of operations or cash flows.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. The new standard will become effective for us beginning on October 1, 2017 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

There were no other significant changes to our accounting policies during the nine months ended June 30, 2014 that will become applicable to the Company in future periods.

Regulatory assets and liabilities

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

Significant regulatory assets and liabilities as of June 30, 2014 and September 30, 2013 included the following:



	June 30, 2014		September 30, 2013
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	172,844	$	187,977
Merger and integration costs, net	4,860		5,250
Deferred gas costs	9,809		15,152
Regulatory cost of removal asset	9,552		10,008
Rate case costs	4,436		6,329
Texas Rule 8.209⁽²⁾	19,349		30,364
APT annual adjustment mechanism	5,927		5,853
Recoverable loss on reacquired debt	19,517		21,435
Other	4,006		4,380
	$	250,300	$	286,748
Regulatory liabilities:
Deferred gas costs	$	62,522	$	16,481
Deferred franchise fees	5,918		1,689
Regulatory cost of removal obligation	441,643		427,524
Other	11,509		7,887
	$	521,592	$	453,581


⁽¹⁾	Includes $18.0 million and $17.4 million of pension and postretirement expense deferred pursuant to regulatory authorization.


⁽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.

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.

3. Segment Information

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, 2013. We evaluate performance based on net income or loss of the respective operating units.

Income statements for the three and nine month periods ended June 30, 2014 and 2013 by segment are presented in the following tables:



	Three Months Ended June 30, 2014
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	516,644	$	24,990		$	401,084	$	—		$	942,718
Intersegment revenues	1,063		62,199			63,949		(127,211		)	—
	517,707		87,189			465,033		(127,211		)	942,718
Purchased gas cost	260,042		—			450,220		(127,077		)	583,185
Gross profit	257,665		87,189			14,813		(134		)	359,533
Operating expenses
Operation and maintenance	92,994		23,570			9,129		(134		)	125,559
Depreciation and amortization	52,542		10,281			1,132		—			63,955
Taxes, other than income	57,596		5,054			764		—			63,414
Total operating expenses	203,132		38,905			11,025		(134		)	252,928
Operating income	54,533		48,284			3,788		—			106,605
Miscellaneous income (expense)	678		(489		)	1,018		(1,581		)	(374		)
Interest charges	23,649		9,162			610		(1,581		)	31,840
Income before income taxes	31,562		38,633			4,196		—			74,391
Income tax expense	13,033		13,695			1,942		—			28,670
Net income	$	18,529	$	24,938		$	2,254	$	—		$	45,721
Capital expenditures	$	146,860	$	45,658		$	1,073	$	—		$	193,591



	Three Months Ended June 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	465,982	$	26,730		$	365,223		$	—		$	857,935
Intersegment revenues	1,162		47,311			56,585			(105,058		)	—
	467,144		74,041			421,808			(105,058		)	857,935
Purchased gas cost	227,649		—			418,548			(104,759		)	541,438
Gross profit	239,495		74,041			3,260			(299		)	316,497
Operating expenses
Operation and maintenance	93,490		17,035			11,034			(301		)	121,258
Depreciation and amortization	48,368		8,676			1,085			—			58,129
Taxes, other than income	45,686		4,287			741			—			50,714
Total operating expenses	187,544		29,998			12,860			(301		)	230,101
Operating income (loss)	51,951		44,043			(9,600		)	2			86,396
Miscellaneous income (expense)	268		(247		)	215			(703		)	(467		)
Interest charges	25,001		8,049			392			(701		)	32,741
Income (loss) from continuing operations before income taxes	27,218		35,747			(9,777		)	—			53,188
Income tax expense (benefit)	11,401		12,650			(4,337		)	—			19,714
Income (loss) from continuing operations	15,817		23,097			(5,440		)	—			33,474
Gain (loss) on sale of discontinued operations, net of tax	5,649		—			(355		)	—			5,294
Net income (loss)	$	21,466	$	23,097		$	(5,795	)	$	—		$	38,768
Capital expenditures	$	114,606	$	78,012		$	738		$	—		$	193,356





	Nine Months Ended June 30, 2014
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,648,505	$	67,162		$	1,446,521	$	—		$	4,162,188
Intersegment revenues	4,027		164,983			223,916		(392,926		)	—
	2,652,532		232,145			1,670,437		(392,926		)	4,162,188
Purchased gas cost	1,710,508		—			1,599,469		(392,556		)	2,917,421
Gross profit	942,024		232,145			70,968		(370		)	1,244,767
Operating expenses
Operation and maintenance	289,433		57,465			19,463		(370		)	365,991
Depreciation and amortization	152,113		30,223			3,395		—			185,731
Taxes, other than income	155,286		8,485			1,869		—			165,640
Total operating expenses	596,832		96,173			24,727		(370		)	717,362
Operating income	345,192		135,972			46,241		—			527,405
Miscellaneous income (expense)	304		(2,751		)	1,785		(3,360		)	(4,022		)
Interest charges	69,802		27,274			1,840		(3,360		)	95,556
Income from before income taxes	275,694		105,947			46,186		—			427,827
Income tax expense	105,665		37,454			18,604		—			161,723
Net income	$	170,029	$	68,493		$	27,582	$	—		$	266,104
Capital expenditures	$	413,921	$	137,579		$	1,100	$	—		$	552,600





	Nine Months Ended June 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,035,712	$	65,084		$	1,100,290		$	—		$	3,201,086
Intersegment revenues	3,395		131,486			150,360			(285,241		)	—
	2,039,107		196,570			1,250,650			(285,241		)	3,201,086
Purchased gas cost	1,172,975		—			1,200,624			(284,123		)	2,089,476
Gross profit	866,132		196,570			50,026			(1,118		)	1,111,610
Operating expenses
Operation and maintenance	266,570		48,745			24,679			(1,123		)	338,871
Depreciation and amortization	146,059		25,756			3,073			—			174,888
Taxes, other than income	132,029		12,513			1,813			—			146,355
Total operating expenses	544,658		87,014			29,565			(1,123		)	660,114
Operating income	321,474		109,556			20,461			5			451,496
Miscellaneous income (expense)	2,728		(473		)	1,791			(2,103		)	1,943
Interest charges	74,228		22,777			1,687			(2,098		)	96,594
Income from continuing operations before income taxes	249,974		86,306			20,565			—			356,845
Income tax expense	94,874		30,574			8,235			—			133,683
Income from continuing operations	155,100		55,732			12,330			—			223,162
Income from discontinued operations, net of tax	7,202		—			—			—			7,202
Gain (loss) on sale of discontinued operations, net of tax	5,649		—			(355		)	—			5,294
Net income	$	167,951	$	55,732		$	11,975		$	—		$	235,658
Capital expenditures	$	391,942	$	189,051		$	1,480		$	—		$	582,473

Balance sheet information at June 30, 2014 and September 30, 2013 by segment is presented in the following tables:



	June 30, 2014
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,036,007	$	1,366,928	$	58,515		$	—		$	6,461,450
Investment in subsidiaries	933,660		—		(2,096		)	(931,564		)	—
Current assets
Cash and cash equivalents	17,042		—		34,379			—			51,421
Assets from risk management activities	36,438		—		7,918			—			44,356
Other current assets	461,644		15,813		581,221			(379,812		)	678,866
Intercompany receivables	775,175		—		—			(775,175		)	—
Total current assets	1,290,299		15,813		623,518			(1,154,987		)	774,643
Goodwill	574,190		132,462		34,711			—			741,363
Noncurrent assets from risk management activities	20,708		—		5,109			—			25,817
Deferred charges and other assets	325,035		22,474		6,407			—			353,916
	$	8,179,899	$	1,537,677	$	726,164		$	(2,086,551	)	$	8,357,189
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,116,685	$	464,914	$	468,746		$	(933,660	)	$	3,116,685
Long-term debt	1,955,907		—		—			—			1,955,907
Total capitalization	5,072,592		464,914		468,746			(933,660		)	5,072,592
Current liabilities
Current maturities of long-term debt	500,000		—		—			—			500,000
Short-term debt	357,000		—		—			(357,000		)	—
Liabilities from risk management activities	609		—		—			—			609
Other current liabilities	477,726		14,837		183,241			(20,716		)	655,088
Intercompany payables	—		717,134		58,041			(775,175		)	—
Total current liabilities	1,335,335		731,971		241,282			(1,152,891		)	1,155,697
Deferred income taxes	988,737		338,350		14,207			—			1,341,294
Noncurrent liabilities from risk management activities	7,024		—		—			—			7,024
Regulatory cost of removal obligation	391,785		—		—			—			391,785
Pension and postretirement liabilities	347,344		—		—			—			347,344
Deferred credits and other liabilities	37,082		2,442		1,929			—			41,453
	$	8,179,899	$	1,537,677	$	726,164		$	(2,086,551	)	$	8,357,189



	September 30, 2013
	Natural Gas Distribution		Regulated Transmission and Storage		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	4,719,873	$	1,249,767	$	61,015		$	—		$	6,030,655
Investment in subsidiaries	831,136		—		(2,096		)	(829,040		)	—
Current assets
Cash and cash equivalents	4,237		—		61,962			—			66,199
Assets from risk management activities	1,837		—		10,129			—			11,966
Other current assets	428,366		11,709		452,126			(293,233		)	598,968
Intercompany receivables	783,738		—		—			(783,738		)	—
Total current assets	1,218,178		11,709		524,217			(1,076,971		)	677,133
Goodwill	574,190		132,462		34,711			—			741,363
Noncurrent assets from risk management activities	109,354		—		—			—			109,354
Deferred charges and other assets	347,687		19,227		8,849			—			375,763
	$	7,800,418	$	1,413,165	$	626,696		$	(1,906,011	)	$	7,934,268
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	2,580,409	$	396,421	$	434,715		$	(831,136	)	$	2,580,409
Long-term debt	2,455,671		—		—			—			2,455,671
Total capitalization	5,036,080		396,421		434,715			(831,136		)	5,036,080
Current liabilities
Current maturities of long-term debt	—		—		—			—			—
Short-term debt	645,984		—		—			(278,000		)	367,984
Liabilities from risk management activities	1,543		—		—			—			1,543
Other current liabilities	491,681		20,288		110,306			(13,316		)	608,959
Intercompany payables	—		712,768		70,970			(783,738		)	—
Total current liabilities	1,139,208		733,056		181,276			(1,075,054		)	978,486
Deferred income taxes	871,360		283,554		8,960			179			1,164,053
Regulatory cost of removal obligation	359,299		—		—			—			359,299
Pension and postretirement liabilities	358,787		—		—			—			358,787
Deferred credits and other liabilities	35,684		134		1,745			—			37,563
	$	7,800,418	$	1,413,165	$	626,696		$	(1,906,011	)	$	7,934,268

4. Earnings Per Share

We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. 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 and nine months ended June 30, 2014 and 2013 are calculated as follows:



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
Income from continuing operations	$	45,721	$	33,474	$	266,104	$	223,162
Less: Income from continuing operations allocated to participating securities	107		91		674		760
Income from continuing operations available to common shareholders	$	45,614	$	33,383	$	265,430	$	222,402
Basic weighted average shares outstanding	100,267		90,603		95,455		90,497
Income from continuing operations per share — Basic	$	0.45	$	0.37	$	2.78	$	2.46

Basic Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	5,294	$	—	$	12,496
Less: Income from discontinued operations allocated to participating securities	—		14		—		43
Income from discontinued operations available to common shareholders	$	—	$	5,280	$	—	$	12,453
Basic weighted average shares outstanding	100,267		90,603		95,455		90,497
Income from discontinued operations per share — Basic	$	—	$	0.06	$	—	$	0.14
Net income per share — Basic	$	0.45	$	0.43	$	2.78	$	2.60



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
	(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
Income from continuing operations available to common shareholders	$	45,614	$	33,383	$	265,430	$	222,402
Effect of dilutive stock options and other shares	—		—		4		5
Income from continuing operations available to common shareholders	$	45,614	$	33,383	$	265,434	$	222,407
Basic weighted average shares outstanding	100,267		90,603		95,455		90,497
Additional dilutive stock options and other shares	883		947		884		948
Diluted weighted average shares outstanding	101,150		91,550		96,339		91,445
Income from continuing operations per share — Diluted	$	0.45	$	0.36	$	2.76	$	2.43

Diluted Earnings Per Share from discontinued operations
Income from discontinued operations available to common shareholders	$	—	$	5,280	$	—	$	12,453
Effect of dilutive stock options and other shares	—		—		—		—
Income from discontinued operations available to common shareholders	$	—	$	5,280	$	—	$	12,453
Basic weighted average shares outstanding	100,267		90,603		95,455		90,497
Additional dilutive stock options and other shares	883		947		884		948
Diluted weighted average shares outstanding	101,150		91,550		96,339		91,445
Income from discontinued operations per share — Diluted	$	—	$	0.06	$	—	$	0.14
Net income per share — Diluted	$	0.45	$	0.42	$	2.76	$	2.57

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2014 and 2013 as their exercise price was less than the average market price of the common stock during those periods.

2014 Equity Offering

On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 1,200,000 shares under our existing shelf registration statement. The offering was priced at $44.00 and generated net proceeds of $390.2 million, which were used to repay short-term debt outstanding under our $950 million commercial paper program, to fund infrastructure spending primarily to enhance the safety and reliability of our system and for general corporate purposes.

2011 Share Repurchase Program

We did not repurchase any shares during the nine months ended June 30, 2014 and 2013 under our 2011 share repurchase program.

5. Debt

The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. Except as noted below, there were no material changes in the terms of our debt instruments during the nine months ended June 30, 2014.

Long-term debt

Long-term debt at June 30, 2014 and September 30, 2013 consisted of the following:



	June 30, 2014		September 30, 2013
	(In thousands)
Unsecured 4.95% Senior Notes, due October 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
Unsecured 4.15% Senior Notes, due 2043	500,000		500,000
Medium-term note Series A, 1995-1, 6.67%, due 2025	10,000		10,000
Unsecured 6.75% Debentures, due 2028	150,000		150,000
Total long-term debt	2,460,000		2,460,000
Less:
Original issue discount on unsecured senior notes and debentures	4,093		4,329
Current maturities	500,000		—
	$	1,955,907	$	2,455,671

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 primarily 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 $950 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1 billion of working capital funding. At June 30, 2014, there were no short-term debt borrowings outstanding. At September 30, 2013, there was a total of $368.0 million outstanding under our commercial paper program.

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 $985 million of working capital funding, including a five-year $950 million unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.2 billion, a $25 million unsecured facility and a $10 million unsecured 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 $10 million revolving credit facility was $4.1 million at June 30, 2014.

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 rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2014.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, had two $25 million 364-day bilateral credit facilities that expired in December 2013. In December 2013, the $25 million 364-day uncommitted bilateral facility was extended to December 2014. In January 2014, this facility was amended to temporarily increase the amount available to $50 million to address the increase in volumes and prices driven by colder than normal weather this past winter-heating season. In June 2014, the facility was further amended to extend the temporary increase for 90 days through September 28, 2014. The maximum available under the facility will return to $25 million after the additional 90-day period expires. The $25 million committed bilateral facility was replaced with a $15 million committed 364-day bilateral credit facility in December 2013. These facilities are 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 $52.3 million at June 30, 2014.

AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to 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, 2014.

Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013 that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, which generated net proceeds of $390.2 million. As of June 30, 2014, $1.35 billion of securities remained available for issuance under the shelf registration statement until March 28, 2016.

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 June 30, 2014, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 46 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.

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

Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of 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 June 30, 2014. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

6. Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and nine months ended June 30, 2014 and 2013 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. On October 2, 2013, due to the retirement of one of our executive officers, we recognized a settlement loss of $4.5 million associated with our Supplemental Executive Benefits Plan (SEBP). In association with his retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP. On April 1, 2013, due to the retirement of certain executives, we recognized a curtailment loss of $3.2 million associated with our SEBP and revalued the net periodic pension cost for the remainder of fiscal 2013. The revaluation of the net periodic pension cost resulted in an increase in the discount rate, effective April 1, 2013, to 4.21 percent, which reduced our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year. All other actuarial assumptions remained the same.



	Three Months Ended June 30
	Pension Benefits						Other Benefits
	2014			2013			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,738		$	5,194		$	4,196		$	4,700
Interest cost	6,824			6,019			3,987			3,241
Expected return on assets	(5,901		)	(5,739		)	(1,291		)	(997		)
Amortization of transition obligation	—			—			69			271
Amortization of prior service credit	(34		)	(35		)	(363		)	(363		)
Amortization of actuarial loss	3,931			5,432			158			1,049
Settlement loss	—			3,161			—			—
Net periodic pension cost	$	9,558		$	14,032		$	6,756		$	7,901




	Nine Months Ended June 30
	Pension Benefits						Other Benefits
	2014			2013			2014			2013
	(In thousands)
Components of net periodic pension cost:
Service cost	$	14,214		$	15,599		$	12,588		$	14,100
Interest cost	20,472			18,067			11,963			9,723
Expected return on assets	(17,702		)	(17,216		)	(3,875		)	(2,991		)
Amortization of transition obligation	—			—			205			811
Amortization of prior service credit	(102		)	(106		)	(1,088		)	(1,088		)
Amortization of actuarial loss	11,793			16,555			474			3,147
Settlement loss	4,539			3,161			—			—
Net periodic pension cost	$	33,214		$	36,060		$	20,267		$	23,702

The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2014 and 2013 are as follows:



	Supplemental Executive Benefit Plans				Pension Benefits				Other Benefits
	2014		2013		2014		2013		2014		2013
Discount rate	4.95	%	4.21	%	4.95	%	4.04	%	4.95	%	4.04	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	3.50	%	N/A		N/A
Expected return on plan assets	N/A		N/A		7.25	%	7.75	%	4.60	%	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. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2014. During the first nine months of fiscal 2014, we contributed $27.1 million to our defined benefit plans and we do not anticipate making any contributions during the fourth quarter of fiscal 2014.

We contributed $18.1 million to our other post-retirement benefit plans during the nine months ended June 30, 2014. We expect to contribute a total of approximately $20 million to $25 million to these plans during all of fiscal 2014.

7. Commitments and Contingencies

Litigation and Environmental Matters

With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 10 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2014.

Kentucky Litigation

Beginning in April 2009, Atmos Energy and two subsidiaries of AEH, AEM and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), were 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, appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court of Appeals 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 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 plus accrued interest to one landowner on that claim. The claim was paid on February 18, 2013. 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 investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, then each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed responses to the motions. The Kentucky Supreme Court denied the motions for discretionary review on February 12, 2014 and the decision of the Court of Appeals became final on February 21, 2014. We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter. This accrual was reversed during the second fiscal quarter of fiscal 2014 as the appellate process in this case had been completed. Atmos Energy had also filed a motion with the trial court, the Circuit Court of Edmonson County, Kentucky, on March 10, 2014, seeking a ruling that the remaining landowner was not entitled to any punitive damages on the sole remaining claim of trespass. On May 19, 2014, the Edmonson County Circuit Court entered judgment dismissing any claim for punitive damages relating to the trespass claim. There was no appeal of this judgment. The lawsuit in Edmonson County has now been fully and finally resolved.

In addition, in a related matter, 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 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 AGC 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. Atmos Energy filed a motion for partial summary judgment against the defendants with the District Court on July 15, 2014, with a ruling by the Court still pending. This case is scheduled for trial beginning October 6, 2014.

Tennessee Business License Tax

Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. The cumulative assessment approximated $12 million as of March 31, 2014, which AEM challenged. We had previously accrued in prior years what we believed to be an adequate amount for the anticipated resolution of this matter. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. An agreed order of dismissal with prejudice between AEM and TDOR was approved by the Chancery Court and entered on May 2, 2014, whereby AEM agreed to pay $6.2 million to TDOR to resolve all business tax-related liabilities outstanding through September 2014. The State of Tennessee also passed related legislation, effective July 1, 2014, that should help minimize any disputes over this type of sales business tax in the future.

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 June 30, 2014, AEH was committed to purchase 105.2 Bcf within one year, 18.0 Bcf within one to three years and 0.6 Bcf after three years under indexed contracts. AEH is committed to purchase 10.0 Bcf within one year under fixed price contracts with prices ranging from $3.66 to $6.36 per Mcf. Purchases under these contracts totaled $383.2 million and $340.9 million for the three months ended June 30, 2014 and 2013 and $1,354.5 million and $958.2 million for the nine months ended June 30, 2014 and 2013.

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

Our Mid-Tex Division maintains long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. The estimated commitments under these contracts as of June 30, 2014 are as follows (in thousands):



2014	$	51,946
2015	234,824
2016	167,747
2017	67,185
Thereafter	—
	$	521,702

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, 2013. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2014.

Regulatory Matters

Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations. Additional rulemakings are

pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.

As of June 30, 2014, rate cases were in progress in our Kansas, Colorado and Virginia service areas, annual rate filing mechanisms were in progress in Louisiana and Mid-Tex and an infrastructure program filing was in progress in Virginia. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.

8. 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, 2013. During the nine months ended June 30, 2014 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 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 2013-2014 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 32 percent, or 24.6 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

The costs associated with the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.

Nonregulated Commodity Risk Management Activities

Our 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 46 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 periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

As of June 30, 2014, we had forward starting interest rate swaps to effectively 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, at 3.129% and 3.37%, which we designated as cash flow hedges at the time the agreements were executed. In April, May and July 2014, we entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with $325 million of the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.91%, 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 are being 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 is 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 June 30, 2014, the remaining amortization periods for the settled Treasury locks extended through fiscal 2043.

Quantitative Disclosures Related to Financial Instruments

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

As of June 30, 2014, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of June 30, 2014, 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	—	(9,255	)
	Cash Flow	—	29,930
	Not designated	20,826	63,168
		20,826	83,843

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of June 30, 2014 and September 30, 2013. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties.



		Natural Gas Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
June 30, 2014
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	8,442		$	(3,741	)
Interest rate contracts	Other current assets / Other current liabilities	33,183		—			—			—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			730			(1,421		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	20,455		(6,849		)	—			—
Total		53,638		(6,849		)	9,172			(5,162		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	3,255		(609		)	45,242			(51,715		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	253		(175		)	20,476			(14,675		)
Total		3,508		(784		)	65,718			(66,390		)
Gross Financial Instruments		57,146		(7,633		)	74,890			(71,552		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(69,782		)	69,782
Net Financial Instruments		57,146		(7,633		)	5,108			(1,770		)
Cash collateral		—		—			7,919			1,770
Net Assets/Liabilities from Risk Management Activities		$	57,146	$	(7,633	)	$	13,027		$	—



		Natural Gas Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
September 30, 2013
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	9,094		$	(12,173	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			416			(1,639		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	107,512		—			—			—
Total		107,512		—			9,510			(13,812		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	1,837		(1,543		)	65,388			(70,876		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	1,842		—			40,982			(45,892		)
Total		3,679		(1,543		)	106,370			(116,768		)
Gross Financial Instruments		111,191		(1,543		)	115,880			(130,580		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(115,875		)	115,875
Net Financial Instruments		111,191		(1,543		)	5			(14,705		)
Cash collateral		—		—			10,124			14,705
Net Assets/Liabilities from Risk Management Activities		$	111,191	$	(1,543	)	$	10,129		$	—

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 June 30, 2014 and 2013 we recognized a loss arising from fair value and cash flow hedge ineffectiveness of $0.1 million and $0.4 million. For the nine months ended June 30, 2014 and 2013, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $1.3 million and $17.3 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

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 and nine months ended June 30, 2014 and 2013 is presented below.



	Three Months Ended June 30
	2014			2013
	(In thousands)
Commodity contracts	$	1,991		$	14,453
Fair value adjustment for natural gas inventory designated as the hedged item	(2,258		)	(15,143		)
Total increase in purchased gas cost	$	(267	)	$	(690	)
The (increase) decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	817		$	(2,361	)
Timing ineffectiveness	(1,084		)	1,671
	$	(267	)	$	(690	)




	Nine Months Ended June 30
	2014			2013
	(In thousands)
Commodity contracts	$	(2,983	)	$	3,921
Fair value adjustment for natural gas inventory designated as the hedged item	4,071			13,261
Total decrease in purchased gas cost	$	1,088		$	17,182
The (increase) decrease in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(382	)	$	(1,143	)
Timing ineffectiveness	1,470			18,325
	$	1,088		$	17,182

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.

Cash Flow Hedges

The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2014 and 2013 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 June 30, 2014
	Natural Gas Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	4,209	$	4,209
Gain arising from ineffective portion of commodity contracts	—			179		179
Total impact on purchased gas cost	—			4,388		4,388
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(1,057		)	—		(1,057		)
Total Impact from Cash Flow Hedges	$	(1,057	)	$	4,388	$	3,331



	Three Months Ended June 30, 2013
	Natural Gas Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	558	$	558
Gain arising from ineffective portion of commodity contracts	—			260		260
Total impact on purchased gas cost	—			818		818
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(1,057		)	—		(1,057		)
Total Impact from Cash Flow Hedges	$	(1,057	)	$	818	$	(239	)





	Nine Months Ended June 30, 2014
	Natural Gas Distribution			Nonregulated		Consolidated
	(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts	$	—		$	8,783	$	8,783
Gain arising from ineffective portion of commodity contracts	—			203		203
Total impact on purchased gas cost	—			8,986		8,986
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(3,172		)	—		(3,172		)
Total Impact from Cash Flow Hedges	$	(3,172	)	$	8,986	$	5,814





	Nine Months Ended June 30, 2013
	Natural Gas Distribution			Nonregulated			Consolidated
	(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts	$	—		$	(9,802	)	$	(9,802	)
Gain arising from ineffective portion of commodity contracts	—			158			158
Total impact on purchased gas cost	—			(9,644		)	(9,644		)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense	(2,432		)	—			(2,432		)
Total Impact from Cash Flow Hedges	$	(2,432	)	$	(9,644	)	$	(12,076	)

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2014 and 2013. 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 June 30						Nine Months Ended June 30
	2014			2013			2014			2013
	(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(24,111	)	$	30,408		$	(38,559	)	$	65,308
Forward commodity contracts	96			(3,168		)	11,805			(1,015		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	671			671			2,014			1,544
Forward commodity contracts	(2,567		)	(340		)	(5,357		)	5,980
Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	(25,911	)	$	27,571		$	(30,097	)	$	71,817


⁽¹⁾	Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

Deferred gains (losses) recorded in accumulated other comprehensive income (AOCI) associated with our interest rate 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 June 30, 2014. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.



	Interest Rate Agreements			Commodity Contracts			Total
	(In thousands)
Next twelve months	$	(1,317	)	$	2,407		$	1,090
Thereafter	(27,033		)	(435		)	(27,468		)
Total⁽¹⁾	$	(28,350	)	$	1,972		$	(26,378	)


⁽¹⁾	Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

Financial Instruments Not Designated as Hedges

The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2014 and 2013 was a decrease in gross profit of $0.6 million and $8.4 million. For the nine months ended June 30, 2014 and 2013 gross profit decreased by $10.7 million and $1.7 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 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.

9. Accumulated Other Comprehensive Income

We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.



	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2013	$	5,448		$	37,906		$	(4,476	)	$	38,878
Other comprehensive income (loss) before reclassifications	3,212			(38,559		)	11,805			(23,542		)
Amounts reclassified from accumulated other comprehensive income	(693		)	2,014			(5,357		)	(4,036		)
Net current-period other comprehensive income (loss)	2,519			(36,545		)	6,448			(27,578		)
June 30, 2014	$	7,967		$	1,361		$	1,972		$	11,300



	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2012	$	5,661		$	(44,273	)	$	(8,995	)	$	(47,607	)
Other comprehensive income (loss) before reclassifications	449			65,308			(1,015		)	64,742
Amounts reclassified from accumulated other comprehensive income	(1,370		)	1,544			5,980			6,154
Net current-period other comprehensive income (loss)	(921		)	66,852			4,965			70,896
June 30, 2013	$	4,740		$	22,579		$	(4,030	)	$	23,289

The following tables detail reclassifications out of AOCI for the three and nine months ended June 30, 2014 and 2013. Amounts in parentheses below indicate decreases to net income in the statement of income.



	Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	733		Operation and maintenance expense
	733			Total before tax
	(267		)	Tax expense
	$	466		Net of tax
Cash flow hedges
Interest rate agreements	$	(1,057	)	Interest charges
Commodity contracts	4,209			Purchased gas cost
	3,152			Total before tax
	(1,256		)	Tax expense
	$	1,896		Net of tax
Total reclassifications	$	2,362		Net of tax



	Three Months Ended June 30, 2013
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	(531	)	Operation and maintenance expense
	(531		)	Total before tax
	193			Tax benefit
	$	(338	)	Net of tax
Cash flow hedges
Interest rate agreements	$	(1,057	)	Interest charges
Commodity contracts	558			Purchased gas cost
	(499		)	Total before tax
	168			Tax benefit
	$	(331	)	Net of tax
Total reclassifications	$	(669	)	Net of tax





	Nine Months Ended June 30, 2014
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	1,091		Operation and maintenance expense
	1,091			Total before tax
	(398		)	Tax expense
	$	693		Net of tax
Cash flow hedges
Interest rate agreements	$	(3,172	)	Interest charges
Commodity contracts	8,783			Purchased gas cost
	5,611			Total before tax
	(2,268		)	Tax expense
	$	3,343		Net of tax
Total reclassifications	$	4,036		Net of tax





	Nine Months Ended June 30, 2013
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)
Available-for-sale securities	$	2,158		Operation and maintenance expense
	2,158			Total before tax
	(788		)	Tax expense
	$	1,370		Net of tax
Cash flow hedges
Interest rate agreements	$	(2,432	)	Interest charges
Commodity contracts	(9,803		)	Purchased gas cost
	(12,235		)	Total before tax
	4,711			Tax benefit
	$	(7,524	)	Net of tax
Total reclassifications	$	(6,154	)	Net of tax

10. 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, 2013. During the nine months ended June 30, 2014, there were no changes in these methods.

Fair value measurements also apply to the valuation of our pension and postretirement 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 6 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2013.

Quantitative Disclosures

Financial Instruments

The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and September 30, 2013. 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⁾			June 30, 2014
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	57,146	$	—	$	—		$	57,146
Nonregulated segment	3		74,887		—		(61,863		)	13,027
Total financial instruments	3		132,033		—		(61,863		)	70,173
Hedged portion of gas stored underground	39,191		—		—		—			39,191
Available-for-sale securities
Money market funds	—		1,959		—		—			1,959
Registered investment companies	45,554		—		—		—			45,554
Bonds	—		33,397		—		—			33,397
Total available-for-sale securities	45,554		35,356		—		—			80,910
Total assets	$	84,748	$	167,389	$	—	$	(61,863	)	$	190,274
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	7,633	$	—	$	—		$	7,633
Nonregulated segment	108		71,444		—		(71,552		)	—
Total liabilities	$	108	$	79,077	$	—	$	(71,552	)	$	7,633



	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, 2013
	(In thousands)
Assets:
Financial instruments
Natural gas distribution segment	$	—	$	111,191	$	—	$	—		$	111,191
Nonregulated segment	745		115,135		—		(105,751		)	10,129
Total financial instruments	745		226,326		—		(105,751		)	121,320
Hedged portion of gas stored underground	44,758		—		—		—			44,758
Available-for-sale securities
Money market funds	—		4,428		—		—			4,428
Registered investment companies	40,094		—		—		—			40,094
Bonds	—		28,160		—		—			28,160
Total available-for-sale securities	40,094		32,588		—		—			72,682
Total assets	$	85,597	$	258,914	$	—	$	(105,751	)	$	238,760
Liabilities:
Financial instruments
Natural gas distribution segment	$	—	$	1,543	$	—	$	—		$	1,543
Nonregulated segment	158		130,422		—		(130,580		)	—
Total liabilities	$	158	$	131,965	$	—	$	(130,580	)	$	1,543

⁽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 June 30, 2014, we had $9.7 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $1.8 million was used to offset current risk management liabilities under master netting arrangements and the remaining $7.9 million 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, 2013 we had $24.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $14.7 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $10.1 million is classified as current risk management assets.

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



	Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)
As of June 30, 2014
Domestic equity mutual funds	$	27,983	$	10,274	$	—		$	38,257
Foreign equity mutual funds	5,092		2,205		—			7,297
Bonds	33,180		220		(3		)	33,397
Money market funds	1,959		—		—			1,959
	$	68,214	$	12,699	$	(3	)	$	80,910
As of September 30, 2013
Domestic equity mutual funds	$	27,043	$	7,476	$	(23	)	$	34,496
Foreign equity mutual funds	4,536		1,062		—			5,598
Bonds	28,016		168		(24		)	28,160
Money market funds	4,428		—		—			4,428
	$	64,023	$	8,706	$	(47	)	$	72,682

At June 30, 2014 and September 30, 2013, our available-for-sale securities included $47.5 million and $44.5 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2014, we maintained investments in bonds that have contractual maturity dates ranging from July 2014 through December 2019. During the nine months ended June 30, 2014 and 2013, we recognized gains of $1.1 million and $2.2 million on the sale of certain assets in the rabbi trusts.

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 June 30, 2014 and September 30, 2013:



	June 30, 2014		September 30, 2013
	(In thousands)
Carrying Amount	$	2,460,000	$	2,460,000
Fair Value	$	2,795,188	$	2,676,487

11. 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, 2013. During the nine months ended June 30, 2014, there were no material changes in our concentration of credit risk.

12. Discontinued Operations

On April 1, 2013, we completed the sale of substantially all of our natural gas distribution assets and certain related nonregulated assets located in Georgia to Liberty Energy (Georgia) Corp., an affiliate of Algonquin Power & Utilities Corp. for a cash price of approximately $153 million. In connection with the sale, we recognized a net of tax gain of $5.3 million.

For the three months ended June 30, 2013, net income from discontinued operations includes the aforementioned gain on sale, while for the nine months ended June 30, 2013, net income from discontinued operations includes the operating results of our Georgia operations and the gain on sale. As required under generally accepted accounting principles, the operating results from our discontinued Georgia operations have been aggregated and reported on the condensed consolidated statements of

income as income from discontinued operations, net of income tax. Expenses related to general corporate overhead and interest expense allocated to their operations are not included in discontinued operations.

The table below sets forth statement of income data related to discontinued operations. At June 30, 2014 and September 30, 2013 we did not have any assets or liabilities held for sale.



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
	(In thousands)
Operating revenues	$	—	$	—	$	—	$	37,962
Purchased gas cost	—		—		—		21,464
Gross profit	—		—		—		16,498
Operating expenses	—		—		—		5,858
Operating income	—		—		—		10,640
Other nonoperating income	—		—		—		548
Income from discontinued operations before income taxes	—		—		—		11,188
Income tax expense	—		—		—		3,986
Income from discontinued operations	—		—		—		7,202
Gain on sale of discontinued operations, net of tax	—		5,294		—		5,294
Net income from discontinued operations	$	—	$	5,294	$	—	$	12,496

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 June 30, 2014, the related condensed consolidated statements of income and comprehensive income for the three and nine-month periods ended June 30, 2014 and 2013, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2014 and 2013. 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, 2013, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 13, 2013, 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, 2013, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ ERNST & YOUNG LLP

Dallas, Texas

August 6, 2014



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, 2013.

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; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our gas distribution business; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; 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 threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; the risks of accidents and additional operating costs associating with distributing, transporting and storing natural gas; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy and our subsidiaries are engaged primarily in the regulated natural gas distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers throughout our six regulated natural gas distribution divisions, which at June 30, 2014 covered service areas located in eight states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems.

Through our nonregulated businesses, we provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our natural gas distribution divisions and to third parties.

As discussed in Note 3, 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, 2013 and include the following:


•	Regulation


•	Unbilled revenue


•	Pension and other postretirement plans


•	Contingencies


•	Financial instruments and hedging activities


•	Fair value measurements


•	Impairment assessments

Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2014.

RESULTS OF OPERATIONS

Executive Summary

Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. To achieve this objective, we are investing in our infrastructure and are seeking to achieve positive rate outcomes that benefit both our customers and the Company.

Consolidated income from continuing operations for the nine months ended June 30, 2014 increased 19 percent period over period as a result of positive rate outcomes combined with increased gross profit associated with weather that was 20 percent colder than the prior-year period. Rate increases received in our regulated segments increased gross profit by $50.8 million. As of June 30, 2014, we had completed 14 regulatory proceedings in our regulated segments resulting in an $86.0 million increase in annual operating income and had six ratemaking efforts in progress seeking $49.6 million of additional annual operating income.

Regulated gross profit increased $17.6 million due to increased customer consumption in our natural gas distribution segment and increased throughput and related margins in our regulated transportation segment associated with colder weather. The colder than normal weather also increased market demand for natural gas, which drove higher price volatility, particularly during our second fiscal quarter. As a result, realized gross margin in our nonregulated operations increased $25.3 million period over period primarily from trading gains captured during the second fiscal quarter.

During the first nine months of fiscal 2014, our capital expenditures were $552.6 million, which primarily represents investments to improve the safety and reliability of our distribution and transportation systems. We expect our capital expenditures to range between $830 million and $850 million for fiscal 2014, and we plan to fund our growth through the use of operating cash flows and debt and equity securities, while maintaining a balanced capital structure.

On February 18, 2014, we completed the sale of 9,200,000 shares of common stock, including the underwriters’ exercise of their overallotment option of 1,200,000 shares, under our shelf registration statement, generating net proceeds of $390.2 million, which were used to repay short-term debt outstanding under our $950 million commercial paper program, to fund infrastructure spending primarily to enhance the safety and reliability of our system and for general corporate purposes.

Our debt-to-capitalization ratio as of June 30, 2014 was 44.1 percent and our liquidity remained strong with over $1 billion of capacity from our short-term facilities. In October 2014, our $500 million Unsecured 4.95% Senior Notes will mature. We plan to issue new senior unsecured notes to replace this maturing debt. We have executed forward starting interest rate swaps to effectively fix the Treasury yield component associated with this anticipated issuance at 3.129%. On January 30, 2014, Moody's upgraded our senior unsecured debt rating to A2 from Baa1 and our commercial paper rating to P-1 from P-2.

Finally, as a result of the continued contribution and stability of our regulated earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 5.7 percent in the first quarter of fiscal 2014.

Consolidated Results

The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2014 and 2013:



	Three Months Ended June 30						Nine Months Ended June 30
	2014			2013			2014			2013
	(In thousands, except per share data)
Operating revenues	$	942,718		$	857,935		$	4,162,188		$	3,201,086
Gross profit	359,533			316,497			1,244,767			1,111,610
Operating expenses	252,928			230,101			717,362			660,114
Operating income	106,605			86,396			527,405			451,496
Miscellaneous income (expense)	(374		)	(467		)	(4,022		)	1,943
Interest charges	31,840			32,741			95,556			96,594
Income from continuing operations before income taxes	74,391			53,188			427,827			356,845
Income tax expense	28,670			19,714			161,723			133,683
Income from continuing operations	45,721			33,474			266,104			223,162
Income from discontinued operations, net of tax	—			—			—			7,202
Gain on sale of discontinued operations, net of tax	—			5,294			—			5,294
Net income	$	45,721		$	38,768		$	266,104		$	235,658
Diluted net income per share from continuing operations	$	0.45		$	0.36		$	2.76		$	2.43
Diluted net income per share from discontinued operations	—			0.06			—			0.14
Diluted net income per share	$	0.45		$	0.42		$	2.76		$	2.57

Our consolidated net income during the three and nine month periods ended June 30, 2014 and 2013 was earned in each of our business segments as follows:



	Three Months Ended June 30
	2014		2013			Change
	(In thousands)
Natural gas distribution segment from continuing operations	$	18,529	$	15,817		$	2,712
Regulated transmission and storage segment	24,938		23,097			1,841
Nonregulated segment	2,254		(5,440		)	7,694
Net income from continuing operations	45,721		33,474			12,247
Net income from discontinued operations	—		5,294			(5,294		)
Net income	$	45,721	$	38,768		$	6,953





	Nine Months Ended June 30
	2014		2013		Change
	(In thousands)
Natural gas distribution segment from continuing operations	$	170,029	$	155,100	$	14,929
Regulated transmission and storage segment	68,493		55,732		12,761
Nonregulated segment	27,582		12,330		15,252
Net income from continuing operations	266,104		223,162		42,942
Net income from discontinued operations	—		12,496		(12,496		)
Net income	$	266,104	$	235,658	$	30,446

Regulated operations contributed 95 percent and 90 percent to our consolidated net income for the three and nine months ended June 30, 2014. The following tables reflect the segregation of our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:



	Three Months Ended June 30
	2014		2013			Change
	(In thousands, except per share data)
Regulated operations	$	43,467	$	38,914		$	4,553
Nonregulated operations	2,254		(5,440		)	7,694
Net income from continuing operations	45,721		33,474			12,247
Net income from discontinued operations	—		5,294			(5,294		)
Net income	$	45,721	$	38,768		$	6,953

Diluted EPS from continuing regulated operations	$	0.43	$	0.42		$	0.01
Diluted EPS from nonregulated operations	0.02		(0.06		)	0.08
Diluted EPS from continuing operations	0.45		0.36			0.09
Diluted EPS from discontinued operations	—		0.06			(0.06		)
Consolidated diluted EPS	$	0.45	$	0.42		$	0.03





	Nine Months Ended June 30
	2014		2013		Change
	(In thousands, except per share data)
Regulated operations	$	238,522	210,832		$	27,690
Nonregulated operations	27,582		12,330		15,252
Net income from continuing operations	266,104		223,162		42,942
Net income from discontinued operations	—		12,496		(12,496		)
Net income	$	266,104	$	235,658	$	30,446

Diluted EPS from continuing regulated operations	$	2.47	$	2.30	$	0.17
Diluted EPS from nonregulated operations	0.29		0.13		0.16
Diluted EPS from continuing operations	2.76		2.43		0.33
Diluted EPS from discontinued operations	—		0.14		(0.14		)
Consolidated diluted EPS	$	2.76	$	2.57	$	0.19

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




Kansas, West Texas	October — May
Tennessee	October — April
Kentucky, Mississippi, 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 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.

Three Months Ended June 30, 2014 compared with Three Months Ended June 30, 2013

Financial and operational highlights for our natural gas distribution segment for the three months ended June 30, 2014 and 2013 are presented below.



	Three Months Ended June 30
	2014		2013		Change
	(In thousands, unless otherwise noted)
Gross profit	$	257,665	$	239,495	$	18,170
Operating expenses	203,132		187,544		15,588
Operating income	54,533		51,951		2,582
Miscellaneous income	678		268		410
Interest charges	23,649		25,001		(1,352		)
Income from continuing operations before income taxes	31,562		27,218		4,344
Income tax expense	13,033		11,401		1,632
Income from continuing operations	18,529		15,817		2,712
Gain on sale of discontinued operations, net of tax	—		5,649		(5,649		)
Net income	$	18,529	$	21,466	$	(2,937	)
Consolidated natural gas distribution sales volumes from continuing operations — MMcf	39,341		43,190		(3,849		)
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf	32,997		29,179		3,818
Consolidated natural gas distribution throughput from continuing operations — MMcf	72,338		72,369		(31		)
Consolidated natural gas distribution throughput from discontinued operations — MMcf	—		—		—
Total consolidated natural gas distribution throughput — MMcf	72,338		72,369		(31		)
Consolidated natural gas distribution average transportation revenue per Mcf	$	0.46	$	0.45	$	0.01
Consolidated natural gas distribution average cost of gas per Mcf sold	$	6.61	$	5.27	$	1.34

Income from continuing operations for our natural gas distribution segment increased 17 percent, primarily due to an $18.2 million increase in gross profit, partially offset by a $15.6 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:


•	a $9.2 million net increase in rate adjustments, primarily in our Mid-Tex and West Texas Divisions.


•	a $2.7 million increase in other revenue, primarily consisting of late payment fees and installment plan surcharges.


•	a $6.7 million increase in revenue-related taxes in our Mid-Tex and West Texas Divisions, offset by a corresponding $10.9 million increase in the related tax expense.

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 June 30, 2014 and 2013. 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 June 30
	2014			2013		Change
	(In thousands)
Mid-Tex	$	26,100		$	30,457	$	(4,357	)
Kentucky/Mid-States	5,724			5,498		226
Louisiana	7,713			7,543		170
West Texas	3,785			3,678		107
Mississippi	(1,520		)	1,634		(3,154		)
Colorado-Kansas	1,369			2,076		(707		)
Other	11,362			1,065		10,297
Total	$	54,533		$	51,951	$	2,582

Nine Months Ended June 30, 2014 compared with Nine Months Ended June 30, 2013

Financial and operational highlights for our natural gas distribution segment for the nine months ended June 30, 2014 and 2013 are presented below.





	Nine Months Ended June 30
	2014		2013		Change
	(In thousands, unless otherwise noted)
Gross profit	$	942,024	$	866,132	$	75,892
Operating expenses	596,832		544,658		52,174
Operating income	345,192		321,474		23,718
Miscellaneous income	304		2,728		(2,424		)
Interest charges	69,802		74,228		(4,426		)
Income from continuing operations before income taxes	275,694		249,974		25,720
Income tax expense	105,665		94,874		10,791
Income from continuing operations	170,029		155,100		14,929
Income from discontinued operations, net of tax	—		7,202		(7,202		)
Gain on sale of discontinued operations, net of tax	—		5,649		(5,649		)
Net income	$	170,029	$	167,951	$	2,078
Consolidated natural gas distribution sales volumes from continuing operations — MMcf	288,702		242,066		46,636
Consolidated natural gas distribution transportation volumes from continuing operations — MMcf	105,608		98,608		7,000
Consolidated natural gas distribution throughput from continuing operations — MMcf	394,310		340,674		53,636
Consolidated natural gas distribution throughput from discontinued operations — MMcf	—		4,731		(4,731		)
Total consolidated natural gas distribution throughput — MMcf	394,310		345,405		48,905
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	$	5.92	$	4.86	$	1.06

Income from continuing operations for our natural gas distribution segment increased 10 percent, primarily due to a $75.9 million increase in gross profit, partially offset by a $52.2 million increase in operating expenses. The year to date increase in gross profit primarily reflects:


•	a $24.5 million net increase in rate adjustments, primarily in our Mid-Tex, Kentucky and Louisiana service areas.


•	a $12.9 million increase due to increased customer consumption resulting from colder weather, primarily experienced in our Mid-Tex and West Texas Divisions.


•	a $24.5 million increase in revenue-related taxes in our Mid-Tex and West Texas Divisions, offset by a corresponding $25.2 million increase in the related tax expense.

The increase in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to the aforementioned increased revenue-related tax expense, increased levels and timing of incentive compensation expense resulting from improved operating results, increased labor costs primarily associated with increased standby and overtime costs and lower labor capitalization rates as employees incurred more time compared to the prior-year period to ensure our distribution system was safe and reliable during the colder than normal weather.

The following table shows our operating income from continuing operations by natural gas distribution division, in order of total rate base, for the nine months ended June 30, 2014 and 2013. The presentation of our natural gas distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.





	Nine Months Ended June 30
	2014		2013		Change
	(In thousands)
Mid-Tex	$	151,009	$	135,747	$	15,262
Kentucky/Mid-States	53,243		45,700		7,543
Louisiana	51,131		48,432		2,699
West Texas	27,591		28,264		(673		)
Mississippi	31,457		33,072		(1,615		)
Colorado-Kansas	26,785		27,497		(712		)
Other	3,976		2,762		1,214
Total	$	345,192	$	321,474	$	23,718

Recent Ratemaking Developments

The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first nine months of fiscal 2014, we completed 13 regulatory proceedings, resulting in a $40.4 million increase in annual operating income as summarized below:



Rate Action	Annual Increase to Operating Income
	(In thousands)
Infrastructure programs	$	6,092
Annual rate filing mechanisms	18,685
Rate case filings	15,872
Other rate activity	(226		)
	$	40,423

Additionally, the following ratemaking efforts seeking $49.6 million in annual operating income were in progress as of June 30, 2014:



Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Colorado-Kansas	Rate Case	Kansas	$	7,005
Colorado-Kansas	Rate Case	Colorado	4,847
Kentucky/Mid-States	Rate Case	Virginia	2,128
Kentucky/Mid-States	Infrastructure Program	Virginia	170
Louisiana	Rate Stabilization Clause⁽¹⁾	LGS	2,046
Mid-Tex	Rate Review Mechanism ⁽²⁾	Mid-Tex Cities	33,415
			$	49,611


⁽¹⁾	On July 1, 2014, an operating income increase of $1.4 million was implemented for the LGS rate stabilization clause.


⁽²⁾	Mid-Tex Cities RRM rates were put into effect on June 1, 2014, subject to refund. The Company appealed the Mid-Tex Cities decision to deny the 2013 RRM increase to the Texas Railroad Commission on May 30, 2014. A hearing for the appeal is currently set to begin September 3, 2014.

Infrastructure Programs

Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow natural gas distribution companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. As of June 30, 2014, we had infrastructure programs approved in Kansas, Kentucky, Louisiana, Texas and Virginia. The following table summarizes our infrastructure program filings with effective dates occurring during the nine months ended June 30, 2014.



Division	Period End	Incremental Net Utility Plant Investment		Increase in Annual Operating Income		Effective Date
		(In thousands)		(In thousands)
2014 Infrastructure Programs:
West Texas⁽¹⁾	12/2013	$	58,841	$	858	06/17/2014
Mid-Tex - Environs⁽²⁾	12/2013	203,714		881		05/22/2014
Colorado-Kansas - Kansas	09/2013	9,323		882		02/01/2014
Kentucky/Mid-States - Kentucky	09/2014	17,488		2,493		10/01/2013
Kentucky/Mid-States - Virginia	09/2014	1,587		210		10/01/2013
Mid-Tex - Environs⁽²⁾	12/2012	164,681		768		10/01/2013
Total 2014 Infrastructure Programs		$	455,634	$	6,092


⁽¹⁾	Incremental net utility plant investment represents the system-wide incremental investment for the West Texas Division. The increase in annual operating income is for the unincorporated areas of the West Texas Division only.


⁽²⁾	Incremental net utility plan investment represents the system-wide incremental investment for the Mid-Tex Division. The increase in annual operating income is for the unincorporated areas of the Mid-Tex Division only.

Annual Rate Filing Mechanisms

As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. As of June 30, 2014 we had annual rate filing mechanisms in our Louisiana and Mississippi service areas and in our Texas divisions. These mechanisms are referred to as the Dallas annual rate review (DARR) and rate review mechanism (RRM) in our Mid-Tex and West Texas Divisions, stable rate filings in the Mississippi Division and rate stabilization clause in the Louisiana Division. The following annual rate filing mechanisms were completed during the nine months ended June 30, 2014.



Division	Jurisdiction	Test Year Ended	Additional Annual Operating Income		Effective Date
		(In thousands)
2014 Filings:
Mid-Tex	City of Dallas	09/30/2013	$	5,638	06/01/2014
Louisiana	Trans LA	09/30/2013	550		04/01/2014
Mid-Tex	Mid-Tex Cities	12/31/2012	12,497		11/01/2013
Total 2014 Filings			$	18,685

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 to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes the rate cases that were completed during the nine months ended June 30, 2014.





Division	State	Increase in Annual Operating Income		Effective Date
	(In thousands)
2014 Rate Case Filings:
Kentucky/Mid-States	Kentucky	$	5,823	04/22/2014
West Texas	Texas	8,440		04/01/2014
Colorado-Kansas	Colorado	1,609		03/01/2014
Total 2014 Rate Case Filings		$	15,872

Other Ratemaking Activity

The following table summarizes other ratemaking activity during the nine months ended June 30, 2014.





Division	Jurisdiction	Rate Activity	Additional Annual Operating Income			Effective Date
		(In thousands)
2014 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	$	(226	)	02/01/2014
Total 2014 Other Rate Activity			$	(226	)


⁽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.

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 arrangements 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.

Three Months Ended June 30, 2014 compared with Three Months Ended June 30, 2013

Financial and operational highlights for our regulated transmission and storage segment for the three months ended June 30, 2014 and 2013 are presented below.



	Three Months Ended June 30
	2014			2013			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	63,313		$	47,117		$	16,196
Third-party transportation	20,413			18,122			2,291
Storage and park and lend services	1,086			1,412			(326		)
Other	2,377			7,390			(5,013		)
Gross profit	87,189			74,041			13,148
Operating expenses	38,905			29,998			8,907
Operating income	48,284			44,043			4,241
Miscellaneous expense	(489		)	(247		)	(242		)
Interest charges	9,162			8,049			1,113
Income before income taxes	38,633			35,747			2,886
Income tax expense	13,695			12,650			1,045
Net income	$	24,938		$	23,097		$	1,841
Gross pipeline transportation volumes — MMcf	160,038			153,216			6,822
Consolidated pipeline transportation volumes — MMcf	127,979			121,194			6,785

Net income for our regulated transmission and storage segment increased 8 percent, primarily due to a $13.1 million increase in gross profit, partially offset by an $8.9 million increase in operating expenses. The increase in gross profit primarily reflects a $12.2 million increase in rates from the approved 2014 GRIP filing. On May 6, 2014, the RRC approved the Atmos Pipeline — Texas GRIP filing with an annual operating income increase of $45.6 million that went into effect with bills rendered on and after May 6, 2014.

Operating expenses increased $8.9 million primarily due to increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system.

Nine Months Ended June 30, 2014 compared with Nine Months Ended June 30, 2013

Financial and operational highlights for our regulated transmission and storage segment for the nine months ended June 30, 2014 and 2013 are presented below.





	Nine Months Ended June 30
	2014			2013			Change
	(In thousands, unless otherwise noted)
Mid-Tex transportation	$	163,818		$	130,849		$	32,969
Third-party transportation	56,457			47,440			9,017
Storage and park and lend services	4,336			4,484			(148		)
Other	7,534			13,797			(6,263		)
Gross profit	232,145			196,570			35,575
Operating expenses	96,173			87,014			9,159
Operating income	135,972			109,556			26,416
Miscellaneous expense	(2,751		)	(473		)	(2,278		)
Interest charges	27,274			22,777			4,497
Income before income taxes	105,947			86,306			19,641
Income tax expense	37,454			30,574			6,880
Net income	$	68,493		$	55,732		$	12,761
Gross pipeline transportation volumes — MMcf	559,824			493,721			66,103
Consolidated pipeline transportation volumes — MMcf	362,583			335,036			27,547

Net income for our regulated transmission and storage segment increased 23 percent, primarily due to a $35.6 million increase in gross profit. The increase in gross profit primarily reflects a $26.3 million increase in rates from the GRIP filings approved by the RRC in fiscal 2014 and 2013 coupled with a $4.7 million increase associated with higher throughput and basis spreads driven by colder weather.

The Atmos Pipeline — Texas rate case approved by the RRC on April 18, 2011 contained an annual adjustment mechanism, approved for a three-year pilot program, that adjusted regulated rates up or down by 75 percent of the difference between the non-regulated annual revenue of Atmos Pipeline — Texas and a pre-defined base credit. The annual adjustment mechanism expired on June 30, 2013. On January 1, 2014, the RRC approved the extension of the annual adjustment mechanism retroactive to July 1, 2013, which will stay in place until the completion of the next Atmos Pipeline — Texas rate case. As a result of this decision, we recognized a $1.8 million increase in gross profit for the application of the annual adjustment mechanism, for the period July 1, 2013 to September 30, 2013.

Operating expenses increased $9.2 million primarily due to increased depreciation expense associated with increased capital investments, increased levels of pipeline and right-of-way maintenance activities and higher employee-related expenses, partially offset by a $6.7 million refund received as a result of the completion of a state use tax audit.

Nonregulated Segment

Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and, for the fiscal year ended September 30, 2013, represented approximately five percent of our consolidated net income.

AEH's primary business is to buy, sell and deliver natural gas at competitive prices to approximately 1,000 customers located primarily in the Midwest and Southeast areas of the United States. AEH accomplishes this objective by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.

AEH also earns storage and transportation demand fees primarily from our regulated natural gas distribution operations in Louisiana and Kentucky. These demand fees are subject to regulatory oversight and are renewed periodically.

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 buying, selling and delivering natural gas to offer more competitive pricing to those customers.

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.


•	Increased or decreased 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. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

Three Months Ended June 30, 2014 compared with Three Months Ended June 30, 2013

Financial and operating highlights for our nonregulated segment for the three months ended June 30, 2014 and 2013 are presented below.



	Three Months Ended June 30
	2014			2013			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	7,871		$	5,945		$	1,926
Storage and transportation services	3,603			3,689			(86		)
Other	4,004			3,322			682
Total realized margins	15,478			12,956			2,522
Unrealized margins	(665		)	(9,696		)	9,031
Gross profit	14,813			3,260			11,553
Operating expenses	11,025			12,860			(1,835		)
Operating income (loss)	3,788			(9,600		)	13,388
Miscellaneous income	1,018			215			803
Interest charges	610			392			218
Income (loss) before income taxes	4,196			(9,777		)	13,973
Income tax expense (benefit)	1,942			(4,337		)	6,279
Income (loss) from continuing operations	2,254			(5,440		)	7,694
Loss on sale of discontinued operations, net of tax	—			(355		)	355
Net income (loss)	$	2,254		$	(5,795	)	$	8,049
Gross nonregulated delivered gas sales volumes — MMcf	96,119			97,388			(1,269		)
Consolidated nonregulated delivered gas sales volumes — MMcf	82,074			83,341			(1,267		)
Net physical position (Bcf)	6.6			19.2			(12.6		)

The $11.6 million quarter-over-quarter increase in gross profit reflected a $2.5 million increase in realized margins, combined with a $9.0 million increase in unrealized margins. The $2.5 million increase in realized margins primarily reflects a $1.9 million increase in gas delivery and related services margins. Gas delivery per-unit margins increased from 6 cents per Mcf in the prior-year quarter to 8 cents, which reflects favorable financial settlements associated with fixed-price purchases compared to the contractual sales price to the customer. The increases in per-unit margins were partially offset by lower

consolidated sales volumes which decrease two percent as a result of warmer spring temperatures which reduced deliveries to marketing customers.

Unrealized margins increased $9.0 million primarily due to the quarter-over-quarter timing of realized margins on the settlement of hedged natural gas inventory positions.

Operating expenses decreased $1.8 million, primarily due to lower legal-related expenses.

Nine Months Ended June 30, 2014 compared with Nine Months Ended June 30, 2013

Financial and operating highlights for our nonregulated segment for the nine months ended June 30, 2014 and 2013 are presented below.





	Nine Months Ended June 30
	2014		2013			Change
	(In thousands, unless otherwise noted)
Realized margins
Gas delivery and related services	$	32,783	$	31,279		$	1,504
Storage and transportation services	10,815		10,806			9
Other	15,831		(7,982		)	23,813
Total realized margins	59,429		34,103			25,326
Unrealized margins	11,539		15,923			(4,384		)
Gross profit	70,968		50,026			20,942
Operating expenses	24,727		29,565			(4,838		)
Operating income	46,241		20,461			25,780
Miscellaneous income	1,785		1,791			(6		)
Interest charges	1,840		1,687			153
Income before income taxes	46,186		20,565			25,621
Income tax expense	18,604		8,235			10,369
Income from continuing operations	27,582		12,330			15,252
Loss on sale of discontinued operations, net of tax	—		(355		)	355
Net income	$	27,582	$	11,975		$	15,607
Gross nonregulated delivered gas sales volumes — MMcf	343,451		306,120			37,331
Consolidated nonregulated delivered gas sales volumes — MMcf	294,678		265,791			28,887
Net physical position (Bcf)	6.6		19.2			(12.6		)

Net income for our nonregulated segment increased 130 percent from the prior year due to higher gross profit and decreased operating expenses.

The $20.9 million period-over-period increase in gross profit reflected a $25.3 million increase in realized margins, offset by a $4.4 million decrease in unrealized margins. The $25.3 million increase in realized margins reflects:

•

A $23.8 million increase in other realized margins due to the acceleration of physical withdrawals into the second quarter from future periods to capture gross profit margin during periods of increased natural gas price volatility caused by strong market demand as a result of significantly colder weather during the second quarter. In contrast, losses were incurred from storage optimization activities in the prior year largely due to unfavorable changes in market prices relative to the execution strategy in place at that time.

•

A $1.5 million increase in gas delivery and related services margins. Consolidated sales volumes increased 11 percent as a result of stronger demand from marketing, industrial and utility/municipal customers due to colder weather. Additionally, gas delivery per-unit margins decreased from 10.2 cents per Mcf in the prior-year period to 9.5 cents per Mcf due primarily to losses incurred during the second quarter to meet peaking requirements for certain customers during periods of colder weather, due to volatility between spot purchase prices and the contractual sales price to the customer.

Unrealized margins decreased $4.4 million primarily due to the period-over-period timing of realized margins on the settlement of hedged natural gas inventory positions.

Operating expenses decreased $4.8 million, primarily due to lower legal expenses related to the dismissal of the Kentucky litigation and the resolution of the Tennessee Business License Tax matter, which are discussed in Note 7 to the financial statements.

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 capital structure to ensure that we (i) have sufficient liquidity for our short-term and long-term needs in a cost-effective manner and (ii) maintain a balanced capital structure with a debt-to-capitalization ratio in a target range of 50 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of capacity from our short-term facilities.

We plan to fund our growth through the use of operating cash flows, debt and equity securities while maintaining a balanced capital structure. To support our capital market activities, we have a shelf registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock including the underwriters’ exercise of their overallotment option of 1,200,000 shares. The offering was priced at $44.00 and generated net proceeds of $390.2 million, which were used to repay short-term debt outstanding under our $950 million commercial paper program, to fund infrastructure spending primarily to enhance the safety and reliability of our system and for general corporate purposes.

As of June 30, 2014, approximately $1.35 billion of securities remained available for issuance under the shelf registration statement until March 28, 2016.

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2014, September 30, 2013 and June 30, 2013:



	June 30, 2014				September 30, 2013				June 30, 2013
	(In thousands, except percentages)
Short-term debt	$	—	—	%	$	367,984	6.8	%	$	141,998	2.7	%
Long-term debt⁽¹⁾	2,455,907		44.1	%	2,455,671		45.4	%	2,455,593		47.4	%
Shareholders’ equity	3,116,685		55.9	%	2,580,409		47.8	%	2,581,444		49.9	%
Total	$	5,572,592	100.0	%	$	5,404,064	100.0	%	$	5,179,035	100.0	%


⁽¹⁾	In October 2014, $500 million of long-term debt will mature. We plan to issue new senior notes to replace this

maturing debt. We have executed forward starting interest rate swaps to effectively fix the Treasury yield component associated with this anticipated issuance at 3.129%.

Total debt as a percentage of total capitalization, including short-term debt, was 44.1 percent at June 30, 2014, 52.2 percent at September 30, 2013 and 50.1 percent at June 30, 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 nine months ended June 30, 2014 and 2013 are presented below.



	Nine Months Ended June 30
	2014			2013			Change
	(In thousands)
Total cash provided by (used in)
Operating activities	$	630,210		$	509,575		$	120,635
Investing activities	(553,220		)	(432,589		)	(120,631		)
Financing activities	(91,768		)	(109,246		)	17,478
Change in cash and cash equivalents	(14,778		)	(32,260		)	17,482
Cash and cash equivalents at beginning of period	66,199			64,239			1,960
Cash and cash equivalents at end of period	$	51,421		$	31,979		$	19,442

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 changes in the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

For the nine months ended June 30, 2014, we generated cash flow of $630.2 million from operating activities compared with $509.6 million for the nine months ended June 30, 2013. The $120.6 million increase in operating cash flows primarily reflects higher operating results from colder weather and rate increases combined with the timing of customer collections and vendor payments.

Cash flows from investing activities

In recent years, a substantial portion of our cash resources has been used to fund growth projects in our regulated operations, 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 regulatory strategy, we focus 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.

For the nine months ended June 30, 2014, capital expenditures were $552.6 million, compared with $582.5 million in the prior-year period. The period-over-period decrease primarily reflects:


•	A $51.5 million decrease in capital spending in our regulated transmission and storage segment primarily associated with the completion of the Line WX expansion project, partially offset by


•	A $22.0 million increase in capital spending in our natural gas distribution segment due to increased spending under our infrastructure replacement programs.

Cash flows from financing activities

For the nine months ended June 30, 2014, our financing activities used $91.8 million of cash compared with $109.2 million used in the prior-year period. The decrease is primarily due to timing between short-term debt borrowings and repayments during the current year partially offset by proceeds from the equity offering completed in February 2014 compared with proceeds generated from the issuance of long-term debt in the prior-year period.

The following table summarizes our share issuances for the nine months ended June 30, 2014 and 2013.



	Nine Months Ended June 30
	2014	2013
Shares issued:
Direct stock purchase plan	41,907	—
1998 Long-Term Incentive Plan	653,130	531,372
Outside Directors Stock-for-Fee Plan	1,354	1,599
February 2014 Offering	9,200,000	—
Total shares issued	9,896,391	532,971

The year-over-year increase in the number of shares issued primarily reflects the equity offering completed in February 2014 as well as a higher number of performance-based awards issued in the current year as actual performance exceeded the target. For the nine months ended June 30, 2014 and 2013, we canceled and retired 190,134 and 133,351 shares attributable to federal income tax withholdings on equity awards.

Credit Facilities

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

We finance our short-term borrowing requirements through a combination of a $950 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders that provide approximately $1 billion of working capital funding. As of June 30, 2014, the amount available to us under our credit facilities, net of outstanding letters of credit, was $1,031.4 million.

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 June 30, 2014, 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
Senior unsecured long-term debt	A-	A2	A-
Commercial paper	A-2	P-1	F-2

On January 30, 2014, Moody's upgraded our senior unsecured debt rating to A2 from Baa1 and our commercial paper rating to P-1 from P-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 is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB- for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of June 30, 2014. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Significant commercial commitments are described in Note 7 to the unaudited condensed consolidated financial statements. There were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2014.

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. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

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 and nine months ended June 30, 2014 and 2013:



	Three Months Ended June 30					Nine Months Ended June 30
	2014			2013		2014			2013
	(In thousands)
Fair value of contracts at beginning of period	$	89,411		$	40,126	$	109,648		$	(76,260	)
Contracts realized/settled	23			81		5,220			2,610
Fair value of new contracts	(902		)	541		(36		)	1,554
Other changes in value	(39,019		)	45,640		(65,319		)	158,484
Fair value of contracts at end of period	$	49,513		$	86,388	$	49,513		$	86,388

The fair value of our natural gas distribution segment’s financial instruments at June 30, 2014 is presented below by time period and fair value source:



	Fair Value of Contracts at June 30, 2014
	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	$	35,829	$	13,684	$	—	$	—	$	49,513
Prices based on models and other valuation methods	—		—		—		—		—
Total Fair Value	$	35,829	$	13,684	$	—	$	—	$	49,513

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and nine months ended June 30, 2014 and 2013:



	Three Months Ended June 30						Nine Months Ended June 30
	2014			2013			2014			2013
	(In thousands)
Fair value of contracts at beginning of period	$	5,796		$	(4,019	)	$	(14,700	)	$	(15,123	)
Contracts realized/settled	(3,220		)	(2,193		)	11,358			10,051
Fair value of new contracts	—			—			—			—
Other changes in value	762			1,889			6,680			749
Fair value of contracts at end of period	3,338			(4,323		)	3,338			(4,323		)
Netting of cash collateral	9,689			14,252			9,689			14,252
Cash collateral and fair value of contracts at period end	$	13,027		$	9,929		$	13,027		$	9,929

The fair value of our nonregulated segment’s financial instruments at June 30, 2014 is presented below by time period and fair value source:



	Fair Value of Contracts at June 30, 2014
	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	$	(1,771	)	$	5,143	$	(34	)	$	—	$	3,338
Prices based on models and other valuation methods	—			—		—			—		—
Total Fair Value	$	(1,771	)	$	5,143	$	(34	)	$	—	$	3,338

Pension and Postretirement Benefits Obligations

For the nine months ended June 30, 2014 and 2013, our total net periodic pension and other benefits costs were $53.5 million and $59.8 million. A substantial portion of those costs relating to our natural gas distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 2014 costs were determined using a September 30, 2013 measurement date. As of September 30, 2013, interest and corporate bond rates utilized to determine our discount rates were higher than the interest and corporate bond rates as of September 30, 2012, the measurement date for our fiscal 2013 net periodic cost. Therefore, we increased the discount rate used to measure our fiscal 2014 net periodic cost from 4.04 percent to 4.95 percent. However, we decreased the expected return on plan assets from 7.75 percent to 7.25 percent in the determination of our fiscal 2014 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2014 net periodic pension cost to decrease by less than five percent.

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. For the nine months ended June 30, 2014 we contributed $27.1 million to our defined benefit plans and we do not anticipate making any contributions in the fiscal 2014 fourth quarter. For the nine months ended June 30, 2014 we contributed $18.1 million to our postretirement medical plans. We anticipate contributing a total of between $20 million and $25 million to these plans during fiscal 2014.

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 and nine month periods ended June 30, 2014 and 2013.

Natural Gas Distribution Sales and Statistical Data — Continuing Operations



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
METERS IN SERVICE, end of period
Residential	2,751,812		2,751,599		2,751,812		2,751,599
Commercial	245,833		246,286		245,833		246,286
Industrial	1,466		1,502		1,466		1,502
Public authority and other	8,400		9,990		8,400		9,990
Total meters	3,007,511		3,009,377		3,007,511		3,009,377

INVENTORY STORAGE BALANCE — Bcf⁽¹⁾	39.0		33.7		39.0		33.7
SALES VOLUMES — MMcf⁽²⁾
Gas sales volumes
Residential	19,555		22,668		175,884		143,920
Commercial	15,305		15,198		92,240		76,919
Industrial	3,074		3,408		12,898		12,891
Public authority and other	1,407		1,916		7,680		8,336
Total gas sales volumes	39,341		43,190		288,702		242,066
Transportation volumes	36,321		32,458		116,064		106,405
Total throughput	75,662		75,648		404,766		348,471
OPERATING REVENUES (000’s)⁽²⁾
Gas sales revenues
Residential	$	309,798	$	289,363	$	1,698,600	$	1,301,264
Commercial	154,375		126,925		748,705		556,194
Industrial	19,458		19,303		74,003		65,059
Public authority and other	10,817		12,970		54,960		51,120
Total gas sales revenues	494,448		448,561		2,576,268		1,973,637
Transportation revenues	16,216		14,253		53,972		47,486
Other gas revenues	7,043		4,330		22,292		17,984
Total operating revenues	$	517,707	$	467,144	$	2,652,532	$	2,039,107
Average transportation revenue per Mcf⁽¹⁾	$	0.45	$	0.44	$	0.47	$	0.45
Average cost of gas per Mcf sold⁽¹⁾	$	6.61	$	5.27	$	5.92	$	4.86

See footnotes following these tables.

Natural Gas Distribution Sales and Statistical Data — Discontinued Operations



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
Meters in service, end of period	—		—		—		—
Sales volumes — MMcf
Total gas sales volumes	—		—		—		3,611
Transportation volumes	—		—		—		1,120
Total throughput	—		—		—		4,731

Operating revenues (000’s)	$	—	$	—	$	—	$	37,962

Regulated Transmission and Storage and Nonregulated Operations Sales and Statistical Data



	Three Months Ended June 30				Nine Months Ended June 30
	2014		2013		2014		2013
CUSTOMERS, end of period
Industrial	736		750		736		750
Municipal	128		133		128		133
Other	524		432		524		432
Total	1,388		1,315		1,388		1,315
NONREGULATED INVENTORY STORAGE
BALANCE — Bcf	10.9		22.2		10.9		22.2
REGULATED TRANSMISSION AND
STORAGE VOLUMES — MMcf⁽²⁾	160,038		153,216		559,824		493,721
NONREGULATED DELIVERED GAS SALES
VOLUMES — MMcf⁽²⁾	96,119		97,388		343,451		306,120
OPERATING REVENUES (000’s)⁽²⁾
Regulated transmission and storage	$	87,189	$	74,041	$	232,145	$	196,570
Nonregulated	465,033		421,808		1,670,437		1,250,650
Total operating revenues	$	552,222	$	495,849	$	1,902,582	$	1,447,220

Notes 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, 2013. During the nine months ended June 30, 2014, there were no material changes in our quantitative and qualitative disclosures about market risk.



Item 4.	Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2014 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of the fiscal year ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION



Item 1.	Legal Proceedings

During the nine months ended June 30, 2014, except as noted in Note 7 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 10 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. 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: August 6, 2014

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.

Atmos Energy - 10-Q quarterly report FY2014 Q3

What is the market capitalization of a company?

DISCLAIMER

Contact

Links