Edgar Filing: ATMOS ENERGY CORP

ATO 2015.06.30 10-Q

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, 2015



¨	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 July 31, 2015.



Class		Shares Outstanding
No Par Value		101,369,699

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
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, 2015			September 30, 2014
	(Unaudited)
	(In thousands, except share data)
ASSETS
Property, plant and equipment	$	9,017,043		$	8,447,700
Less accumulated depreciation and amortization	1,804,955			1,721,794
Net property, plant and equipment	7,212,088			6,725,906
Current assets
Cash and cash equivalents	43,153			42,258
Accounts receivable, net	301,743			343,400
Gas stored underground	213,151			278,917
Other current assets	58,602			111,265
Total current assets	616,649			775,840
Goodwill	742,029			742,029
Deferred charges and other assets	313,723			350,929
	$	8,884,489		$	8,594,704
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, 2015 — 101,336,818 shares; September 30, 2014 — 100,388,092 shares	$	507		$	502
Additional paid-in capital	2,207,102			2,180,151
Retained earnings	1,092,887			917,972
Accumulated other comprehensive loss	(62,241		)	(12,393		)
Shareholders’ equity	3,238,255			3,086,232
Long-term debt	2,455,303			2,455,986
Total capitalization	5,693,558			5,542,218
Current liabilities
Accounts payable and accrued liabilities	227,256			308,086
Other current liabilities	437,344			405,869
Short-term debt	251,977			196,695
Total current liabilities	916,577			910,650
Deferred income taxes	1,429,090			1,286,616
Regulatory cost of removal obligation	432,153			445,387
Pension and postretirement liabilities	318,140			340,963
Deferred credits and other liabilities	94,971			68,870
	$	8,884,489		$	8,594,704

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended June 30
	2015			2014
	(Unaudited) (In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	416,794		$	517,707
Regulated pipeline segment	97,008			87,189
Nonregulated segment	278,769			465,485
Intersegment eliminations	(106,170		)	(127,211		)
	686,401			943,170
Purchased gas cost
Regulated distribution segment	149,775			260,042
Regulated pipeline segment	—			—
Nonregulated segment	260,990			450,672
Intersegment eliminations	(106,037		)	(127,077		)
	304,728			583,637
Gross profit	381,673			359,533
Operating expenses
Operation and maintenance	132,447			125,559
Depreciation and amortization	68,444			63,955
Taxes, other than income	63,175			63,414
Total operating expenses	264,066			252,928
Operating income	117,607			106,605
Miscellaneous income (expense)	634			(374		)
Interest charges	27,955			31,840
Income before income taxes	90,286			74,391
Income tax expense	34,005			28,670
Net income	$	56,281		$	45,721
Basic net income per share	$	0.55		$	0.45
Diluted net income per share	$	0.55		$	0.45
Cash dividends per share	$	0.39		$	0.37
Weighted average shares outstanding:
Basic	102,000			101,162
Diluted	102,000			101,163

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME





	Nine Months Ended June 30
	2015			2014
	(Unaudited) (In thousands, except per share data)
Operating revenues
Regulated distribution segment	$	2,394,179		$	2,652,532
Regulated pipeline segment	272,305			232,145
Nonregulated segment	1,179,379			1,660,131
Intersegment eliminations	(360,629		)	(392,926		)
	3,485,234			4,151,882
Purchased gas cost
Regulated distribution segment	1,397,113			1,710,508
Regulated pipeline segment	—			—
Nonregulated segment	1,122,655			1,589,163
Intersegment eliminations	(360,230		)	(392,556		)
	2,159,538			2,907,115
Gross profit	1,325,696			1,244,767
Operating expenses
Operation and maintenance	384,489			365,991
Depreciation and amortization	204,059			185,731
Taxes, other than income	181,606			165,640
Total operating expenses	770,154			717,362
Operating income	555,542			527,405
Miscellaneous expense	(2,634		)	(4,022		)
Interest charges	85,166			95,556
Income before income taxes	467,742			427,827
Income tax expense	176,182			161,723
Net income	291,560			266,104
Basic net income per share	$	2.86		$	2.76
Diluted net income per share	$	2.86		$	2.76
Cash dividends per share	$	1.17		$	1.11
Weighted average shares outstanding:
Basic	101,776			96,392
Diluted	101,776			96,394

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
	2015			2014			2015			2014
	(Unaudited) (In thousands)
Net income	$	56,281		$	45,721		$	291,560		$	266,104
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(41), $216, $(170) and $1,518	(191		)	377			(296		)	2,519
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $31,314, $(13,472), $(17,232) and $(21,005)	54,475			(23,440		)	(29,981		)	(36,545		)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $7,393, $(1,580), $(12,698) and $4,122	11,563			(2,471		)	(19,571		)	6,448
Total other comprehensive income (loss)	65,847			(25,534		)	(49,848		)	(27,578		)
Total comprehensive income	$	122,128		$	20,187		$	241,712		$	238,526

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended June 30
	2015			2014
	(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	291,560		$	266,104
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization:
Charged to depreciation and amortization	204,059			185,731
Charged to other accounts	853			669
Deferred income taxes	164,627			150,457
Other	18,146			21,587
Net assets / liabilities from risk management activities	(13,136		)	3,158
Net change in operating assets and liabilities	51,473			2,504
Net cash provided by operating activities	717,582			630,210
Cash Flows From Investing Activities
Capital expenditures	(667,483		)	(552,600		)
Other, net	(1,119		)	(620		)
Net cash used in investing activities	(668,602		)	(553,220		)
Cash Flows From Financing Activities
Net increase (decrease) in short-term debt	48,830			(366,602		)
Net proceeds from equity offering	—			390,205
Net proceeds from issuance of long-term debt	493,538			—
Settlement of interest rate agreements	13,364			—
Repayment of long-term debt	(500,000		)	—
Cash dividends paid	(116,645		)	(108,806		)
Repurchase of equity awards	(7,985		)	(8,717		)
Issuance of common stock	20,813			2,152
Net cash used in financing activities	(48,085		)	(91,768		)
Net increase (decrease) in cash and cash equivalents	895			(14,778		)
Cash and cash equivalents at beginning of period	42,258			66,199
Cash and cash equivalents at end of period	$	43,153		$	51,421

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2015

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 pipeline businesses as well as other nonregulated natural gas businesses. Historically, our regulated businesses have generated over 90 percent of our consolidated net income.

Through our regulated 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 distribution divisions, which at June 30, 2015, covered service areas located in eight states. 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 regulated 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, 2014. 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, 2014. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2015 are not indicative of our results of operations for the full 2015 fiscal year, which ends September 30, 2015.

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, 2014.

Certain prior-year amounts have been reclassified to conform with the current year presentation.

During the second quarter of fiscal 2015, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.

In May 2014, the Financial Accounting Standards Board (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. On July 9, 2015, the FASB voted to approve a deferral of the effective date of the new standard by one year. With the one year extension, the new standard is currently scheduled to become effective for us beginning on October 1, 2018 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.

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new standard will be effective for us beginning on October 1, 2016, and will be applied retrospectively. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

In April 2015, the FASB issued guidance to simplify the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. The new guidance is effective for us beginning October 1, 2016 and may be applied either prospectively or retrospectively with early adoption permitted. We anticipate the adoption of this standard will not have a material impact 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, 2015 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, 2015 and September 30, 2014 included the following:



	June 30, 2015		September 30, 2014
	(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	149,202	$	162,777
Merger and integration costs, net	4,327		4,730
Deferred gas costs	1,494		20,069
Rate case costs	1,354		3,757
Infrastructure Mechanisms⁽²⁾	24,228		26,948
APT annual adjustment mechanism	—		8,479
Recoverable loss on reacquired debt	16,959		18,877
Other	4,944		4,672
	$	202,508	$	250,309
Regulatory liabilities:
Deferred gas costs	$	81,134	$	35,063
Deferred franchise fees	747		5,268
Regulatory cost of removal obligation	486,672		490,448
Other	12,810		14,980
	$	581,363	$	545,759


⁽¹⁾	Includes $15.8 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.


⁽²⁾	Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest expense, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable 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 regulated distribution segment, which includes our regulated natural gas distribution and related sales operations,


•	The regulated pipeline 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 regulated distribution segment operations are geographically dispersed, they are reported as a single segment as each regulated 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, 2014. 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, 2015 and 2014 by segment are presented in the following tables:



	Three Months Ended June 30, 2015
	Regulated Distribution		Regulated Pipeline			Nonregulated			Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	415,160	$	25,859		$	245,382		$	—		$	686,401
Intersegment revenues	1,634		71,149			33,387			(106,170		)	—
	416,794		97,008			278,769			(106,170		)	686,401
Purchased gas cost	149,775		—			260,990			(106,037		)	304,728
Gross profit	267,019		97,008			17,779			(133		)	381,673
Operating expenses
Operation and maintenance	98,552		26,572			7,456			(133		)	132,447
Depreciation and amortization	55,491		11,816			1,137			—			68,444
Taxes, other than income	56,176		6,193			806			—			63,175
Total operating expenses	210,219		44,581			9,399			(133		)	264,066
Operating income	56,800		52,427			8,380			—			117,607
Miscellaneous income (expense)	1,045		(211		)	345			(545		)	634
Interest charges	19,961		8,299			240			(545		)	27,955
Income before income taxes	37,884		43,917			8,485			—			90,286
Income tax expense	15,420		15,349			3,236			—			34,005
Net income	$	22,464	$	28,568		$	5,249		$	—		$	56,281
Capital expenditures	$	170,134	$	55,914		$	(209	)	$	—		$	225,839



	Three Months Ended June 30, 2014
	Regulated Distribution		Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	516,644	$	24,990		$	401,536	$	—		$	943,170
Intersegment revenues	1,063		62,199			63,949		(127,211		)	—
	517,707		87,189			465,485		(127,211		)	943,170
Purchased gas cost	260,042		—			450,672		(127,077		)	583,637
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




	Nine Months Ended June 30, 2015
	Regulated Distribution			Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,389,037		$	70,887		$	1,025,310	$	—		$	3,485,234
Intersegment revenues	5,142			201,418			154,069		(360,629		)	—
	2,394,179			272,305			1,179,379		(360,629		)	3,485,234
Purchased gas cost	1,397,113			—			1,122,655		(360,230		)	2,159,538
Gross profit	997,066			272,305			56,724		(399		)	1,325,696
Operating expenses
Operation and maintenance	288,962			74,029			21,897		(399		)	384,489
Depreciation and amortization	165,730			34,945			3,384		—			204,059
Taxes, other than income	162,759			16,296			2,551		—			181,606
Total operating expenses	617,451			125,270			27,832		(399		)	770,154
Operating income	379,615			147,035			28,892		—			555,542
Miscellaneous income (expense)	(1,221		)	(842		)	897		(1,468		)	(2,634		)
Interest charges	60,914			25,014			706		(1,468		)	85,166
Income before income taxes	317,480			121,179			29,083		—			467,742
Income tax expense	121,776			42,894			11,512		—			176,182
Net income	$	195,704		$	78,285		$	17,571	$	—		$	291,560
Capital expenditures	$	482,371		$	185,028		$	84	$	—		$	667,483




	Nine Months Ended June 30, 2014
	Regulated Distribution		Regulated Pipeline			Nonregulated		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,648,505	$	67,162		$	1,436,215	$	—		$	4,151,882
Intersegment revenues	4,027		164,983			223,916		(392,926		)	—
	2,652,532		232,145			1,660,131		(392,926		)	4,151,882
Purchased gas cost	1,710,508		—			1,589,163		(392,556		)	2,907,115
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 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

Balance sheet information at June 30, 2015 and September 30, 2014 by segment is presented in the following tables:



	June 30, 2015
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,543,386	$	1,613,182	$	55,520		$	—		$	7,212,088
Investment in subsidiaries	1,028,457		—		(2,096		)	(1,026,361		)	—
Current assets
Cash and cash equivalents	35,288		—		7,865			—			43,153
Assets from risk management activities	780		—		10,806			—			11,586
Other current assets	375,213		20,100		497,871			(331,274		)	561,910
Intercompany receivables	820,587		—		—			(820,587		)	—
Total current assets	1,231,868		20,100		516,542			(1,151,861		)	616,649
Goodwill	574,816		132,502		34,711			—			742,029
Noncurrent assets from risk management activities	1,109		—		—			—			1,109
Deferred charges and other assets	291,740		15,305		5,569			—			312,614
	$	8,671,376	$	1,781,089	$	610,246		$	(2,178,222	)	$	8,884,489
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,238,255	$	560,898	$	467,559		$	(1,028,457	)	$	3,238,255
Long-term debt	2,455,303		—		—			—			2,455,303
Total capitalization	5,693,558		560,898		467,559			(1,028,457		)	5,693,558
Current liabilities
Short-term debt	570,977		—		—			(319,000		)	251,977
Liabilities from risk management activities	4,916		—		—			—			4,916
Other current liabilities	551,102		17,850		100,910			(10,178		)	659,684
Intercompany payables	—		786,493		34,094			(820,587		)	—
Total current liabilities	1,126,995		804,343		135,004			(1,149,765		)	916,577
Deferred income taxes	1,014,432		415,687		(1,029		)	—			1,429,090
Noncurrent liabilities from risk management activities	47,224		—		—			—			47,224
Regulatory cost of removal obligation	432,153		—		—			—			432,153
Pension and postretirement liabilities	318,140		—		—			—			318,140
Deferred credits and other liabilities	38,874		161		8,712			—			47,747
	$	8,671,376	$	1,781,089	$	610,246		$	(2,178,222	)	$	8,884,489



	September 30, 2014
	Regulated Distribution		Regulated Pipeline		Nonregulated			Eliminations			Consolidated
	(In thousands)
ASSETS
Property, plant and equipment, net	$	5,202,761	$	1,464,572	$	58,573		$	—		$	6,725,906
Investment in subsidiaries	952,171		—		(2,096		)	(950,075		)	—
Current assets
Cash and cash equivalents	33,303		—		8,955			—			42,258
Assets from risk management activities	23,102		—		22,725			—			45,827
Other current assets	490,408		14,009		526,161			(342,823		)	687,755
Intercompany receivables	790,442		—		—			(790,442		)	—
Total current assets	1,337,255		14,009		557,841			(1,133,265		)	775,840
Goodwill	574,816		132,502		34,711			—			742,029
Noncurrent assets from risk management activities	13,038		—		—			—			13,038
Deferred charges and other assets	309,965		21,826		6,100			—			337,891
	$	8,390,006	$	1,632,909	$	655,129		$	(2,083,340	)	$	8,594,704
CAPITALIZATION AND LIABILITIES
Shareholders’ equity	$	3,086,232	$	482,612	$	469,559		$	(952,171	)	$	3,086,232
Long-term debt	2,455,986		—		—			—			2,455,986
Total capitalization	5,542,218		482,612		469,559			(952,171		)	5,542,218
Current liabilities
Short-term debt	522,695		—		—			(326,000		)	196,695
Liabilities from risk management activities	1,730		—		—			—			1,730
Other current liabilities	559,765		24,790		142,397			(14,727		)	712,225
Intercompany payables	—		763,635		26,807			(790,442		)	—
Total current liabilities	1,084,190		788,425		169,204			(1,131,169		)	910,650
Deferred income taxes	913,260		361,688		11,668			—			1,286,616
Noncurrent liabilities from risk management activities	20,126		—		—			—			20,126
Regulatory cost of removal obligation	445,387		—		—			—			445,387
Pension and postretirement liabilities	340,963		—		—			—			340,963
Deferred credits and other liabilities	43,862		184		4,698			—			48,744
	$	8,390,006	$	1,632,909	$	655,129		$	(2,083,340	)	$	8,594,704

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, 2015 and 2014 are calculated as follows:



	Three Months Ended June 30				Nine Months Ended June 30
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Basic Earnings Per Share
Net income	$	56,281	$	45,721	$	291,560	$	266,104
Less: Income allocated to participating securities	111		106		596		667
Income available to common shareholders	$	56,170	$	45,615	$	290,964	$	265,437
Basic weighted average shares outstanding	102,000		101,162		101,776		96,392
Net income per share - Basic	$	0.55	$	0.45	$	2.86	$	2.76
Diluted Earnings Per Share
Net income available to common shareholders	$	56,170	$	45,615	290,964		265,437
Effect of dilutive stock options and other shares	—		—		—		—
Net income available to common shareholders	$	56,170	$	45,615	290,964		265,437
Basic weighted average shares outstanding	102,000		101,162		101,776		96,392
Additional dilutive stock options and other shares	—		1		—		2
Diluted weighted average shares outstanding	102,000		101,163		101,776		96,394
Net income per share - Diluted	$	0.55	$	0.45	$	2.86	$	2.76

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 as their exercise price was less than the average market price of the common stock during those periods. As of June 30, 2015 there were no outstanding options.

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 commercial paper program, 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, 2015 and 2014 under our 2011 share repurchase program, which is scheduled to end on September 30, 2016.

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, 2014. Except as noted below, there were no material changes in the terms of our debt instruments during the nine months ended June 30, 2015.

Long-term debt

Long-term debt at June 30, 2015 and September 30, 2014 consisted of the following:



	June 30, 2015		September 30, 2014
	(In thousands)
Unsecured 4.95% Senior Notes, due October 2014	$	—	$	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
Unsecured 4.125% Senior Notes, due 2044	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	4,697		4,014
	$	2,455,303	$	2,455,986

On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds of approximately $494 million were used to repay our $500 million 4.95% senior unsecured notes at maturity on October 15, 2014.

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 $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1.3 billion of working capital funding. At June 30, 2015 and September 30, 2014 a total of $252.0 million and $196.7 million was 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 $1.3 billion of working capital funding, including a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 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 $4.2 million at June 30, 2015.

In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or

(ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.

Nonregulated Operations

Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility and one committed $15 million 364-day bilateral credit facility that expire in December 2015. 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 $36.0 million at June 30, 2015.

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. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.

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. At June 30, 2015, $845 million of securities remain 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, 2015, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 47 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, 2015. 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, 2015 and 2014 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.



	Three Months Ended June 30
	Pension Benefits						Other Benefits
	2015			2014			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	5,051		$	4,738		$	3,895		$	4,196
Interest cost	6,698			6,824			3,596			3,987
Expected return on assets	(6,435		)	(5,901		)	(1,608		)	(1,291		)
Amortization of transition obligation	—			—			69			69
Amortization of prior service credit	(48		)	(34		)	(411		)	(363		)
Amortization of actuarial loss	3,916			3,931			—			158
Net periodic pension cost	$	9,182		$	9,558		$	5,541		$	6,756




	Nine Months Ended June 30
	Pension Benefits						Other Benefits
	2015			2014			2015			2014
	(In thousands)
Components of net periodic pension cost:
Service cost	$	15,153		$	14,214		$	11,687		$	12,588
Interest cost	20,095			20,472			10,789			11,963
Expected return on assets	(19,308		)	(17,702		)	(4,824		)	(3,875		)
Amortization of transition obligation	—			—			205			205
Amortization of prior service credit	(144		)	(102		)	(1,233		)	(1,088		)
Amortization of actuarial loss	11,749			11,793			—			474
Settlement loss	—			4,539			—			—
Net periodic pension cost	$	27,545		$	33,214		$	16,624		$	20,267

The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2015 and 2014 are as follows:



	Pension Benefits				Other Benefits
	2015		2014		2015		2014
Discount rate	4.43	%	4.95	%	4.43	%	4.95	%
Rate of compensation increase	3.50	%	3.50	%	N/A		N/A
Expected return on plan assets	7.25	%	7.25	%	4.60	%	4.60	%

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, 2015. Based on that determination, we are not required to make a minimum contribution to our defined benefit plans during fiscal 2015. However, we made a voluntary contribution of $38.0 million during the third quarter of fiscal 2015.

We contributed $15.0 million to our other post-retirement benefit plans during the nine months ended June 30, 2015. We expect to contribute a total of approximately $20 million to these plans during all of fiscal 2015.

In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. We anticipate utilizing the new mortality data in our next actuarial calculation date on September 30, 2015. We are currently evaluating the impact the updated data will have on the valuation of our defined benefit and other post-retirement benefits plans. It is expected the use of this new data will increase the total amount of liabilities reported on our balance sheet in future periods by less than five percent.

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, 2014, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2015.

We are a party to various 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

Our regulated 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 also maintains a limited number of 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 prices indexed to natural gas distribution hubs. At June 30, 2015, we were committed to purchase 36.6 Bcf within one year and 35.2 Bcf within two years under indexed contracts. Purchases under these contracts totaled $21.2 million and $27.8 million for the three months ended June 30, 2015 and 2014 and $93.2 million, and $81.9 million for the nine months ended June 30, 2015 and 2014.

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, 2015, AEH was committed to purchase 99.1 Bcf within one year, 22.6 Bcf within one to three years and 0.2 Bcf after three years under indexed contracts. AEH is committed to purchase 4.1 Bcf within one year under fixed price contracts with prices ranging from $2.62 to $3.23 per Mcf. Purchases under these contracts totaled $203.3 million and $383.2 million for the three months ended June 30, 2015 and 2014 and $925.4 million and $1,354.5 million for the nine months ended June 30, 2015 and 2014.

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, 2014. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2015.

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, 2015, a rate case was in progress in our Colorado service area, an annual rate filing mechanism was in progress in Louisiana and an infrastructure program 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 currently use financial instruments in our regulated distribution and nonregulated segments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments, which have been tailored to our regulated distribution and nonregulated segments, and the related accounting for these financial instruments are fully described in Notes 2 and 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the nine months ended June 30, 2015 there were no changes in our objectives, strategies and accounting for using financial instruments. 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. The following summarizes those objectives and strategies.

Regulated Commodity Risk Management Activities

Our purchased gas cost adjustment mechanisms essentially insulate our regulated distribution segment from commodity price risk; however, 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.

We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2014-2015 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 37 percent, or 28.2 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Nonregulated Commodity Risk Management Activities

Our nonregulated segment is exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. 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. Specifically, these operations use financial instruments in the following ways:

•

Gas delivery and related services - Certain financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, are used to mitigate the commodity price risk associated with deliveries under fixed-priced forward contracts to either deliver gas to customers or purchase gas from suppliers. These financial instruments have maturity dates ranging from one to 52 months.

•

Transportation and storage services - Our nonregulated operations 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.


•	Aggregating and purchasing gas supply - Certain financial instruments, designated as fair value hedges, are used to hedge our natural gas inventory used in asset optimization activities.

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, 2015, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $250 million and $450 million unsecured senior notes in fiscal 2017 and fiscal 2019, at 3.37% and 3.78%, which we designated as cash flow hedges at the time the swaps were executed. As of June 30, 2015, we had $18.7 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.

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, 2015, 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, 2015, we had net long/(short) commodity contracts outstanding in the following quantities:



Contract Type	Hedge Designation	Regulated Distribution	Nonregulated
		Quantity (MMcf)
Commodity contracts	Fair Value	—	(25,020	)
	Cash Flow	—	55,158
	Not designated	14,609	65,577
		14,609	95,715

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, 2015 and September 30, 2014. 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.



		Regulated Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets			Liabilities
		(In thousands)
June 30, 2015
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	8,465		$	(31,422	)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			476			(7,591		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	570		(47,224		)	—			—
Total		570		(47,224		)	8,941			(39,013		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	780		(4,916		)	86,265			(78,374		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	539		—			9,000			(7,336		)
Total		1,319		(4,916		)	95,265			(85,710		)
Gross Financial Instruments		1,889		(52,140		)	104,206			(124,723		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—			(104,206		)	104,206
Net Financial Instruments		1,889		(52,140		)	—			(20,517		)
Cash collateral		—		—			10,806			20,517
Net Assets/Liabilities from Risk Management Activities		$	1,889	$	(52,140	)	$	10,806		$	—



		Regulated Distribution					Nonregulated
	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
		(In thousands)
September 30, 2014
Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	$	—	$	—		$	8,912	$	(7,082	)
Interest rate contracts	Other current assets / Other current liabilities	21,869		—			—		—
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		—			757		(2,459		)
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	12,608		(19,835		)	—		—
Total		34,477		(19,835		)	9,669		(9,541		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	1,233		(1,730		)	43,677		(47,729		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	430