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,~~December 31, 2017



¨	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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large Accelerated Filer þ	Accelerated Filer ¨	Non-Accelerated Filer ¨	Smaller Reporting Company ¨	Emerging growth company ¨

(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 28, 2017.~~February 1, 2018.



Class		Shares Outstanding
No Par Value		~~106,065,596~~110,967,636

GLOSSARY OF KEY TERMS




Adjusted diluted EPS from continuing operations	Non-GAAP measure defined as diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit
Adjusted income from continuing operations	Non-GAAP measure defined as income from continuing operations before the one-time, non-cash income tax benefit
AEC	Atmos Energy Corporation
AEH	Atmos Energy Holdings, Inc.
AEM	Atmos Energy Marketing, LLC
AOCI	Accumulated other comprehensive income
ARM	Annual Rate Mechanism
Bcf	Billion cubic feet
DARR	Dallas Annual Rate Review
ERISA	Employee Retirement Income Security Act of 1974
FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
Gross Profit	Non-GAAP measure defined as operating revenues less purchased gas cost
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
RSC	Rate Stabilization Clause
S&P	Standard & Poor’s Corporation
SAVE	Steps to Advance Virginia Energy
SEC	United States Securities and Exchange Commission
SGR	Supplemental Growth Filing
SIR	System Integrity Rider
SRF	Stable Rate Filing
SSIR	System Safety and Integrity Rider
TCJA	Tax Cuts and Jobs Act of 2017
WNA	Weather Normalization Adjustment

PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2017			September 30, 2016			December 31, 2017			September 30, 2017
	(Unaudited)						(Unaudited)
	(In thousands, except share data)						(In thousands, except share data)
ASSETS
Property, plant and equipment	$	10,952,422		$	10,142,506		$	11,609,627		$	11,301,304
Less accumulated depreciation and amortization	2,028,041			1,873,900			2,090,835			2,042,122
Net property, plant and equipment	8,924,381			8,268,606			9,518,792			9,259,182
Current assets
Cash and cash equivalents	69,777			47,534			54,750			26,409
Accounts receivable, net	250,224			215,880			489,217			222,263
Gas stored underground	151,656			179,070			163,959			184,653
Current assets of disposal group classified as held for sale	—			151,117
Other current assets	62,725			88,085			70,984			106,321
Total current assets	534,382			681,686			778,910			539,646
Goodwill	729,673			726,962			730,132			730,132
Noncurrent assets of disposal group classified as held for sale	—			28,616
Deferred charges and other assets	310,339			305,019			236,886			220,636
	$	10,498,775		$	10,010,889		$	11,264,720		$	10,749,596
CAPITALIZATION AND LIABILITIES
Shareholders’ equity
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2017 — 106,059,875 shares; September 30, 2016 — 103,930,560 shares	$	530		$	520
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2017 — 110,962,112 shares; September 30, 2017 — 106,104,634 shares							$	555		$	531
Additional paid-in capital	2,525,752			2,388,027			2,940,062			2,536,365
Accumulated other comprehensive loss	(104,599		)	(188,022		)	(106,316		)	(105,254		)
Retained earnings	1,480,027			1,262,534			1,729,319			1,467,024
Shareholders’ equity	3,901,710			3,463,059			4,563,620			3,898,666
Long-term debt	3,066,734			2,188,779			3,067,469			3,067,045
Total capitalization	6,968,444			5,651,838			7,631,089			6,965,711
Current liabilities
Accounts payable and accrued liabilities	164,365			196,485			285,675			233,050
Current liabilities of disposal group classified as held for sale	—			72,900
Other current liabilities	322,721			439,085			336,919			332,648
Short-term debt	258,573			829,811			336,816			447,745
Current maturities of long-term debt	—			250,000
Total current liabilities	745,659			1,788,281			959,410			1,013,443
Deferred income taxes	1,853,564			1,603,056			1,033,206			1,878,699
Regulatory excess deferred taxes (See Note 6)							746,246			—
Regulatory cost of removal obligation	457,060			424,281			480,086			485,420
Pension and postretirement liabilities	304,919			297,743			233,337			230,588
Noncurrent liabilities of disposal group held for sale	—			316
Deferred credits and other liabilities	169,129			245,374			181,346			175,735
	$	10,498,775		$	10,010,889		$	11,264,720		$	10,749,596

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended June 30						Three Months Ended December 31
	2017			2016			2017			2016
	(Unaudited) (In thousands, except per share data)						(Unaudited) (In thousands, except per share data)
Operating revenues
Distribution segment	$	494,060		$	424,905		$	860,792		$	754,656
Pipeline and storage segment	117,283			113,855			126,463			109,952
Intersegment eliminations	(84,842		)	(82,548		)	(98,063		)	(84,440		)
Total operating revenues	526,501			456,212			889,192			780,168

Purchased gas cost
Distribution segment	197,767			147,569			463,758			395,346
Pipeline and storage segment	1,251			(438		)	912			355
Intersegment eliminations	(84,842		)	(82,548		)	(97,753		)	(84,396		)
Total purchased gas cost	114,176			64,583			366,917			311,305
Operation and maintenance expense	128,690			131,388			129,567			124,938
Depreciation and amortization expense	80,023			72,880			88,374			76,958
Taxes, other than income	62,948			58,965			62,773			57,049
Operating income	140,664			128,396			241,561			209,918
Miscellaneous (expense) income	(289		)	1,118
Miscellaneous expense, net							(2,035		)	(994		)
Interest charges	28,498			27,679			31,509			31,030
Income from continuing operations before income taxes	111,877			101,835			208,017			177,894
Income tax expense	41,069			35,692
Income tax (benefit) expense							(106,115		)	63,856
Income from continuing operations	70,808			66,143			314,132			114,038
Income from discontinued operations, net of tax ($0 and $3,414)	—			5,050
Net Income	$	70,808		$	71,193
Income from discontinued operations, net of tax ($0 and $6,841)							—			10,994
Net income							$	314,132		$	125,032
Basic and diluted net income per share
Income per share from continuing operations	$	0.67		$	0.64		$	2.89		$	1.08
Income per share from discontinued operations	—			0.05			—			0.11
Net income per share - basic and diluted	$	0.67		$	0.69		$	2.89		$	1.19
Cash dividends per share	$	0.45		$	0.42		$	0.485		$	0.450
Basic and diluted weighted average shares outstanding	106,364			103,750			108,564			105,284

See accompanying notes to condensed consolidated financial statements.

~~ATMOS ENERGY CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME~~

Nine Months Ended
June 30
2017 2016

(Unaudited)
(In thousands, except per
share data)
Operating revenues
Distribution segment $ 2,211,257
$ 1,936,475
Pipeline and storage segment 339,207
314,424
Intersegment eliminations (255,609 ) (229,894 )
Total operating revenues 2,294,855
2,021,005

Purchased gas cost
Distribution segment 1,106,209
912,231
Pipeline and storage segment 2,331
(72 )
Intersegment eliminations (255,565 ) (229,894 )
Total purchased gas cost 852,975
682,265
Operation and maintenance expense 385,867
379,073
Depreciation and amortization expense 234,648
214,927
Taxes, other than income 185,611
171,959
Operating income 635,754
572,781
Miscellaneous expense (450 ) (90 )
Interest charges 86,472
84,775
Income from continuing operations before income taxes 548,832
487,916
Income tax expense 201,974
177,224
Income from continuing operations 346,858
310,692
Income from discontinued operations, net of tax ($6,841 and $3,495) 10,994
5,172
Gain on sale of discontinued operations, net of tax ($10,215 and $0) 2,716
—
Net Income $ 360,568
$ 315,864
Basic and diluted net income per share
Income per share from continuing operations $ 3.27
$ 3.01
Income per share from discontinued operations 0.13
0.05
Net income per share - basic and diluted $ 3.40
$ 3.06
Cash dividends per share $ 1.35
$ 1.26
Basic and diluted weighted average shares outstanding 105,862
103,137

~~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					Three Months Ended December 31
	2017			2016			2017		2016			2017			2016
	(Unaudited) (In thousands)											(Unaudited) (In thousands)
Net income	$	70,808		$	71,193		$	360,568	$	315,864		$	314,132		$	125,032
Other comprehensive income (loss), net of tax
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $490, $110, $893 and $(837)	851			151			1,553		(1,496		)
Net unrealized holding losses on available-for-sale securities, net of tax of $62 and $476												(107		)	(828		)
Cash flow hedges:
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(10,667), $(22,561), $44,194 and $(50,631)	(18,556		)	(39,250		)	76,888		(88,085		)
Net unrealized gains on commodity cash flow hedges, net of tax of $0, $11,575, $3,183 and $13,220	—			18,105			4,982		20,678
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(549) and $52,429												(955		)	91,214
Net unrealized gains on commodity cash flow hedges, net of tax of $0 and $3,183												—			4,982
Total other comprehensive income (loss)	(17,705		)	(20,994		)	83,423		(68,903		)	(1,062		)	95,368
Total comprehensive income	$	53,103		$	50,199		$	443,991	$	246,961		$	313,070		$	220,400

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended June 30						Three Months Ended December 31
	2017			2016			2017			2016
	(Unaudited) (In thousands)						(Unaudited) (In thousands)
Cash Flows From Operating Activities
Net income	$	360,568		$	315,864		$	314,132		$	125,032
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	234,833			216,670			88,374			77,143
Deferred income taxes	188,256			171,042			53,149			67,241
Gain on sale of discontinued operations	(12,931		)	—
One-time income tax benefit							(161,884		)	—
Discontinued cash flow hedging for natural gas marketing commodity contracts	(10,579		)	—			—			(10,579		)
Other	14,892			14,430			6,915			4,842
Net assets / liabilities from risk management activities	25,661			7,973			2,030			3,969
Net change in operating assets and liabilities	(55,139		)	(96,033		)	(129,478		)	(150,685		)
Net cash provided by operating activities	745,561			629,946			173,238			116,963
Cash Flows From Investing Activities
Capital expenditures	(812,148		)	(789,688		)	(383,238		)	(297,962		)
Acquisition	(86,128		)	—			—			(85,714		)
Proceeds from the sale of discontinued operations	140,253			—
Available-for-sale securities activities, net	(14,329		)	558			(135		)	(10,263		)
Use tax refund	18,562			—
Other, net	6,435			5,731			2,001			1,802
Net cash used in investing activities	(747,355		)	(783,399		)	(381,372		)	(392,137		)
Cash Flows From Financing Activities
Net (decrease) increase in short-term debt	(571,238		)	212,539			(110,929		)	110,936
Net proceeds from equity offering	98,755			98,660			395,099			49,400
Issuance of common stock through stock purchase and employee retirement plans	22,673			26,500			5,660			8,998
Proceeds from issuance of long-term debt	884,911			—			—			125,000
Settlement of interest rate agreements	(36,996		)	—
Interest rate agreements cash collateral	25,670			(16,330		)	—			25,670
Repayment of long-term debt	(250,000		)	—
Cash dividends paid	(143,075		)	(130,363		)	(51,837		)	(47,740		)
Debt issuance costs	(6,663		)	—
Other							(1,518		)	—
Net cash provided by financing activities	24,037			191,006			236,475			272,264
Net increase in cash and cash equivalents	22,243			37,553
Net increase (decrease) in cash and cash equivalents							28,341			(2,910		)
Cash and cash equivalents at beginning of period	47,534			28,653			26,409			47,534
Cash and cash equivalents at end of period	$	69,777		$	66,206		$	54,750		$	44,624

See accompanying notes to condensed consolidated financial statements.

ATMOS ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~June 30,~~December 31, 2017

1. Nature of Business

Atmos Energy Corporation (“Atmos Energy” or the “Company”) is engaged in the regulated natural gas distribution and pipeline and storage businesses. Our ~~regulated businesses are~~distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our regulated divisions and subsidiaries operate.

Our distribution business delivers natural gas through sales and transportation arrangements to ~~approximately~~over three million residential, commercial, public authority and industrial customers through our six ~~natural gas~~regulated distribution divisions, which at ~~June 30,~~December 31, 2017, covered service areas located in eight states.

Our pipeline and storage business, which is also subject to federal and state regulations, includes the transportation of natural gas to our Texas and Louisiana distribution systems and the management of our underground storage facilities used to support ~~Texas~~our distribution ~~businesses.~~

Effective January 1, 2017, we completed the sale of all of the equity interests of Atmos Energy Marketing (AEM) to CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES). Accordingly, AEM’s historical financial results are reflectedbusiness in the Company’s condensed consolidated financial statements as discontinued operations, which required retrospective application to financial information for all periods presented. Refer to Note 6 for further information. Our discontinued natural gas marketing segment was primarily engaged in a nonregulated natural gas marketing business, conducted by AEM. This business provided natural gas management and transportation services to municipalities, regulated distribution companies, including certain divisions of Atmos Energy and third parties.various states.

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, ~~2016, which appear in Exhibit 99.1 to our Current Report on Form 8-K dated April 12, 2017 (the "Fiscal 2016 Financial Statements").~~2017. 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 ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. Because of seasonal and other factors, the results of operations for the ~~nine-month~~three-month period ended ~~June 30,~~December 31, 2017 are not indicative of our results of operations for the full ~~2017~~2018 fiscal year, which ends September 30, ~~2017.~~2018.

~~During~~Except for the ~~third quarter, we completed a State~~actions of ~~Texas use~~our regulators regarding tax ~~audit that covered~~reform as discussed in Note 6 and the ~~period from October 2011~~receipt of funds held in escrow related to ~~March 2017, which resulted in a refund~~the prior year sale of $29.8 million. We concluded the appropriate regulatory treatment of this refund was to reduce rate base. We received $18.7 million during the third quarter, which has been included in cash flows from investing activities, and recorded an $11.1 million receivable as of June 30, 2017.

On January 6, 2017, our Atmos Pipeline - Texas Division filed its statement of intent seeking $63.6 million, as adjusted in its rebuttal case, in additional annual operating income. On August 1, 2017, a final order was issued in our APT rate case resulting in a $13.0 million increase in annual operating income. No otherAEM, 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 ~~of our Fiscal 2016 Financial Statements.~~

~~As discussed in Note 3, due~~ to the ~~realignment of~~consolidated financial statements in our ~~reportable segments, prior periods' segment information has been recast in accordance with applicable accounting guidance. Additionally, as discussed in Note 6, due to~~Annual Report on Form 10-K for the sale of AEM, prior period amounts have been presented as discontinued operations. The segment realignment and the presentation of discontinued operations have not impacted our reported net income, financial position or cash flows.

~~During the second quarter of~~ fiscal ~~2017, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.~~year ended September 30, 2017.

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, an entity 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 may need to use more judgment and make more estimates than under current guidance.

The new guidance will become effective for us 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.

As of ~~June 30,~~December 31, 2017, we ~~have~~had substantially completed the evaluation of our sources of revenue and ~~are currently assessing~~ the ~~effect~~impact that the new guidance will have on our financial position, results of operations, cash flows and business processes. The conclusion of our assessment is contingent, in part, upon the completion of deliberations currently in progress by our industry, notably in connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants (AICPA).

In association with this undertaking, the AICPA formed a number of industry task forces, including a Power & Utilities (P&U) Task Force. Industry representatives and organizations, the largest auditing firms, the AICPA’s Revenue Recognition Working Group and its Financial Reporting Executive Committee have undertaken, and continue to undertake, consideration of several items relevant to our industry as further discussed below. Where applicable or necessary, the FASB’s Transition Resource Group (TRG) is also participating.

Additionally, we are actively working with our peers in the rate-regulated natural gas industry and with the public accounting profession to conclude on the accounting treatment for several other issues that are not expected to be addressed by the P&U Task Force. Based on ~~the progress of these deliberations to date,~~this evaluation, we currently do not believe the implementation of the new guidance will have a material effect on our financial position, results of operations, cash flows or business processes. We expect to apply the new guidance using the modified retrospective method on the date of adoption. We are currently still evaluating the ~~transition method we will utilize to adopt the new guidance as well as the~~ impact toon our financial statement presentation and related disclosures.

In May 2015, the FASB issued guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The guidance was effective for us on October 1, 2016, to be applied retrospectively. We measure certain pension plan assets using the net asset value per share practical expedient, which are disclosed on an annual basis in our Form 10-K. The adoption of the new standard should have no material impact on our results of operations, consolidated balance sheets or cash flows.

In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning October 1, 2018; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adoption is permitted. The new leasing standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the

earliest comparative period presented in the year of adoption. ~~As of June 30, 2017, we had begun~~Additionally, in January 2018, the ~~process of identifying and categorizing our lease contracts, evaluating our~~FASB issued amendments to the standard that provides a practical expedient for entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current ~~business processes and identifying a lease software solution.~~guidance. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations and cash flows.

In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

In January 2017, the FASB issued new guidance that simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The new standard will be effective for our fiscal 2021 goodwill impairment test; however, early adoption is permitted for goodwill impairment tests performed on testing dates after January 1, 2017. ~~The adoption of~~We have elected to early adopt the new standard, which will be effective for our goodwill impairment test performed in our second fiscal quarter. We do not anticipate the new standard will have noa material impact on our results of operations, consolidated balance sheets or cash flows.

In March 2017, the FASB issued new guidance related to the income statement presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit cost from the other components and present it with other current compensation costs for related employees in the statement of income. The other components of net

benefit cost will be presented outside of income from operations on the statement of income. In addition, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). However, we believe that we will be allowed to defer the other components of net periodic benefit cost as a regulatory asset and that we will still be allowed to capitalize all components of net periodic benefit cost for ratemaking purposes. The new guidance iswill be effective for us in the fiscal year beginning on October 1, 2018 and for interim periods within that year. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.

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~~a portion 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~~our regulatory excess deferred taxes and regulatory cost of removal obligation is reported separately.

Significant regulatory assets and liabilities as of ~~June 30,~~December 31, 2017 and September 30, ~~2016~~2017 included the following:


	June 30, 2017		September 30, 2016		December 31, 2017		September 30, 2017
	(In thousands)				(In thousands)
Regulatory assets:
Pension and postretirement benefit costs⁽¹⁾	$	122,202	$	132,348	$	24,598	$	26,826
Infrastructure mechanisms⁽²⁾	38,653		42,719		54,571		46,437
Deferred gas costs	16,405		45,184		18,505		65,714
Recoverable loss on reacquired debt	11,843		13,761		10,580		11,208
Deferred pipeline record collection costs	10,327		7,336		12,942		11,692
APT annual adjustment mechanism	4,973		7,171		—		2,160
Rate case costs	2,480		1,539		3,160		2,629
Other	9,949		13,565		9,703		10,132
	$	216,832	$	263,623	$	134,059	$	176,798
Regulatory liabilities:
Regulatory cost of removal obligations	$	492,404	$	476,891
Regulatory excess deferred taxes⁽³⁾					$	746,246	$	—
Regulatory cost of removal obligation					520,483		521,330
Deferred gas costs	16,753		20,180		19,739		15,559
Asset retirement obligations	13,404		13,404
Asset retirement obligation					12,827		12,827
APT annual adjustment mechanism					1,720		—
Other	6,729		4,250		7,673		5,941
	$	529,290	$	514,725	$	1,308,688	$	555,657


(1)	Includes ~~$11.5~~$8.6 million and ~~$12.4~~$9.4 million of pension and postretirement expense deferred pursuant to regulatory authorization.


(2)	Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.


(3)	The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. The excess deferred taxes will be returned to utility customers in accordance with regulatory requirements. See Note 6 for further information.

3. Segment Information

~~Through November 30, 2016, our consolidated operations were managed~~ We manage and ~~reviewed through three segments:~~

~~The~~ ~~regulated distribution segment, which included our regulated natural gas distribution and related sales operations.~~

~~The~~ ~~regulated pipeline segment, which included the pipeline and storage operations of our Atmos Pipeline-Texas division and,~~

~~The~~ ~~nonregulated segment, which included our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.~~

As a result of the announced sale of Atmos Energy Marketing, we revised the information used by the chief operating decision maker to manage the Company, effective December 1, 2016. Accordingly, we have been managing and reviewingreview our consolidated operations through the following ~~three~~ reportable segments:

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight ~~states and storage assets located in Kentucky and Tennessee, which are used solely to support our natural gas distribution operations in those~~ states. ~~These storage assets were formerly included in our nonregulated segment.~~

The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in ~~Louisiana, which were formerly included in our nonregulated segment.~~Louisiana.

The natural gas marketing segment iswas comprised of our discontinued natural gas marketing business.

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 distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. We evaluate performance based on net income or loss of the respective operating ~~segments.~~units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.

~~Prior periods'~~ Income taxes are allocated to each segment ~~information has been recast~~ as ~~required by applicable accounting guidance. The segment realignment has not impacted our reported consolidated revenues or net income.~~ if each segment’s taxes were calculated on a separate return basis.

Income statements and capital expenditures for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2017 and 2016 by segment are presented in the following tables:


	Three Months Ended June 30, 2017														Three Months Ended December 31, 2017
	Distribution			Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated			Distribution			Pipeline and Storage			Eliminations			Consolidated
	(In thousands)														(In thousands)
Operating revenues from external parties	$	493,738		$	32,763		$	—	$	—		$	526,501		$	860,453		$	28,739		$	—		$	889,192
Intersegment revenues	322			84,520			—		(84,842		)	—			339			97,724			(98,063		)	—
Total operating revenues	494,060			117,283			—		(84,842		)	526,501			860,792			126,463			(98,063		)	889,192
Purchased gas cost	197,767			1,251			—		(84,842		)	114,176			463,758			912			(97,753		)	366,917
Operation and maintenance expense	99,631			29,059			—		—			128,690			103,737			26,140			(310		)	129,567
Depreciation and amortization expense	62,760			17,263			—		—			80,023			65,434			22,940			—			88,374
Taxes, other than income	56,850			6,098			—		—			62,948			55,107			7,666			—			62,773
Operating income	77,052			63,612			—		—			140,664			172,756			68,805			—			241,561
Miscellaneous expense	(62		)	(227		)	—		—			(289		)	(1,400		)	(635		)	—			(2,035		)
Interest charges	18,394			10,104			—		—			28,498			21,368			10,141			—			31,509
Income before income taxes	58,596			53,281			—		—			111,877			149,988			58,029			—			208,017
Income tax expense	22,082			18,987			—		—			41,069
Income tax benefit															(99,111		)	(7,004		)	—			(106,115		)
Net income	$	36,514		$	34,294		$	—	$	—		$	70,808		$	249,099		$	65,033		$	—		$	314,132
Capital expenditures	$	205,780		$	46,983		$	—	$	—		$	252,763		$	241,249		$	141,989		$	—		$	383,238


	Three Months Ended June 30, 2016												Three Months Ended December 31, 2016
	Distribution		Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated		Distribution			Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated
	(In thousands)												(In thousands)
Operating revenues from external parties	$	424,553	$	31,659		$	—	$	—		$	456,212	$	754,266		$	25,902		$	—	$	—		$	780,168
Intersegment revenues	352		82,196			—		(82,548		)	—		390			84,050			—		(84,440		)	—
Total operating revenues	424,905		113,855			—		(82,548		)	456,212		754,656			109,952			—		(84,440		)	780,168
Purchased gas cost	147,569		(438		)	—		(82,548		)	64,583		395,346			355			—		(84,396		)	311,305
Operation and maintenance expense	101,819		29,569			—		—			131,388		92,714			32,268			—		(44		)	124,938
Depreciation and amortization expense	59,193		13,687			—		—			72,880		61,157			15,801			—		—			76,958
Taxes, other than income	52,662		6,303			—		—			58,965		50,546			6,503			—		—			57,049
Operating income	63,662		64,734			—		—			128,396		154,893			55,025			—		—			209,918
Miscellaneous income (expense)	1,243		(125		)	—		—			1,118
Miscellaneous expense													(633		)	(361		)	—		—			(994		)
Interest charges	18,677		9,002			—		—			27,679		21,118			9,912			—		—			31,030
Income from continuing operations before income taxes	46,228		55,607			—		—			101,835		133,142			44,752			—		—			177,894
Income tax expense	15,867		19,825			—		—			35,692		47,778			16,078			—		—			63,856
Income from continuing operations	30,361		35,782			—		—			66,143		85,364			28,674			—		—			114,038
Income from discontinued operations, net of tax	—		—			5,050		—			5,050		—			—			10,994		—			10,994
Net income	$	30,361	$	35,782		$	5,050	$	—		$	71,193	$	85,364		$	28,674		$	10,994	$	—		$	125,032
Capital expenditures	$	187,470	$	66,108		$	106	$	—		$	253,684	$	222,484		$	75,478		$	—	$	—		$	297,962

Nine Months Ended June 30, 2017
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
Operating revenues from external parties $ 2,210,221
$ 84,634
$ —
$ —
$ 2,294,855
Intersegment revenues 1,036
254,573
—
(255,609 ) —
Total operating revenues 2,211,257
339,207
—
(255,609 ) 2,294,855
Purchased gas cost 1,106,209
2,331
—
(255,565 ) 852,975
Operation and maintenance expense 296,048
89,863
—
(44 ) 385,867
Depreciation and amortization expense 185,219
49,429
—
—
234,648
Taxes, other than income 165,032
20,579
—
—
185,611
Operating income 458,749
177,005
—
—
635,754
Miscellaneous income (expense) 334
(784 ) —
—
(450 )
Interest charges 56,437
30,035
—
—
86,472
Income from continuing operations before income taxes 402,646
146,186
—
—
548,832
Income tax expense 149,623
52,351
—
—
201,974
Income from continuing operations 253,023
93,835
—
—
346,858
Income from discontinued operations, net of tax —
—
10,994
—
10,994
Gain on sale of discontinued operations, net of tax —
—
2,716
—
2,716
Net income $ 253,023
$ 93,835
$ 13,710
$ —
$ 360,568
Capital expenditures $ 636,449
$ 175,699
$ —
$ —
$ 812,148

Nine Months Ended June 30, 2016
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
Operating revenues from external parties $ 1,935,421
$ 85,584
$ —
$ —
$ 2,021,005
Intersegment revenues 1,054
228,840
—
(229,894 ) —
Total operating revenues 1,936,475
314,424
—
(229,894 ) 2,021,005
Purchased gas cost 912,231
(72 ) —
(229,894 ) 682,265
Operation and maintenance expense 294,154
84,919
—
—
379,073
Depreciation and amortization expense 174,748
40,179
—
—
214,927
Taxes, other than income 153,198
18,761
—
—
171,959
Operating income 402,144
170,637
—
—
572,781
Miscellaneous income (expense) 804
(894 ) —
—
(90 )
Interest charges 57,481
27,294
—
—
84,775
Income from continuing operations before income taxes 345,467
142,449
—
—
487,916
Income tax expense 126,090
51,134
—
—
177,224
Income from continuing operations 219,377
91,315
—
—
310,692
Income from discontinued operations, net of tax —
—
5,172
—
5,172
Net income $ 219,377
$ 91,315
$ 5,172
$ —
$ 315,864
Capital expenditures $ 528,063
$ 261,446
$ 179
$ —
$ 789,688

Balance sheet information at ~~June 30,~~December 31, 2017 and September 30, ~~2016~~2017 by segment is presented in the following tables:

June 30, 2017
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
ASSETS
Property, plant and equipment, net $ 6,678,875
$ 2,245,506
$ —
$ —
$ 8,924,381
Investment in subsidiaries 798,994
13,851
—
(812,845 ) —
Current assets
Cash and cash equivalents 69,777
—
—
—
69,777
Other current assets 437,700
29,265
—
(2,360 ) 464,605
Intercompany receivables 983,866
—
—
(983,866 ) —
Total current assets 1,491,343
29,265
—
(986,226 ) 534,382
Goodwill 586,661
143,012
—
—
729,673
Deferred charges and other assets 280,240
30,099
—
—
310,339
$ 9,836,113
$ 2,461,733
$ —
$ (1,799,071 ) $ 10,498,775
CAPITALIZATION AND LIABILITIES
Shareholders’ equity $ 3,901,710
$ 812,845
$ —
$ (812,845 ) $ 3,901,710
Long-term debt 3,066,734
—
—
—
3,066,734
Total capitalization 6,968,444
812,845
—
(812,845 ) 6,968,444
Current liabilities
Short-term debt 258,573
—
—
—
258,573
Other current liabilities 451,026
38,420
—
(2,360 ) 487,086
Intercompany payables —
983,866
—
(983,866 ) —
Total current liabilities 709,599
1,022,286
—
(986,226 ) 745,659
Deferred income taxes 1,251,528
602,036
—
—
1,853,564
Regulatory cost of removal obligation 432,531
24,529
—
—
457,060
Pension and postretirement liabilities 304,919
—
—
—
304,919
Deferred credits and other liabilities 169,092
37
—
—
169,129
$ 9,836,113
$ 2,461,733
$ —
$ (1,799,071 ) $ 10,498,775



	December 31, 2017
	Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)
Property, plant and equipment, net	$	7,010,709	$	2,508,083	$	—		$	9,518,792
Total assets	$	10,633,234	$	2,729,455	$	(2,097,969	)	$	11,264,720

September 30, 2016
Distribution Pipeline and Storage Natural Gas Marketing Eliminations Consolidated
(In thousands)
ASSETS
Property, plant and equipment, net $ 6,208,465
$ 2,060,141
$ —
$ —
$ 8,268,606
Investment in subsidiaries 768,415
13,854
—
(782,269 ) —
Current assets
Cash and cash equivalents 22,117
—
25,417
—
47,534
Current assets of disposal group classified as held for sale —
—
162,508
(11,391 ) 151,117
Other current assets 489,963
39,078
5
(46,011 ) 483,035
Intercompany receivables 971,665
—
—
(971,665 ) —
Total current assets 1,483,745
39,078
187,930
(1,029,067 ) 681,686
Goodwill 583,950
143,012
—
—
726,962
Noncurrent assets of disposal group classified as held for sale —
—
28,785
(169 ) 28,616
Deferred charges and other assets 277,240
27,779
—
—
305,019
$ 9,321,815
$ 2,283,864
$ 216,715
$ (1,811,505 ) $ 10,010,889
CAPITALIZATION AND LIABILITIES
Shareholders’ equity $ 3,463,059
$ 715,672
$ 66,597
$ (782,269 ) $ 3,463,059
Long-term debt 2,188,779
—
—
—
2,188,779
Total capitalization 5,651,838
715,672
66,597
(782,269 ) 5,651,838
Current liabilities
Current maturities of long-term debt 250,000
—
—
—
250,000
Short-term debt 829,811
—
35,000
(35,000 ) 829,811
Current liabilities of the disposal group classified as held for sale —
—
81,908
(9,008 ) 72,900
Other current liabilities 605,790
39,911
3,263
(13,394 ) 635,570
Intercompany payables —
957,526
14,139
(971,665 ) —
Total current liabilities 1,685,601
997,437
134,310
(1,029,067 ) 1,788,281
Deferred income taxes 1,055,348
543,390
4,318
—
1,603,056
Regulatory cost of removal obligation 397,162
27,119
—
—
424,281
Pension and postretirement liabilities 297,743
—
—
—
297,743
Noncurrent liabilities of disposal group classified as held for sale —
—
316
—
316
Deferred credits and other liabilities 234,123
246
11,174
(169 ) 245,374
$ 9,321,815
$ 2,283,864
$ 216,715
$ (1,811,505 ) $ 10,010,889



	September 30, 2017
	Distribution		Pipeline and Storage		Eliminations			Consolidated
	(In thousands)
Property, plant and equipment, net	$	6,849,517	$	2,409,665	$	—		$	9,259,182
Total assets	$	10,050,164	$	2,621,601	$	(1,922,169	)	$	10,749,596

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,~~December 31, 2017 and 2016 are calculated as follows:


	Three Months Ended June 30				Nine Months Ended June 30				Three Months Ended December 31
	2017		2016		2017		2016		2017		2016
	(In thousands, except per share amounts)								(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share from continuing operations
Income from continuing operations	$	70,808	$	66,143	$	346,858	$	310,692	$	314,132	$	114,038
Less: Income from continuing operations allocated to participating securities	75		100		424		488		328		153
Income from continuing operations available to common shareholders	$	70,733	$	66,043	$	346,434	$	310,204	$	313,804	$	113,885
Basic and diluted weighted average shares outstanding	106,364		103,750		105,862		103,137		108,564		105,284
Income from continuing operations per share — Basic and Diluted	$	0.67	$	0.64	$	3.27	$	3.01	$	2.89	$	1.08

Basic and Diluted Earnings Per Share from discontinued operations
Income from discontinued operations	$	—	$	5,050	$	13,710	$	5,172	$	—	$	10,994
Less: Income from discontinued operations allocated to participating securities	—		6		15		4		—		14
Income from discontinued operations available to common shareholders	$	—	$	5,044	$	13,695	$	5,168	$	—	$	10,980
Basic and diluted weighted average shares outstanding	106,364		103,750		105,862		103,137		108,564		105,284
Income from discontinued operations per share — Basic and Diluted	$	—	$	0.05	$	0.13	$	0.05	$	—	$	0.11
Net income per share — Basic and Diluted	$	0.67	$	0.69	$	3.40	$	3.06	$	2.89	$	1.19

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 ~~Fiscal 2016 Financial Statements. Except as noted below, there~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. There were no material changes in the terms of our debt instruments during the ~~nine~~three months ended ~~June 30,~~December 31, 2017.

Long-term debt at ~~June 30,~~December 31, 2017 and September 30, ~~2016~~2017 consisted of the following:


	June 30, 2017			September 30, 2016		December 31, 2017			September 30, 2017
	(In thousands)					(In thousands)
Unsecured 6.35% Senior Notes, due June 2017	$	—		$	250,000
Unsecured 8.50% Senior Notes, due 2019	450,000			450,000
Unsecured 8.50% Senior Notes, due March 2019						$	450,000		$	450,000
Unsecured 3.00% Senior Notes, due 2027	500,000			—		500,000			500,000
Unsecured 5.95% Senior Notes, due 2034	200,000			200,000		200,000			200,000
Unsecured 5.50% Senior Notes, due 2041	400,000			400,000		400,000			400,000
Unsecured 4.15% Senior Notes, due 2043	500,000			500,000		500,000			500,000
Unsecured 4.125% Senior Notes, due 2044	750,000			500,000		750,000			750,000
Medium-term note Series A, 1995-1, 6.67%, due 2025	10,000			10,000		10,000			10,000
Unsecured 6.75% Debentures, due 2028	150,000			150,000		150,000			150,000
Floating-rate term loan, due 2019	125,000			—
Floating-rate term loan, due September 2019⁽¹⁾						125,000			125,000
Total long-term debt	3,085,000			2,460,000		3,085,000			3,085,000
Less:
Original issue (premium) discount on unsecured senior notes and debentures	(4,370		)	4,270
Original issue premium / discount on unsecured senior notes and debentures						(4,398		)	(4,384		)
Debt issuance cost	22,636			16,951		21,929			22,339
Current maturities	—			250,000
	$	3,066,734		$	2,188,779	$	3,067,469		$	3,067,045

On June 8, 2017, we completed a public offering of $500 million of 3.00% senior notes due 2027 and $250 million of 4.125% senior notes due 2044. The effective rate of these notes is 3.12% and 4.40%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds (excluding the loss on the settlement of the interest rate swaps of $37 million) of approximately $753 million were used to repay our $250 million 6.35% senior unsecured notes at maturity on June 15, 2017 and for general corporate purposes, including the repayment of working capital borrowings pursuant to our commercial paper program.

On September 22, 2016, we entered into a three year, $200 million multi-draw floating-rate term loan agreement with a syndicate of three lenders. Borrowings under the term loan may be made in increments of $1.0 million or higher, may be repaid at any time during the loan period and will bear interest at a rate dependent upon our credit ratings at the time of such borrowing and based, at our election, on a base rate or LIBOR for the applicable interest period. The term loan was used to repay short-term debt and for working capital, capital expenditures and other general corporate purposes. At June 30, 2017, there was $125.0 million outstanding under the


(1)	Up to $200 million can be drawn under this term loan.

We utilize short-term debt to ~~fund ongoing working~~provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital ~~needs, such as our seasonal requirements for gas supply, general corporate liquidity~~structure with an equity–to–capitalization ratio between 50% and ~~capital expenditures.~~60%, inclusive of long–term and short–term debt. Our ~~short-term~~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~~short–term borrowings typically reach their highest levels in the winter months.

~~We currently finance~~Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility that expires September 25, 2021. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. ~~This facility was amended in October 2016 to increase the total availability from $1.25 billion.~~ At ~~June 30,~~December 31, 2017 and September 30, ~~2016~~2017 a total of ~~$258.6~~$336.8 million and ~~$829.8~~$447.7 million was outstanding under our commercial paper program.

Additionally, we have a $25 million 364-day unsecured facility ~~which was renewed on April 1, 2017,~~ and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At ~~June 30,~~December 31, 2017, there were no borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total amount available to us under our $10 million ~~unsecured revolving~~ facility to ~~$4.1~~$4.4 million.

The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of ~~total debt to total capitalization~~total-debt-to-total-capitalization of no greater than 70 percent. At ~~June 30,~~December 31, 2017, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 4744 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.

These credit facilities and our 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,~~December 31, 2017. 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.

AEM had one uncommitted $25 million 364-day bilateral credit facility that was scheduled to expire on July 31, 2017 and one committed $15 million 364-day bilateral credit facility that was scheduled to expire on September 30, 2017. In connection with the sale of AEM discussed in Note 6, both facilities were terminated on January 3, 2017.

6. ~~Divestitures~~Impact of the Tax Cuts and ~~Acquisitions~~Jobs Act of 2017

~~Divestiture~~On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. The TCJA introduced several significant changes to corporate income tax laws in the United States. The most significant change that will affect Atmos Energy ~~Marketing (AEM)~~

~~On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all~~is the reduction of the ~~equity interests~~federal statutory income tax rate from 35% to 21%. As a rate-regulated entity, the accelerated capital expensing and the limitation on interest deductibility provisions included in the TCJA are not applicable to us.

Under generally accepted accounting principles, we use the asset and liability method of ~~AEM.~~accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

At September 30, 2017, we measured our net deferred tax liability using the enacted federal statutory tax rate of 35%. The ~~transaction closed~~enactment of the TCJA on ~~January 3,~~December 22, 2017 ~~with an effective date~~required us to remeasure our deferred tax assets and liabilities, including our U.S. federal income tax net operating loss carryforwards, at the newly enacted federal statutory income tax rate. As the Company’s fiscal year end is September 30, the Internal Revenue Code requires the Company to use a blended statutory federal corporate income tax rate of ~~January 1, 2017. CES paid a cash purchase price of $38.3 million plus working capital of $109.0 million~~24.5% for ~~total cash consideration of $147.3~~fiscal 2018.

The decrease in the federal statutory income tax rate reduced our net deferred tax liability by $908.1 million. Of this amount, ~~$7.0~~$746.2 million ~~was placed into escrow~~relates to regulated operations and has been recorded as a regulatory liability, which will be returned to utility customers. The period and timing of these revenue adjustments are subject to Internal Revenue Code provisions and regulatory actions in each of the eight states in which we operate. The remaining $161.9 million has been reflected as a one-time income tax benefit in our condensed consolidated statement of income because these taxes were not considered in our cost of service ratemaking.

At December 31, 2017, we had $330.4 million of remeasured federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset future taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards that do not expire and are expected to be ~~paid~~fully refunded to us between 2019 and 2022 as a result of changes introduced by the TCJA. These credit carryforwards are now reflected as taxes receivable within the deferred charges and other assets line item on our condensed consolidated balance sheet. In addition, the Company has $5.1 million in remeasured charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expire between 2018 and 2023.

The Company also has $25.9 million of state net operating loss carryforwards and $1.5 million of state tax credit carryforwards (net of $6.9 million and $0.4 million of remeasured federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire between 2018 and 2032.

Due to the changes introduced by the TCJA, we now believe it is more likely than not that the benefit from certain charitable contribution carryforwards for which a valuation allowance was previously established will be realized. As a result, we reduced our valuation allowance by $4.2 million during the first quarter. This amount is included in the $161.9 million one-time income tax benefit.

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allows us to record provisional amounts during a one-year measurement period, similar to the measurement period in accounting for business combinations. The Company ~~within 24 months~~has determined a reasonable estimate for the measurement and accounting for certain effects of the ~~closing date,~~TCJA, including the remeasurement of our net deferred tax liabilities and the establishment of ~~any indemnification claims agreed~~a regulatory liability, which have been reflected as provisional amounts in the December 31, 2017 condensed consolidated financial statements and are described in further detail above. The amounts represent our best estimates based upon ~~between~~records, information and current guidance. We are still analyzing certain aspects of the ~~two companies.~~ TCJA, refining our calculations and expect additional guidance relating to the TCJA from the U.S. Department of the Treasury and the Internal Revenue Service. Any additional issued guidance or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the TCJA.

We ~~recognized~~are actively working with our regulators in each jurisdiction to address the impact of the TCJA on our cost of service based rates. Accounting orders have been issued for our Colorado, Kansas, Kentucky, Tennessee and Virginia service areas that require us to establish, effective January 1, 2018, a ~~net gain~~separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35% statutory income tax rate and the new 21% statutory income tax rate. The establishment of ~~$0.03 per diluted share on the sale~~this regulatory liability relating to our cost of service rates will result in a reduction to our revenues beginning in the second quarter of fiscal ~~2017~~2018. The period and ~~completed~~timing of the ~~working capital true–up during the third quarter~~return of ~~fiscal 2017.~~

~~The operating results~~these liabilities to utility customers will be determined by regulators in each of our ~~natural~~jurisdictions.

Regulators in our other services areas, including Texas, Mississippi and Louisiana, have also taken action in response to the TCJA:

• On January 23, 2018, the Railroad Commission of Texas directed the Commission Staff to develop recommendations to ensure that, beginning January 1, 2018, all gas ~~marketing reportable segment have been reported~~utility customers in Texas receive the full benefit of the TCJA.

•On January 26, 2018, the Mississippi Public Service Commission (MPSC) entered an order requiring each utility to file within thirty days a detailed description identifying how the TCJA will be reflected in the formula rate plan or other rate structures under which the utility operates.

•On January 31, 2018, Louisiana Public Service Commission (LPSC) directed utilities to file reports on the condensed consolidated statements of income as income from discontinued operations, net of income tax. Accordingly, expenses related to allocable general corporate overhead and interest expense are not included in these results. The decision to report this segmentFebruary 14, 2018, regarding savings for ratepayers as a discontinued operation was predicated, in part, on the following qualitative and quantitative factors: 1) the disposal resulted in the company becoming a fully regulated entity; 2) the fact that an entire reportable segment was disposed of and 3) the fact the disposed segment represented in excess of 30 percent of consolidated revenues over the last five fiscal years.

The tables below set forth selected financial and operational information related to assets, liabilities and operating results related to discontinued operations. Operating expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income. Additionally, assets and liabilities related to our natural gas marketing operations are classified as “held for sale” on our consolidated balance sheet at September 30, 2016. Prior period revenues and expenses associated with these assets have been reclassified into discontinued operations. This reclassification had no impact on previously reported consolidated net income.

~~The following tables present statement of income data related to discontinued operations:~~

Three Months Ended
June 30
2017 2016
(In thousands)

Operating revenues $ —
$ 200,213

Purchased gas cost —
184,398
Operating expenses —
7,047
Operating income —
8,768
Other nonoperating expense —
(304 )
Income from discontinued operations before income taxes —
8,464
Income tax expense —
3,414
Net income from discontinued operations $ —
$ 5,050

Nine Months Ended
June 30
2017 2016
(In thousands)

Operating revenues $ 303,474
$ 728,989

Purchased gas cost 277,554
698,445
Operating expenses 7,874
19,940
Operating income 18,046
10,604
Other nonoperating expense (211 ) (1,937 )
Income from discontinued operations before income taxes 17,835
8,667
Income tax expense 6,841
3,495
Income from discontinued operations 10,994
5,172
Gain on sale from discontinued operations, net of tax ($10,215 and $0) 2,716
—
Net income from discontinued operations $ 13,710
$ 5,172

~~The following table presents a reconciliation~~result of the ~~carrying amounts of major classes of assets~~new federal tax laws. The LPSC is also considering an accounting order to direct the utilities to track and ~~liabilities of our natural gas marketing's operations to total assets and liabilities classified as held for sale:~~

June 30, 2017 September 30, 2016
(In thousands)
Assets:
Net property, plant and equipment $ —
$ 11,905
Accounts receivable —
93,551
Gas stored underground —
54,246
Other current assets —
14,711
Goodwill —
16,445
Deferred charges and other assets —
435
Total assets of the disposal group classified as held for sale in the statement of financial position ⁽¹⁾
—
191,293
Cash —
25,417
Other assets —
5
Total assets of disposal group in the statement of financial position $ —
$ 216,715

Liabilities:
Accounts payable and accrued liabilities $ —
$ 72,268
Other current liabilities —
9,640
Deferred credits and other —
316
Total liabilities of the disposal group classified as held for sale in the statement of financial position ⁽¹⁾
—
82,224
Intercompany note payable —
35,000
Tax liabilities —
15,471
Intercompany payables —
14,139
Other liabilities —
3,284
Total liabilities of disposal group in the statement of financial position $ —
$ 150,118


~~(1)~~	~~Amounts in the comparative period are classified as current and long term in the statement of financial position.~~

~~The following table presents statement of cash flow data related to discontinued operations:~~

Nine Months Ended
June 30
2017 2016
(In thousands)
Depreciation and amortization expense $ 185
$ 1,743
Capital expenditures $ —
$ 179
Noncash gain (loss) in commodity contract cash flow hedges $ 18,744
$ (33,898 )

~~Acquisition of EnLink Pipeline~~

~~On December 20, 2016, we executed a purchase and sale agreement to acquire~~record the general partnership and limited partnership interests in EnLink North Texas Pipeline, LP (EnLink Pipeline) from EnLink Energy GP, LLC and EnLink Midstream Operating, LP for a cash purchase price of $85 million, plus working capital of $1.1 million.

~~EnLink Pipeline's primary asset was a 140–mile natural gas pipeline located on the north side~~impacts of the ~~Dallas–Fort Worth Metroplex. The $85 million purchase price has been allocated, based on fair value using observable market inputs,~~TCJA and a rule making docket to address the ~~net book value of the acquired pipeline.~~TCJA.

7. Shareholders' Equity

Shelf Registration, ~~and~~ At-the-Market Equity Sales Program and Equity Issuance

On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt ~~securities. We also~~securities, which expires March 28, 2019. At December 31, 2017, approximately $1.2 billion of securities remained available for issuance under the shelf registration statement.

On November 14, 2017, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity ~~distribution~~sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of ~~$200 million.~~$500 million, which expires March 28, 2019. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, ~~we sold 1,303,494~~no shares of common stock were sold under the ATM program.

On November 30, 2017, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 4,558,404 shares of our ~~existing ATM program for $100~~common stock. We received aggregate gross proceeds of $400 million and received net proceeds, after expenses, of ~~$98.8 million. At June 30, 2017, approximately $1.6 billion of securities remained available for issuance under~~$395.1 million from the ~~shelf registration statement and substantially all shares have been issued under our ATM program.~~offering.

Accumulated Other Comprehensive Income (Loss)

We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate cash flow hedges and prior to the sale of Atmos Energy Marketing on January 3, 2017, 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 (loss):

Available-
for-Sale
Securities

Interest
Rate
Agreement
Cash Flow
Hedges

Commodity
Contracts
Cash Flow
Hedges
Total
(In thousands)
September 30, 2016 $ 4,484
$ (187,524 ) $ (4,982 ) $ (188,022 )
Other comprehensive income before reclassifications 1,485
76,602
9,847
87,934
Amounts reclassified from accumulated other comprehensive income 68
286
(4,865 ) (4,511 )
Net current-period other comprehensive income 1,553
76,888
4,982
83,423
June 30, 2017 $ 6,037
$ (110,636 ) $ —
$ (104,599 )



	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Total
	(In thousands)
September 30, 2017	$	7,048		$	(112,302	)	$	(105,254	)
Other comprehensive loss before reclassifications	(107		)	(1,332		)	(1,439		)
Amounts reclassified from accumulated other comprehensive income	—			377			377
Net current-period other comprehensive loss	(107		)	(955		)	(1,062		)
December 31, 2017	$	6,941		$	(113,257	)	$	(106,316	)

Available-
for-Sale
Securities

Interest
Rate
Agreement
Cash Flow
Hedges

Commodity
Contracts
Cash Flow
Hedges
Total
(In thousands)
September 30, 2015 $ 4,949
$ (88,842 ) $ (25,437 ) $ (109,330 )
Other comprehensive loss before reclassifications (1,417 ) (88,345 ) (8,612 ) (98,374 )
Amounts reclassified from accumulated other comprehensive income (79 ) 260
29,290
29,471
Net current-period other comprehensive income (loss) (1,496 ) (88,085 ) 20,678
(68,903 )
June 30, 2016 $ 3,453
$ (176,927 ) $ (4,759 ) $ (178,233 )



	Available- for-Sale Securities			Interest Rate Agreement Cash Flow Hedges			Commodity Contracts Cash Flow Hedges			Total
	(In thousands)
September 30, 2016	$	4,484		$	(187,524	)	$	(4,982	)	$	(188,022	)
Other comprehensive income (loss) before reclassifications	(828		)	91,127			9,847			100,146
Amounts reclassified from accumulated other comprehensive income	—			87			(4,865		)	(4,778		)
Net current-period other comprehensive income (loss)	(828		)	91,214			4,982			95,368
December 31, 2016	$	3,656		$	(96,310	)	$	—		$	(92,654	)

The following tables detail reclassifications out of AOCI for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2017 and 2016. Amounts in parentheses below indicate decreases to net income in the statement of income:


	Three Months Ended June 30, 2017				Three Months Ended December 31, 2017
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)				(In thousands)
Cash flow hedges
Interest rate agreements	$	(177	)	Interest charges	$	(594	)	Interest charges
Commodity contracts	—			Purchased gas cost
	(177		)	Total before tax	(594		)	Total before tax
	64			Tax benefit	217			Tax benefit
Total reclassifications	$	(113	)	Net of tax	$	(377	)	Net of tax


	Three Months Ended June 30, 2016				Three Months Ended December 31, 2016
Accumulated Other Comprehensive Income Components	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income	Amount Reclassified from Accumulated Other Comprehensive Income			Affected Line Item in the Statement of Income
	(In thousands)				(In thousands)
Cash flow hedges
Interest rate agreements	$	(137	)	Interest charges	$	(137	)	Interest charges
Commodity contracts	(12,347		)	Purchased gas cost⁽¹⁾	7,967			Purchased gas cost⁽¹⁾
	(12,484		)	Total before tax	7,830			Total before tax
	4,865			Tax benefit	(3,052		)	Tax expense
Total reclassifications	$	(7,619	)	Net of tax	$	4,778		Net of tax

(1) Amounts are presented as part of income from discontinued operations in the condensed consolidated statements of income.

Nine Months Ended June 30, 2017
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 $ (107 ) Operation and maintenance expense
(107 ) Total before tax
39
Tax benefit
$ (68 ) Net of tax
Cash flow hedges
Interest rate agreements $ (450 ) Interest charges
Commodity contracts 7,976

Purchased gas cost⁽¹⁾
7,526
Total before tax
(2,947 ) Tax expense
$ 4,579
Net of tax
Total reclassifications $ 4,511
Net of tax

Nine Months Ended June 30, 2016
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 $ 124
Operation and maintenance expense
124
Total before tax
(45 ) Tax expense
$ 79
Net of tax
Cash flow hedges
Interest rate agreements $ (410 ) Interest charges
Commodity contracts (48,015 )
Purchased gas cost⁽¹⁾
(48,425 ) Total before tax
18,875
Tax benefit
$ (29,550 ) Net of tax
Total reclassifications $ (29,471 ) Net of tax



~~(1)~~	~~Amounts are presented as part of income from discontinued operations on the condensed consolidated statements of income.~~

8. Interim Pension and Other Postretirement Benefit Plan Information

The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2017 and 2016 are presented in the following table. Most of these costs are recoverable through our tariff rates; however, a portion of these costs is capitalized into our rate base. The remaining costs are recorded as a component of operation and maintenance expense.

Three Months Ended June 30
Pension Benefits Other Benefits
2017 2016 2017 2016
(In thousands)
Components of net periodic pension cost:
Service cost $ 5,216
$ 4,698
$ 3,109
$ 2,705
Interest cost 6,296
7,095
2,669
3,106
Expected return on assets (6,993 ) (6,881 ) (1,796 ) (1,566 )
Amortization of transition obligation —
—
—
21
Amortization of prior service credit (57 ) (57 ) (411 ) (411 )
Amortization of actuarial (gain) loss 4,248
3,319
(706 ) (541 )
Net periodic pension cost $ 8,710
$ 8,174
$ 2,865
$ 3,314

Nine Months Ended June 30
Pension Benefits Other Benefits
2017 2016 2017 2016
(In thousands)
Components of net periodic pension cost:
Service cost $ 15,649
$ 14,093
$ 9,327
$ 8,117
Interest cost 18,890
21,284
8,009
9,318
Expected return on assets (20,981 ) (20,642 ) (5,389 ) (4,698 )
Amortization of transition obligation —
—
—
62
Amortization of prior service credit (173 ) (170 ) (1,233 ) (1,233 )
Amortization of actuarial (gain) loss 12,746
9,959
(2,120 ) (1,625 )
Net periodic pension cost $ 26,131
$ 24,524
$ 8,594
$ 9,941



	Three Months Ended December 31
	Pension Benefits						Other Benefits
	2017			2016			2017			2016
	(In thousands)
Components of net periodic pension cost:
Service cost	$	4,560		$	5,216		$	3,020		$	3,109
Interest cost	6,430			6,297			2,727			2,670
Expected return on assets	(6,917		)	(6,994		)	(2,002		)	(1,796		)
Amortization of prior service cost (credit)	(58		)	(58		)	3			(411		)
Amortization of actuarial (gain) loss	3,089			4,249			(1,618		)	(707		)
Net periodic pension cost	$	7,104		$	8,710		$	2,130		$	2,865

The assumptions used to develop our net periodic pension cost for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2017 and 2016 are as follows:


	Pension Benefits		Other Benefits		Pension Benefits		Other Benefits
	2017	2016	2017	2016	2017	2016	2017	2016
Discount rate	3.73%	4.55%	3.73%	4.55%	3.89%	3.73%	3.89%	3.73%
Rate of compensation increase	3.50%	3.50%	N/A	N/A	3.50%	3.50%	N/A	N/A
Expected return on plan assets	7.00%	7.00%	4.45%	4.45%	6.75%	7.00%	4.29%	4.45%

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 plan as of January 1, 2017. Based on that determination, we ~~are~~were not required to make a minimum contribution to our defined benefit plan during ~~fiscal 2017; however, we made a voluntary contribution of $5.0 million during~~ the ~~third~~first quarter of fiscal ~~2017.~~2018.

We contributed ~~$9.9~~$3.9 million to our other post-retirement benefit plans during the ~~nine~~three months ended ~~June 30,~~December 31, 2017. We expect to contribute a total of between $10 million and $20 million to these plans during fiscal ~~2017.~~2018.

9. Commitments and Contingencies

Litigation and Environmental Matters

With respect to the ~~specific~~ litigation and environmental-related matters or claims that were disclosed in Note 11 ofto the financial statements in our ~~Fiscal 2016 Financial Statements,~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017, there were no material changes in the status of such litigation and environmental-related matters or claims during the ~~nine~~three months ended ~~June 30,~~December 31, 2017.

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 distribution divisions 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 hubs. ~~At June~~These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2017, we~~2017. There were ~~committed~~no material changes to the purchase ~~53.2 Bcf within one year, 37.6 Bcf within two to~~commitments for the three ~~years and 0.4 Bcf beyond three years under indexed contracts.~~months ended December 31, 2017.

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,~~December 31, 2017, formula rate mechanisms were pending regulatory approval in our Louisiana and Tennessee service ~~area,~~areas, infrastructure mechanisms were pending regulatory approval in our ~~Mississippi and Virginia~~Kansas service ~~areas~~area, an ad valorem tax rider filing was in progress in our Kansas service area and rate cases were pending regulatory approval in our Colorado, Kentucky and Mid-Tex service ~~area and Texas service area related to APT.~~areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. Additionally, as discussed in further detail in Note 6, all jurisdictions are addressing impacts of the TCJA.

10. Financial Instruments

We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 ofto the consolidated financial statements in our ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, ~~except for the change in the scope of our natural gas marketing commodity risk management activities as a result of the sale of AEM,~~ there were no material

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 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 ~~2016-2017~~2017-2018 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we ~~hedged~~anticipate hedging approximately 2726 percent, or ~~16.2~~15.0 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

~~Natural Gas Marketing Commodity Risk Management Activities~~

Our natural gas marketing segment was 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. Through December 31, 2016, we managed 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. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.

Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax gain of $10.6 million, which is included in income from discontinued operations on the condensed consolidated statement of income for the three months ended December 31, 2016.

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,~~December 31, 2017, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.78%, which we designated as a cash flow hedge at the time the swaps were executed. As of ~~June 30,~~December 31, 2017, we had ~~$41.5~~$40.8 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,~~December 31, 2017, 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,~~December 31, 2017, we had ~~18,833~~12,143 MMcf of net short commodity contracts outstanding. These contracts have not been designated as hedges.

Financial Instruments on the Balance Sheet

The following tables present the fair value and balance sheet classification of our financial instruments as of ~~June 30,~~December 31, 2017 and September 30, ~~2016.~~2017. 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~~our counterparties.



	Balance Sheet Location	Assets		Liabilities			Balance Sheet Location	Assets		Liabilities
		(In thousands)						(In thousands)
June 30, 2017
December 31, 2017
Designated As Hedges:
Interest rate contracts	Deferred credits and other liabilities	—		(108,860		)	Deferred charges and other assets / Deferred credits and other liabilities	—		(114,175		)
Total		—		(108,860		)		—		(114,175		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	2,960		(230		)	Other current assets / Other current liabilities	456		(2,738		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	268		(282		)	Deferred charges and other assets / Deferred credits and other liabilities	190		(262		)
Total		3,228		(512		)		646		(3,000		)
Gross Financial Instruments		3,228		(109,372		)		646		(117,175		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—				—		—
Net Financial Instruments		3,228		(109,372		)		646		(117,175		)
Cash collateral		—		—				—		—
Net Assets/Liabilities from Risk Management Activities		$	3,228	$	(109,372	)		$	646	$	(117,175	)




	Balance Sheet Location	Assets		Liabilities
		(In thousands)
September 30, 2017
Designated As Hedges:
Interest rate contracts	Deferred charges and other assets / Deferred credits and other liabilities	—		(112,076		)
Total		—		(112,076		)
Not Designated As Hedges:
Commodity contracts	Other current assets / Other current liabilities	2,436		(322		)
Commodity contracts	Deferred charges and other assets / Deferred credits and other liabilities	803		—
Total		3,239		(322		)
Gross Financial Instruments		3,239		(112,398		)
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting		—		—
Net Financial Instruments		3,239		(112,398		)
Cash collateral		—		—
Net Assets/Liabilities from Risk Management Activities		$	3,239	$	(112,398	)

Balance Sheet Location Assets Liabilities
(In thousands)
September 30, 2016
Designated As Hedges:
Commodity contracts
Other current assets /
Other current liabilities
$ 6,612
$ (21,903 )
Interest rate contracts Other current assets /
Other current liabilities —
(68,481 )
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
2,178
(3,779 )
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
—
(198,008 )
Total 8,790
(292,171 )
Not Designated As Hedges:
Commodity contracts
Other current assets /
Other current liabilities
21,186
(18,812 )
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
14,165
(12,701 )
Total 35,351
(31,513 )
Gross Financial Instruments 44,141
(323,684 )
Gross Amounts Offset on Consolidated Balance Sheet:
Contract netting (39,290 ) 39,290
Net Financial Instruments 4,851
(284,394 )
Cash collateral 6,775
43,575
Net Assets/Liabilities from Risk Management Activities $ 11,626
$ (240,819 )

Impact of Financial Instruments on the Income Statement

~~Hedge ineffectiveness for~~Cash Flow Hedges

As discussed above, our ~~natural gas marketing~~distribution segment ~~was recorded~~has interest rate swap agreements, which we designated as a ~~component of purchased gas cost, which is included in discontinued operations~~cash flow hedge at the time the swaps were executed. The net loss on ~~the~~settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of income ~~and primarily results from differences in the location and timing of the derivative instrument and the hedged item. For~~for the three months ended ~~June 30, 2016, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $13.6 million. For the nine months ended June 30,~~December 31, 2017 and 2016 ~~we recognized gains arising from fair value and cash flow hedge ineffectiveness of $3.4~~was $0.6 million and ~~$18.1~~$0.1 million. ~~Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.~~

~~Fair Value Hedges~~

The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item on the results of discontinued operations on our condensed consolidated income statement for the three and nine months ended June 30, 2017 and 2016 is presented below.

Three Months Ended
June 30 Nine Months Ended
June 30
2017 2016 2017 2016
(In thousands)
Commodity contracts $ —
$ (22,146 ) $ (9,567 ) $ (11,808 )
Fair value adjustment for natural gas inventory designated as the hedged item —
35,630
12,858
29,852
Total decrease in purchased gas cost reflected in income from discontinued operations $ —
$ 13,484
$ 3,291
$ 18,044
The decrease in purchased gas cost reflected in income from discontinued operations is comprised of the following:
Basis ineffectiveness $ —
$ (684 ) $ (597 ) $ (1,490 )
Timing ineffectiveness —
14,168
3,888
19,534
$ —
$ 13,484
$ 3,291
$ 18,044

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.

~~Cash Flow Hedges~~

The impact of our interest rate and natural gas marketing segment cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2017 and 2016 is presented below.

Three Months Ended
June 30 Nine Months Ended
June 30
2017 2016 2017 2016
(In thousands)
Loss reclassified from AOCI for effective portion of natural gas marketing commodity contracts $ —
$ (12,347 ) $ (2,612 ) $ (48,015 )
Gain arising from ineffective portion of natural gas marketing commodity contracts —
66
111
84
Gain on discontinuance of cash flow hedging of natural gas marketing commodity contracts reclassified from AOCI —
—
10,579
—
Total impact on purchased gas cost reflected in income from discontinued operations —
(12,281 ) 8,078
(47,931 )
Net loss on settled interest rate agreements reclassified from AOCI into interest expense (177 ) (137 ) (450 ) (410 )
Total Impact from Cash Flow Hedges $ (177 ) $ (12,418 ) $ 7,628
$ (48,341 )

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,~~December 31, 2017 and 2016. 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						Three Months Ended December 31
	2017			2016			2017			2016			2017			2016 (1)
	(In thousands)												(In thousands)
Increase (decrease) in fair value:
Interest rate agreements	$	(18,669	)	$	(39,337	)	$	76,602		$	(88,345	)	$	(1,332	)	$	91,127
Forward commodity contracts(2)	—			10,573			9,847			(8,612		)	—			9,847
Recognition of (gains) losses in earnings due to settlements:
Interest rate agreements	113			87			286			260			377			87
Forward commodity contracts(2)	—			7,532			(4,865		)	29,290			—			(4,865		)
Total other comprehensive income (loss) from hedging, net of tax⁽¹⁾	$	(18,556	)	$	(21,145	)	$	81,870		$	(67,407	)	$	(955	)	$	96,196


(1)	Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing ~~jurisdiction.~~jurisdiction for the three-month period ended December 31, 2016.


(2)	Due to the sale of AEM, these amounts are included in income from discontinued operations.

Deferred gains (losses) recorded in 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 natural gas marketing segment commodity contracts were recognized in earnings upon settlement.~~instruments. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of ~~June 30,~~December 31, 2017. 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			Interest Rate Agreements
	(In thousands)			(In thousands)
Next twelve months	$	(1,509	)	$	(1,508	)
Thereafter	(40,001		)	(39,248		)
Total⁽¹⁾	$	(41,510	)
Total				$	(40,756	)


~~(1)~~	~~Utilizing an income tax rate of 37 percent.~~

Financial Instruments Not Designated as Hedges

The impact of the natural gas marketing segment's financial instruments that had not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2016 was a decrease in purchased gas cost of $1.9 million, which is included in discontinued operations on the condensed consolidated statements of income. For the nine months ended June 30, 2017 and 2016 purchased gas cost (increased) decreased by $6.8 million and $(2.8) million.

As discussed above, financial instruments used in our distribution segment are not designated as hedges. However, there is no earnings impact on our 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.

11. 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 ofto the financial statements in our ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, 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 7 ofto the financial statements in our ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017.

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,~~December 31, 2017 and September 30, ~~2016.~~2017. 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		June 30, 2017		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		December 31, 2017
	(In thousands)										(In thousands)
Assets:
Financial instruments	$	—	$	3,228	$	—	$	—	$	3,228	$	—	$	646	$	—	$	—	$	646
Available-for-sale securities
Registered investment companies	39,406		—		—		—		39,406		43,065		—		—		—		43,065
Bond mutual funds	15,892		—		—		—		15,892		16,359		—		—		—		16,359
Bonds	—		31,429		—		—		31,429		—		30,861		—		—		30,861
Money market funds	—		2,884		—		—		2,884		—		614		—		—		614
Total available-for-sale securities	55,298		34,313		—		—		89,611		59,424		31,475		—		—		90,899
Total assets	$	55,298	$	37,541	$	—	$	—	$	92,839	$	59,424	$	32,121	$	—	$	—	$	91,545
Liabilities:
Financial instruments	$	—	$	109,372	$	—	$	—	$	109,372	$	—	$	117,175	$	—	$	—	$	117,175


	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⁾			September 30, 2016		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)⁽¹⁾		Significant Other Unobservable Inputs (Level 3)		Netting and Cash Collateral		September 30, 2017
	(In thousands)											(In thousands)
Assets:
Financial instruments	$	—	$	44,141	$	—	$	(32,515	)	$	11,626	$	—	$	3,239	$	—	$	—	$	3,239
Hedged portion of gas stored underground	52,578		—		—		—			52,578
Available-for-sale securities
Registered investment companies	38,677		—		—		—			38,677		41,097		—		—		—		41,097
Bond mutual funds												16,371		—		—		—		16,371
Bonds	—		31,394		—		—			31,394		—		29,104		—		—		29,104
Money market funds	—		2,630		—		—			2,630		—		1,837		—		—		1,837
Total available-for-sale securities	38,677		34,024		—		—			72,701		57,468		30,941		—		—		88,409
Total assets	$	91,255	$	78,165	$	—	$	(32,515	)	$	136,905	$	57,468	$	34,180	$	—	$	—	$	91,648
Liabilities:
Financial instruments	$	—	$	323,684	$	—	$	(82,865	)	$	240,819	$	—	$	112,398	$	—	$	—	$	112,398

(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. As of September 30, 2016, we had $50.4 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $43.6 million was used to offset current and noncurrent risk management liabilities under master netting arrangements with the remaining $6.8 million 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		Amortized Cost		Gross Unrealized Gain		Gross Unrealized Loss			Fair Value
	(In thousands)									(In thousands)
As of June 30, 2017
As of December 31, 2017
Domestic equity mutual funds	$	25,236	$	7,749	$	(17	)	$	32,968	$	27,171	$	8,850	$	(14	)	$	36,007
Foreign equity mutual funds	4,581		1,857		—			6,438		4,725		2,333		—			7,058
Bond mutual funds	15,928		—		(36		)	15,892		16,461		—		(102		)	16,359
Bonds	31,407		52		(30		)	31,429		30,936		6		(81		)	30,861
Money market funds	2,884		—		—			2,884		614		—		—			614
	$	80,036	$	9,658	$	(83	)	$	89,611	$	79,907	$	11,189	$	(197	)	$	90,899
As of September 30, 2016
As of September 30, 2017
Domestic equity mutual funds	$	26,692	$	6,419	$	(590	)	$	32,521	$	25,361	$	8,920	$	—		$	34,281
Foreign equity mutual funds	4,954		1,202		—			6,156		4,581		2,235		—			6,816
Bond mutual funds										16,391		2		(22		)	16,371
Bonds	31,296		108		(10		)	31,394		29,074		46		(16		)	29,104
Money market funds	2,630		—		—			2,630		1,837		—		—			1,837
	$	65,572	$	7,729	$	(600	)	$	72,701	$	77,244	$	11,203	$	(38	)	$	88,409

At ~~June 30,~~December 31, 2017 and September 30, ~~2016,~~2017, our available-for-sale securities included ~~$42.3~~$43.7 million and ~~$41.3~~$42.9 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At ~~June 30,~~December 31, 2017, we maintained investments in bonds that have contractual maturity dates ranging from ~~July 2017~~January 2018 through December 2020.

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,~~December 31, 2017 and September 30, ~~2016:~~2017:


	June 30, 2017		September 30, 2016		December 31, 2017		September 30, 2017
	(In thousands)				(In thousands)
Carrying Amount	$	3,085,000	$	2,460,000	$	3,085,000	$	3,085,000
Fair Value	$	3,388,003	$	2,844,990	$	3,305,656	$	3,382,272

12. Concentration of Credit Risk

Information regarding our concentration of credit risk is disclosed in Note 16 ofto the financial statements in our ~~Fiscal 2016 Financial Statements. Except~~Annual Report on Form 10-K for the ~~sale of AEM, during~~fiscal year ended September 30, 2017. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, there were no material changes in our concentration of credit risk.

13. Discontinued Operations

On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all of the equity interests of Atmos Energy Marketing, LLC (AEM). The transaction closed on January 3, 2017, with an effective date of January 1, 2017. CES paid a cash purchase price of $38.3 million plus working capital of $109.0 million for total cash consideration of $147.3 million. Of this amount, $7.0 million was placed into escrow and was to be paid to the Company within 24 months of the closing date, net of any indemnification claims agreed upon between the two companies. In January 2018, $3.0 million of this escrowed amount was released and received by the Company. We recognized a net gain of $0.03 per diluted share on the sale in the second quarter of fiscal 2017 and completed the working capital true–up during the third quarter of fiscal 2017.

The operating results of our natural gas marketing reportable segment have been reported on the condensed consolidated statement of income as income from discontinued operations, net of income tax, for the three months ended December 31, 2016. Accordingly, expenses related to allocable general corporate overhead and interest expense are not included in these results.

The tables below set forth selected financial information related to discontinued operations. Operating expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income. At December 31, 2017 and September 30, 2017 we did not have any assets or liabilities held for sale.

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




	Three Months Ended December 31, 2016
	(In thousands)

Operating revenues	$	303,474
Purchased gas cost	277,554
Operating expenses	7,874
Operating income	18,046
Other nonoperating expense	(211		)
Income from discontinued operations before income taxes	17,835
Income tax expense	6,841
Net income from discontinued operations	$	10,994

The following table presents statement of cash flow data related to discontinued operations:



	Three Months Ended December 31, 2016
	(In thousands)
Depreciation and amortization expense	$	185
Capital expenditures	$	—
Noncash loss in commodity contract cash flow hedges	$	(8,165	)

Natural Gas Marketing Commodity Risk Management Activities

Our discontinued natural gas marketing segment was 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. Through December 31, 2016, we managed 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. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.

The Company's other risk management activities are discussed in Note 10.

Impact of Financial Instruments on the Income Statement

Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas cost, which is included in discontinued operations on the condensed consolidated statements of income, and primarily results from differences in the location and timing of the derivative instrument and the hedged item. For the three months ended December 31, 2016 , we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.4 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.

Fair Value Hedges



	Three Months Ended December 31, 2016
	(In thousands)
Commodity contracts	$	(9,567	)
Fair value adjustment for natural gas inventory designated as the hedged item	12,858
Total decrease in purchased gas cost reflected in income from discontinued operations	$	3,291
The decrease in purchased gas cost reflected in income from discontinued operations is comprised of the following:
Basis ineffectiveness	$	(597	)
Timing ineffectiveness	3,888
	$	3,291

Cash Flow Hedges

The impact of our natural gas marketing segment cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2016 is presented below:



	Three Months Ended December 31, 2016
	(In thousands)
Loss reclassified from AOCI for effective portion of natural gas marketing commodity contracts	$	(2,612	)
Gain arising from ineffective portion of natural gas marketing commodity contracts	111
Gain on discontinuance of cash flow hedging of natural gas marketing commodity contracts reclassified from AOCI	10,579
Total impact on purchased gas cost reflected in income from discontinued operations	$	8,078

Financial Instruments Not Designated as Hedges

The impact of the natural gas marketing segment's financial instruments that had not been designated as hedges on our condensed consolidated income statements for the three months ended December 31, 2016 was a decrease in purchased gas cost of $6.8 million, which is included in discontinued operations on the condensed consolidated statements of income.

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,~~December 31, 2017 and the related condensed consolidated statements of income, ~~and~~ comprehensive income ~~for the three~~ and ~~nine-month periods ended June 30, 2017 and 2016 and the condensed consolidated statements of~~ cash flows for the ~~nine-month~~three-month periods ended ~~June 30,~~December 31, 2017 and 2016. 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, ~~2016,~~2017, 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 ~~14, 2016 except for the effects of the change in segments described in Note 3 and the discontinued operations described in Note 15, to which the date is April 12,~~13, 2017, 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, ~~2016,~~2017, is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived.

/s/ ERNST & YOUNG LLP

Dallas, Texas

~~August 2, 2017~~February 6, 2018



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 ~~which appears~~ in ~~Item 7 of Exhibit 99.1 to~~ our ~~Current~~Annual Report on Form ~~8-K dated April 12,~~10-K for the year ended September 30, 2017.

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 and capital markets to ~~satisfy~~execute our ~~liquidity requirements;~~business strategy; 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; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty ~~creditworthiness~~performance or ~~performance~~creditworthiness and interest rate risk; 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 ~~natural gas distribution, pipeline and storage businesses;~~business; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain ~~appropriate~~operational, technical and managerial personnel; 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 climate ~~changes~~change or related additional legislation or regulation in the future; the inherent hazards and risks involved in ~~operating our distribution~~distributing, transporting and ~~pipeline and storage businesses;~~storing natural gas; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology ~~systems;~~systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information; 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 ~~transmission~~pipeline and storage ~~businesses, as well as our natural gas marketing business through December 31, 2016.~~businesses. We distribute natural gas through sales and transportation arrangements to ~~approximately~~over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at ~~June 30,~~December 31, 2017 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

Through December 31, 2016, our natural gas marketing business provided natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast. We completed the sale of this business in January 2017.

We manage and review our consolidated operations through the following ~~three~~ reportable segments:

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight ~~states.~~states and storage assets located in Kentucky and Tennessee.

The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in ~~Louisiana, which were included in our former nonregulated segment.~~Louisiana.

The natural gas marketing segment iswas comprised of our discontinued natural gas marketing business.

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 ~~Item 7 of Exhibit 99.1 to~~ our ~~Current~~Annual Report on Form ~~8-K dated April 12,~~10-K for the fiscal year ended September 30, 2017 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~~three months ended ~~June 30,~~December 31, 2017.

Non-GAAP Financial ~~Measure~~Measures

Our operations are affected by the cost of natural ~~gas. The cost of~~ gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Gross Profit, ~~a non-GAAP financial measure~~ defined as operating revenues less purchased gas cost, is a ~~better indicator of our financial performance than operating revenues as it provides a~~more useful and ~~more~~ relevant measure to analyze our financial ~~performance.~~performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference gross profit rather than operating revenues and purchased gas cost individually.

As described further in Note 6, the enactment of the Tax Cuts and Jobs Act of 2017 (the TCJA) required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a one-time, non-cash income tax benefit of $161.9 million during the three months ended December 31, 2017. Due to the non-recurring nature of this benefit, we believe that income from continuing operations and diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit provide a more relevant measure to analyze our financial performance than income from continuing operations and consolidated diluted earnings per share from continuing operations. Accordingly, the following discussion and analysis of our financial performance will reference adjusted income from continuing operations and diluted earnings per share, which is calculated as follows:



	Three Months Ended December 31
	2017		2016		Change
	(In thousands, except per share data)
Income from continuing operations	$	314,132	$	114,038	$	200,094
One-time, non-cash income tax benefit	161,884		—		161,884
Adjusted income from continuing operations	$	152,248	$	114,038	$	38,210

Consolidated diluted EPS from continuing operations	$	2.89	$	1.08	$	1.81
Diluted EPS from one-time, non-cash income tax benefit	1.49		—		1.49
Adjusted diluted EPS from continuing operations	$	1.40	$	1.08	$	0.32

RESULTS OF OPERATIONS

Executive Summary

Atmos Energy strives to operate ~~its~~our businesses safely and reliably while delivering superior shareholder value. ~~In recent years, we~~Our commitment to modernizing our natural gas distribution and transmission systems requires significant levels of capital spending. We have ~~implemented~~the ability to begin recovering a significant portion of these investments timely through rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. ~~Additionally, we have significantly increased investments in the safety and reliability~~The execution of our ~~natural gas distribution and transmission infrastructure. This increased level of investment and timely recovery of~~capital spending program, the ability to recover these investments ~~through~~timely and our ~~regulatory mechanisms has resulted in increased earnings and operating cash flows in recent years.~~

~~The pursuit of~~ability to access the capital markets to satisfy our ~~strategy was~~financing needs are the primary ~~driver for~~drivers that affect our ~~decision to sell our nonregulated natural gas marketing business and to fully exit that business. The sale was announced in October 2016 and closed in January 2017 with~~financial performance.

During the ~~receipt~~first three months of ~~$140.3~~fiscal 2018, we recorded adjusted income from continuing operations of $152.2 million, ~~in cash proceeds, including working capital. We recorded a net gain of $0.03~~or $1.40 per diluted share, oncompared to adjusted income from continuing operations of $114.0 million, or $1.08 per diluted share for the ~~sale in the second quarter~~first three months of fiscal 2017. The ~~proceeds received from the transaction were used to fund infrastructure additions and enhancements in our remaining businesses. As a result~~period-over-period increase of ~~the sale, the results of operations for the divested business have been presented as discontinued operations in the tables below:~~

Three Months Ended June 30
2017 2016 Change
(In thousands, except per share data)
Distribution operations $ 36,514
$ 30,361
$ 6,153
Pipeline and storage operations 34,294
35,782
(1,488 )
Net income from continuing operations 70,808
66,143
4,665
Net income from discontinued operations —
5,050
(5,050 )
Net income $ 70,808
$ 71,193
$ (385 )

Diluted EPS from continuing operations $ 0.67
$ 0.64
$ 0.03
Diluted EPS from discontinued operations —
0.05
(0.05 )
Consolidated diluted EPS $ 0.67
$ 0.69
$ (0.02 )

Nine Months Ended June 30
2017 2016 Change
(In thousands, except per share data)
Distribution operations $ 253,023
$ 219,377
$ 33,646
Pipeline and storage operations 93,835
91,315
2,520
Net income from continuing operations 346,858
310,692
36,166
Net income from discontinued operations 13,710
5,172
8,538
Net income $ 360,568
$ 315,864
$ 44,704

Diluted EPS from continuing operations $ 3.27
$ 3.01
$ 0.26
Diluted EPS from discontinued operations 0.13
0.05
0.08
Consolidated diluted EPS $ 3.40
$ 3.06
$ 0.34

Net income from continuing operations increased 12 percent, compared to the prior-year period, despite weather that was 30 percent warmer than normal and 12 percent warmer than the prior-year period, primarily due to$38.2 million, or 33.5%, largely reflects positive rate outcomes and ~~customer growth in~~the impact of the TCJA on our ~~distribution business.~~effective income tax rate. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, ~~our distribution segment~~we completed 17seven regulatory proceedings, resulting in an increase in annual operating income of ~~$85.0~~$46.1 million and had ~~four~~seven ratemaking efforts in progress at ~~June 30,~~December 31, 2017 seeking $17.1 million of additional annual operating income. Additionally, on January 6, 2017, our Atmos Pipeline - Texas Division filed its statement of intent seeking $63.6 million, as adjusted in its rebuttal case, in additional annual operating income. On August 1, 2017, a ~~final order was issued resulting in a $13 million~~total increase in annual operating ~~income. Our discontinued natural gas marketing results for the nine months ended June 30, 2017 primarily include a pre-tax gain~~income of $10.6 million recognized in the first fiscal quarter related to the discontinuance of cash flow hedging for our natural gas marketing commodity contracts and a $2.7 million net gain on sale recognized in January 2017 upon completion of the sale.$13.3 million.

Capital expenditures for the first ~~nine~~three months of fiscal ~~2017~~2018 were ~~$812.1~~$383.2 million. Approximately 82 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between ~~$1.1~~$1.3 billion and ~~$1.25~~$1.4 billion for fiscal ~~2017.~~2018. We funded our capital ~~expenditure~~expenditures program primarily through operating cash flows of ~~$745.6~~$173.2 million. Additionally, we issued ~~approximately $885 million of long-term debt and $100~~$400 million of common stock during the ~~nine month period ending June 30,~~three months ended December 31, 2017. The net proceeds from ~~these issuances was~~the issuance were primarily used to repay ~~maturing long-term~~short-term debt under our commercial paper program, to fund capital spending and ~~to reduce short-term debt.~~

~~In addition, we acquired EnLink Pipeline in the first fiscal quarter of 2017~~ for an all–cash price of $86.1 million, inclusive of working capital. The acquisition of EnLink Pipeline increases the capacity on our APT intrastate pipeline to serve transportation customers in North Texas, which continues to experience significant population growth.general corporate purposes.

As a result of our sustained financial performance, improved cash flows and capital structure, our Board of Directors increased the quarterly dividend by ~~7.1~~7.8 percent for fiscal 2018.

TCJA Impact

The TCJA introduced several significant changes to corporate income tax laws in the United States, which have been reflected in our condensed consolidated financial statements for the period ended December 31, 2017. As a rate regulated entity, the effects of lower tax rates included in our cost of service rates will ultimately flow through to our utility customers in the form of adjusted rates. Therefore, the favorable impact of the reduction in our federal statutory income tax rate on our financial performance will be limited to items that impact our income before income taxes in the current period that have not yet been reflected in our rates (most notably increases to and decreases in commission-approved regulatory assets and liabilities recorded on our condensed consolidated balance sheet) and market-based revenues that are earned from customers who utilize our assets. Note 6 to the condensed consolidated financial statements details the various impacts of the TCJA on our financial position and results from operations. The most significant changes are summarized as follows:

•Because our fiscal year started on October 1, 2017, our federal statutory income tax rate for fiscal 2018 was reduced from 35% to 24.5%. We anticipate our effective income tax rate for fiscal 2018 will range from 26% to 28%, before the effect of the return of the excess deferred tax liability and the one-time, non-cash income tax benefit. Our federal statutory income tax rate will decline to 21% on October 1, 2018.

•We remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $908.1 million. Of this amount, $746.2 million was reclassified to a regulatory liability, which will be returned to utility customers. The remaining $161.9 million was recognized as a one-time, non-cash income tax benefit in our condensed consolidated statement of income.

•Atmos Energy supports our regulators' efforts to ensure our utility customers receive the full benefits of changes in our cost of service rates arising from tax reform. Income taxes, like other costs, are passed through to our customers in our rates; however, changes to customer rates must be approved by our regulators. Beginning in the second quarter of fiscal 2018, we will establish regulatory liabilities in jurisdictions that have issued orders requiring us to reduce future rates for the difference in taxes included in our cost of service rates that have been calculated based on a 35% statutory income tax rate and a 21% statutory income tax rate. As of February 6, 2018, we had received orders in five jurisdictions and anticipate receiving regulatory orders in the remaining jurisdictions by the end of the second quarter of fiscal 2018. The establishment of these regulatory liabilities for our cost of service rates will reduce our revenues. The timing of the establishment of regulatory liabilities as well as the period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.

•The enactment of the TCJA is expected to reduce our cash flows from operations primarily due to 1) the collection of taxes at a lower rate and 2) the return of regulatory liabilities established in response to the enactment of the TCJA and regulatory activities to our utility customers. We intend to externally finance this reduction in operating cash flow in a balanced fashion in order to maintain an equity capitalization ratio ranging from 50% to 60% to maintain our current credit ratings. We currently anticipate this external financing need will range from $500 million to $600 million through fiscal 2022.

The following discusses the results of operations for each of our operating segments.

Distribution Segment

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment 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 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 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. Gross profit in our Texas and Mississippi service areas includes franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.

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 7576 percent of our residential and commercial margins.

Three Months Ended ~~June 30,~~December 31, 2017 compared with Three Months Ended ~~June 30,~~December 31, 2016

Financial and operational highlights for our distribution segment for the three months ended ~~June 30,~~December 31, 2017 and 2016 are presented below.


	Three Months Ended June 30								Three Months Ended December 31
	2017			2016		Change			2017			2016			Change
	(In thousands, unless otherwise noted)								(In thousands, unless otherwise noted)
Operating revenues	$	494,060		$	424,905	$	69,155		$	860,792		$	754,656		$	106,136
Purchased gas cost	197,767			147,569		50,198			463,758			395,346			68,412
Gross profit	296,293			277,336		18,957			397,034			359,310			37,724
Operating expenses	219,241			213,674		5,567			224,278			204,417			19,861
Operating income	77,052			63,662		13,390			172,756			154,893			17,863
Miscellaneous income (expense)	(62		)	1,243		(1,305		)
Miscellaneous expense									(1,400		)	(633		)	(767		)
Interest charges	18,394			18,677		(283		)	21,368			21,118			250
Income before income taxes	58,596			46,228		12,368			149,988			133,142			16,846
One-time, non-cash income tax benefit									(140,151		)	—			(140,151		)
Income tax expense	22,082			15,867		6,215			41,040			47,778			(6,738		)
Net income	$	36,514		$	30,361	$	6,153		$	249,099		$	85,364		$	163,735
Consolidated distribution sales volumes — MMcf	42,974			39,040		3,934			86,307			74,430			11,877
Consolidated distribution transportation volumes — MMcf	33,307			30,416		2,891			38,050			36,175			1,875
Total consolidated distribution throughput — MMcf	76,281			69,456		6,825			124,357			110,605			13,752
Consolidated distribution average cost of gas per Mcf sold	$	4.60		$	3.78	$	0.82		$	5.37		$	5.31		$	0.06

Income before income taxes for our distribution segment increased 2013 percent, primarily due to a ~~$19.0~~$37.7 million increase in gross profit, partially offset with a ~~$5.6~~$19.9 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:

a ~~$13.7~~$25.6 million net increase in rate adjustments, primarily in our Mid-Tex, Mississippi, West Texas ~~Louisiana~~and Kentucky/Mid-States Divisions.

a $5.7 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.

~~Customer~~a $3.5 million increase from customer growth, primarily in our Mid-Tex ~~Division, which contributed an incremental $1.1 million.~~

~~a $1.8 million net increase in residential~~ and ~~commercial consumption, primarily in our Mid-Tex Division.~~Kentucky/Mid-States Divisions.

The increase in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to ~~higher~~incremental system integrity activities, increased depreciation and property tax expense associated with increased capital ~~investments,~~investments.

The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9% to 27.4%, as ~~well as higher administrative expenses.~~a result of the TCJA, which is partially offset by an increase in income before income taxes.

The following table shows our operating income by distribution division, in order of total rate base, for the three months ended ~~June 30,~~December 31, 2017 and 2016. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.



	Three Months Ended December 31
	2017		2016		Change
	(In thousands)
Mid-Tex	$	72,925	$	72,743	$	182
Kentucky/Mid-States	28,129		22,738		5,391
Louisiana	23,268		19,863		3,405
West Texas	15,761		14,928		833
Mississippi	18,275		11,958		6,317
Colorado-Kansas	12,931		11,705		1,226
Other	1,467		958		509
Total	$	172,756	$	154,893	$	17,863

Three Months Ended June 30
2017 2016 Change
(In thousands)
Mid-Tex $ 37,055
$ 33,562
$ 3,493
Kentucky/Mid-States 13,073
7,126
5,947
Louisiana 11,051
10,051
1,000
West Texas 6,639
5,659
980
Mississippi 3,437
3,916
(479 )
Colorado-Kansas 3,842
3,111
731
Other 1,955
237
1,718
Total $ 77,052
$ 63,662
$ 13,390

~~Nine Months Ended June 30, 2017 compared with Nine Months Ended June 30, 2016~~

~~Financial and operational highlights for our distribution segment for the nine months ended June 30, 2017 and 2016 are presented below.~~

Nine Months Ended June 30
2017 2016 Change
(In thousands, unless otherwise noted)
Operating revenues $ 2,211,257
$ 1,936,475
$ 274,782
Purchased gas cost 1,106,209
912,231
193,978
Gross profit 1,105,048
1,024,244
80,804
Operating expenses 646,299
622,100
24,199
Operating income 458,749
402,144
56,605
Miscellaneous income 334
804
(470 )
Interest charges 56,437
57,481
(1,044 )
Income before income taxes 402,646
345,467
57,179
Income tax expense 149,623
126,090
23,533
Net income $ 253,023
$ 219,377
$ 33,646
Consolidated regulated distribution sales volumes — MMcf 215,158
227,664
(12,506 )
Consolidated regulated distribution transportation volumes — MMcf 109,397
103,304
6,093
Total consolidated regulated distribution throughput — MMcf 324,555
330,968
(6,413 )
Consolidated regulated distribution average cost of gas per Mcf sold $ 5.14
$ 4.01
$ 1.13

Income for our distribution segment increased 15 percent, primarily due to an $80.8 million increase in gross profit, partially offset with a $24.2 million increase in operating expenses. The year-over-year increase in gross profit primarily reflects:

~~a $59.0 million net increase in rate adjustments, primarily in our Mid-Tex, Louisiana and Mississippi Divisions.~~

~~Customer growth, primarily in our Mid-Tex and Tennessee service areas, which contributed an incremental $5.4 million.~~

~~a $3.8 million increase in revenue-related taxes in our Mid-Tex and West Texas Divisions, offset by a corresponding $3.5 million increase in the related tax expense.~~

~~a $4.2 million increase in transportation primarily in our Kentucky/Mid-States, Mid-Tex and West Texas Divisions.~~

~~a $2.1 million net increase in residential consumption, primarily in our Mid-Tex Division.~~

The increase in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to an increase in employee-related costs, higher levels of line locate and pipeline integrity activities, primarily in our Mid-Tex Division, and higher depreciation and property tax expense associated with increased capital investments.

The following table shows our operating income by distribution division, in order of total rate base, for the nine months ended June 30, 2017 and 2016. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

Nine Months Ended June 30
2017 2016 Change
(In thousands)
Mid-Tex $ 200,607
$ 181,858
$ 18,749
Kentucky/Mid-States 69,821
56,911
12,910
Louisiana 61,276
50,754
10,522
West Texas 42,590
38,793
3,797
Mississippi 41,197
40,369
828
Colorado-Kansas 33,878
31,189
2,689
Other 9,380
2,270
7,110
Total $ 458,749
$ 402,144
$ 56,605

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~~three months of fiscal ~~2017,~~2018, we completed 17six regulatory proceedings, resulting in ana $~~85.0~~17.1 million increase in annual operating income as summarized below.


Rate Action	Annual Increase in Operating Income		Annual Increase in Operating Income
	(In thousands)		(In thousands)
Annual formula rate mechanisms	$	84,190	$	17,077
Rate case filings	6		—
Other rate activity	784		—
	$	84,980	$	17,077

~~Additionally, the~~The following ratemaking efforts seeking ~~$17.1~~$13.3 million in increased annual operating income were in progress as of ~~June 30,~~December 31, 2017:

Division

Rate Action

Jurisdiction

Operating Income

Requested

Rate Action

Jurisdiction

Operating Income

Requested

(In thousands)

Louisiana

Formula Rate Mechanism

LGS⁽¹⁾

6,237

Mississippi

Infrastructure Mechanism

Mississippi

7,600

Colorado-Kansas

Rate Case

Colorado

2,916

Rate Case ⁽¹⁾

Colorado

2,916

GSRS

Kansas

821

Ad Valorem

Kansas

457

Kentucky/Mid-States

Infrastructure Mechanism

Virginia

308

Rate Case

Kentucky

4,778

17,061

ARM True-Up ⁽²⁾

Tennessee

850

Louisiana

RSC

Trans La

1,195

Mid-Tex

Rate Case ⁽³⁾

City of Dallas

2,247

13,264


(1)	A Recommended Decision for $2.1 million was issued on January 8, 2018. The ~~proposed increase~~Recommended Decision also recommended a five year extension of the Company's System Safety and Integrity Rider tariff.


(2)	The Annual Rate Mechanism (ARM) is a formula rate mechanism that refreshes the Company's rates on an annual basis.


(3)	The Company extended the deadline for ~~LGS customers was implemented on July 1, 2017, subject~~the City of Dallas to ~~refund.~~act until February 15, 2018.

Annual Formula Rate Mechanisms

As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi and Tennessee operations and in substantially all ofthe service areas in our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a ~~prior test-year~~

prior test-year period. The following table summarizes our annual formula rate mechanisms by state:



	Annual Formula Rate Mechanisms
State	Infrastructure Programs	Formula Rate Mechanisms

Colorado	System Safety and Integrity Rider (SSIR)	—
Kansas	Gas System Reliability Surcharge (GSRS)	—
Kentucky	Pipeline Replacement Program (PRP)	—
Louisiana	(1)	Rate Stabilization Clause (RSC)
Mississippi	System Integrity Rider (SIR)	Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee	—	Annual Rate Mechanism (ARM)
Texas	Gas Reliability Infrastructure Program (GRIP), (1)	Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia	Steps to Advance Virginia Energy (SAVE)	—


(1)	Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes (Texas only), until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

The following annual formula rate mechanisms were approved during the ~~nine~~three months ended ~~June 30,~~December 31, 2017:

Division

Jurisdiction

Test Year

Ended

Increase in

Annual

Operating

Income

Effective

Date

Jurisdiction

Test Year

Ended

Increase in

Annual

Operating

Income

Effective

Date

(In thousands)

2017 Filings:

Mid-Tex

Mid-Tex DARR ⁽¹⁾

09/30/2016

9,672

06/01/2017

Mid-Tex

Mid-Tex Cities RRM

12/31/2016

36,239

06/01/2017

Kentucky/Mid-States

Tennessee ARM

05/31/2016

6,740

06/01/2017

Mid-Tex

Mid-Tex Environs

12/31/2016

1,568

05/23/2017

West Texas

West Texas Environs

12/31/2016

872

05/23/2017

West Texas

West Texas ALDC

12/31/2016

4,682

04/25/2017

Louisiana

TransLa ⁽²⁾

09/30/2016

4,392

04/01/2017

West Texas

West Texas Cities RRM

09/30/2016

4,255

03/15/2017

2018 Filings:

Colorado-Kansas

Kansas

09/30/2016

801

02/09/2017

Colorado SSIR

12/31/2018

2,228

12/20/2017

Mississippi

Mississippi SRF

10/31/2017

4,390

01/12/2017

Mississippi - SIR

10/31/2018

7,658

12/05/2017

Mississippi

Mississippi SIR

10/31/2017

3,334

01/01/2017

Mississippi - SGR ⁽¹⁾

10/31/2018

1,245

12/05/2017

Mississippi

Mississippi SGR

10/31/2017

1,292

01/01/2017

Mississippi - SRF ⁽¹⁾

10/31/2018

—

12/05/2017

Colorado-Kansas

Colorado SSIR

12/31/2017

1,350

01/01/2017

Kentucky/Mid-States

Kentucky PRP

09/30/2017

4,981

10/14/2016

Kentucky - PRP

09/30/2018

5,638

10/27/2017

Kentucky/Mid-States

Virginia SAVE

09/30/2017

(378

)

10/01/2016

Virginia - SAVE ⁽²⁾

09/30/2017

308

10/01/2017

Total 2017 Filings

84,190

Total 2018 Filings

17,077


(1)	~~The Company and~~In our next SRF filing, the ~~City of Dallas were unable to arrive at a mutually agreeable settlement; therefore the DARR rates were implemented, subject to refund, pending the outcome of an appeal filed~~SGR rate base will be combined with the ~~Texas Railroad Commission.~~SRF rate base, per Commission order.


(2)	The ~~Trans Louisiana RSC rates were implemented subject~~Company completed our Steps to Advance Virginia Energy (SAVE) program. On October 1, 2017 a refund ~~on April 1, 2017.~~factor was removed from the rate resulting in an operating income increase of $308,000.

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 and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers.

~~The following table summarizes the~~There was no rate ~~cases that were~~case activity completed during the ~~nine~~three months ended ~~June 30, 2017:~~December 31, 2017.

Division State
Increase in Annual
Operating Income

Effective
Date
(In thousands)
2017 Rate Case Filings:
Kentucky/Mid-States ⁽¹⁾
Virginia $ 6
12/27/2016
Total 2017 Rate Case Filings $ 6



~~(1)~~	The Virginia State Corporation Commission issued a final order approving a re-basing of the Company's SAVE rates into base rates and a decrease to depreciation expense. The Company had implemented rates on April 1, 2016, subject to refund, of $0.5 million.

Other Ratemaking Activity

The ~~following table summarizes~~Company had no other ratemaking activity during the ~~nine~~three months ended ~~June 30, 2017:~~December 31, 2017.

Division Jurisdiction Rate Activity
Additional
Annual
Operating
Income

Effective
Date
(In thousands)
2017 Other Rate Activity:
Colorado-Kansas Kansas
Ad-Valorem⁽¹⁾
$ 784
2/1/2017
Total 2017 Other Rate Activity $ 784



~~(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.~~

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in ~~Louisiana, which were previously included in our former nonregulated segment.~~Louisiana. APT is one of the largest intrastate pipeline operations in Texas

with a heavy concentration in the established natural gas producing areas of central, northern, eastern and western Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Midland Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third-party local distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT manages five underground storage facilities in Texas.

Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.

Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Texas and Louisiana service areas. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation and storage 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 in Texas could influence the volumes of gas transported for shippers through our Texas pipeline system and the rates for such transportation.

The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

APT annually uses GRIP to recover capital costs incurred in the prior calendar year. ~~However, GRIP also requires a utility to file a statement~~Following the conclusion of ~~intent at least once every five years to review~~ its ~~costs and expenses, including capital costs filed for recovery under GRIP. However,~~rate case in August 2017, APT ~~is precluded from submitting~~made a GRIP filing ~~until~~that covered changes in net investment from October 1, 2016 through December 31, 2016 with a ~~final order has been issued on the~~

statement of intent. Accordingly, APT has not yet submitted its annual GRIP filing for calendar year 2016. On January 6, 2017, APT filed its statement of intent seeking $63.6 million, as adjusted in its rebuttal case, in additional annual operating income. On August 1, 2017, a final order was issued resulting in a $13 millionrequested increase in ~~annual~~ operating ~~income.~~income of $29.0 million. On December 5, 2017, the filing was approved.

On December 21, 2016, the Louisiana Public Service Commission approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017. ~~This agreement will replace the existing agreement that expires in September 2017.~~

Three Months Ended ~~June 30,~~December 31, 2017 compared with Three Months Ended ~~June 30,~~December 31, 2016

Financial and operational highlights for our pipeline and storage segment for the three months ended ~~June 30,~~December 31, 2017 and 2016 are presented below.

Three Months Ended June 30
2017 2016 Change
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue $ 84,594
$ 85,262
$ (668 )
Third-party transportation revenue 27,369
23,877
3,492
Other revenue 5,320
4,716
604
Total operating revenues 117,283
113,855
3,428
Total purchased gas cost 1,251
(438 ) 1,689
Gross profit 116,032
114,293
1,739
Operating expenses 52,420
49,559
2,861
Operating income 63,612
64,734
(1,122 )
Miscellaneous expense (227 ) (125 ) (102 )
Interest charges 10,104
9,002
1,102
Income before income taxes 53,281
55,607
(2,326 )
Income tax expense 18,987
19,825
(838 )
Net income $ 34,294
$ 35,782
$ (1,488 )
Gross pipeline transportation volumes — MMcf 192,543
158,758
33,785
Consolidated pipeline transportation volumes — MMcf 159,023
128,881
30,142

Net income for our pipeline and storage segment decreased four percent, primarily due to a $2.9 million increase in operating expenses, offset by a $1.7 million increase in gross profit. The increase in gross profit is primarily the result of higher through system revenue of $1.3 million, largely related to incremental throughput on the EnLink Pipeline, which was acquired in the first quarter of fiscal 2017, and higher basis spreads due to increased production in the Permian Basin. As noted above, as a result of the annual rate case, we did not file our annual GRIP filing during the second quarter of fiscal 2017, which influenced this segment's performance quarter-over-quarter.

Operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $2.9 million, primarily due to higher depreciation expense and property taxes associated with increased capital investments and the acquisition of EnLink Pipeline.



	Three Months Ended December 31
	2017			2016			Change
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	93,898		$	82,468		$	11,430
Third-party transportation revenue	28,931			22,220			6,711
Other revenue	3,634			5,264			(1,630		)
Total operating revenues	126,463			109,952			16,511
Total purchased gas cost	912			355			557
Gross profit	125,551			109,597			15,954
Operating expenses	56,746			54,572			2,174
Operating income	68,805			55,025			13,780
Miscellaneous expense	(635		)	(361		)	(274		)
Interest charges	10,141			9,912			229
Income before income taxes	58,029			44,752			13,277
One-time, non-cash income tax benefit	(21,733		)	—			(21,733		)
Income tax expense	14,729			16,078			(1,349		)
Net income	$	65,033		$	28,674		$	36,359
Gross pipeline transportation volumes — MMcf	213,137			186,780			26,357
Consolidated pipeline transportation volumes — MMcf	155,105			134,976			20,129

~~Nine Months Ended June 30, 2017 compared with Nine Months Ended June 30, 2016~~

~~Financial and operational highlights for our pipeline and storage segment for the nine months ended June 30, 2017 and 2016 are presented below.~~

Nine Months Ended June 30
2017 2016 Change
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue $ 251,354
$ 229,916
$ 21,438
Third-party transportation revenue 72,414
66,393
6,021
Other revenue 15,439
18,115
(2,676 )
Total operating revenues 339,207
314,424
24,783
Total purchased gas cost 2,331
(72 ) 2,403
Gross profit 336,876
314,496
22,380
Operating expenses 159,871
143,859
16,012
Operating income 177,005
170,637
6,368
Miscellaneous expense (784 ) (894 ) 110
Interest charges 30,035
27,294
2,741
Income before income taxes 146,186
142,449
3,737
Income tax expense 52,351
51,134
1,217
Net income $ 93,835
$ 91,315
$ 2,520
Gross pipeline transportation volumes — MMcf 574,556
526,532
48,024
Consolidated pipeline transportation volumes — MMcf 425,150
373,080
52,070

~~Net~~Income before income taxes for our pipeline and storage segment increased ~~three~~30 percent, primarily due to a ~~$22.4~~$16.0 million increase in gross profit, offset by a ~~$16.0~~$2.2 million increase in operating expenses. The increase in gross profit primarily reflects a ~~$22.1~~$13.9 million increase in rates from the approved APT rate case and the GRIP ~~filings~~filing approved in ~~fiscal~~December 2017. Additionally, average transportation fees increased as a result of higher basis spreads creating a $4.1 million increase in gross profit and transport volumes increased due to incremental throughput on the North Texas pipeline, which was acquired on December 20, 2016.

Operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased ~~$16.0~~$2.2 million, primarily due to ~~increased levels of pipeline maintenance and integrity activities and~~ higher depreciation expense ~~and property taxes associated with increased capital investments and~~partially offset by lower system maintenance expense.

The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9% to 25.4%, as a result of the ~~acquisition of EnLink Pipeline.~~TCJA, which is partially offset by an increase in income before income taxes.

Natural Gas Marketing Segment

Through December 31, 2016, we were engaged in an unregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. Additionally, AEM utilized proprietary and customer–owned transportation and storage assets to provide various services its customers requested. AEM served most of its customers under contracts generally having one to two year terms. As a result, AEM’s margins arose from the types of commercial transactions it had structured with its customers and its ability to identify the lowest cost alternative among the natural gas supplies, transportation and markets to which it had access to serve those customers.

As more fully described in Note 6,13, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, ~~these operations have been~~net income of $11.0 million for AEM is reported as discontinued ~~operations.~~

~~Three Months Ended June 30, 2017 compared with Three Months Ended June 30, 2016~~

~~Financial and operating highlights for our natural gas marketing segment~~operations for the three months ended ~~June 30, 2017 and 2016 are presented below.~~December 31, 2016.

Three Months Ended June 30
2017 2016 Change
(In thousands, unless otherwise noted)
Operating revenues $ —
$ 200,213
$ (200,213 )
Purchased gas cost —
184,398
(184,398 )
Gross profit —
15,815
(15,815 )
Operating income —
7,047
(7,047 )
Operating income —
8,768
(8,768 )
Miscellaneous income —
56
(56 )
Interest charges —
360
(360 )
Income before income taxes —
8,464
(8,464 )
Income tax expense —
3,414
(3,414 )
Net income from discontinued operations $ —
$ 5,050
$ (5,050 )
Gross natural gas marketing delivered gas sales volumes — MMcf —
84,415
(84,415 )
Consolidated natural gas marketing delivered gas sales volumes — MMcf —
72,742
(72,742 )
Net physical position (Bcf) —
29.4
(29.4 )

~~Nine Months Ended June 30, 2017 compared with Nine Months Ended June 30, 2016~~

~~Financial and operating highlights for our natural gas marketing segment for the nine months ended June 30, 2017 and 2016 are presented below.~~

Nine Months Ended June 30
2017 2016 Change
(In thousands, unless otherwise noted)
Operating revenues $ 303,474
$ 728,989
$ (425,515 )
Purchased gas cost 277,554
698,445
(420,891 )
Gross profit 25,920
30,544
(4,624 )
Operating expenses 7,874
19,940
(12,066 )
Operating income 18,046
10,604
7,442
Miscellaneous income 30
171
(141 )
Interest charges 241
2,108
(1,867 )
Income before income taxes 17,835
8,667
9,168
Income tax expense 6,841
3,495
3,346
Income from discontinued operations 10,994
5,172
5,822
Gain on sale of discontinued operations, net of tax 2,716
—
2,716
Net income from discontinued operations $ 13,710
$ 5,172
$ 8,538
Gross nonregulated delivered gas sales volumes — MMcf 90,223
280,588
(190,365 )
Consolidated nonregulated delivered gas sales volumes — MMcf 78,646
245,702
(167,056 )
Net physical position (Bcf) —
29.4
(29.4 )

The $8.5 million year-over-year increase in net income from discontinued operations primarily reflects the recognition of a net $6.6 million noncash gain from unwinding hedge accounting for certain of the natural gas marketing business's financial positions in connection with the sale of AEM. Additionally, we recognized a $2.7 million net gain on sale upon completion of the sale of AEM to CES in January 2017.

Liquidity and Capital Resources

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a ~~variety~~combination of ~~sources, including~~ internally generated ~~funds~~cash flows and ~~borrowings under our~~external debt and equity financing. External debt financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program and ~~bank~~three committed revolving credit ~~facilities.~~facilities with a total availability from third-party lenders of approximately $1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure with an equity-to-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. 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~~The liquidity provided by these sources is expected to ~~time, we raise funds from the public debt and equity capital markets~~be sufficient to fund the Company's working capital needs and capital expenditure program for the fiscal year 2018 and beyond. Refer to the TCJA impact section above regarding anticipated impacts on our liquidity, ~~needs.~~capital resources and cash flows.

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 45 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1.5 billion of capacity under our short-term facilities.

~~We plan to continue to fund our growth through the use of operating cash flows and debt and equity securities, while maintaining a balanced capital structure.~~ To support our capital market activities, we have a registration statement on file with the SEC that permits us to issue a total of $2.5 billion in common stock and/or debt securities. Under the shelf registration statement, we ~~have~~recently filed a prospectus supplement for an at–the-market (ATM) equity distribution program under which we may issue and sell, shares of our common stock, up to an aggregate offering price of ~~$200~~$500 million.

During the first nine months of fiscal 2017, we issued 1,303,494 shares under our ATM program and received net proceeds of $98.8 million. Substantially all shares have now been issued under this program. Additionally, on June 8, 2017, we completed a public offering of $500 million of 3.00% senior unsecured notes due 2027 and $250 million of 4.125% senior unsecured notes due 2044. The net proceeds of approximately $753 million were used to repay our $250 million 6.35% senior unsecured notes at maturity on June 15, 2017 and for general corporate purposes, including the repayment of working capital borrowings pursuant to our commercial paper program. At ~~June 30,~~December 31, 2017, approximately ~~$1.6~~$1.2 billion of securities ~~remain~~remained available for issuance under the shelf registration statement.

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of ~~June 30,~~December 31, 2017, September 30, ~~2016~~2017 and ~~June 30,~~December 31, 2016:


	June 30, 2017				September 30, 2016				June 30, 2016				December 31, 2017				September 30, 2017				December 31, 2016
	(In thousands, except percentages)												(In thousands, except percentages)
Short-term debt	$	258,573	3.6	%	$	829,811	12.3	%	$	670,466	10.2	%	$	336,816	4.2	%	$	447,745	6.0	%	$	940,747	13.1	%
Long-term debt	3,066,734		42.4	%	2,438,779		36.2	%	2,438,699		37.1	%	3,067,469		38.5	%	3,067,045		41.4	%	2,564,199		35.6	%
Shareholders’ equity	3,901,710		54.0	%	3,463,059		51.5	%	3,466,724		52.7	%	4,563,620		57.3	%	3,898,666		52.6	%	3,698,975		51.3	%
Total	$	7,227,017	100.0	%	$	6,731,649	100.0	%	$	6,575,889	100.0	%	$	7,967,905	100.0	%	$	7,413,456	100.0	%	$	7,203,921	100.0	%

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~~three months ended ~~June 30,~~December 31, 2017 and 2016 are presented below.


	Nine Months Ended June 30									Three Months Ended December 31
	2017			2016			Change			2017			2016			Change
	(In thousands)									(In thousands)
Total cash provided by (used in)
Operating activities	$	745,561		$	629,946		$	115,615		$	173,238		$	116,963		$	56,275
Investing activities	(747,355		)	(783,399		)	36,044			(381,372		)	(392,137		)	10,765
Financing activities	24,037			191,006			(166,969		)	236,475			272,264			(35,789		)
Change in cash and cash equivalents	22,243			37,553			(15,310		)	28,341			(2,910		)	31,251
Cash and cash equivalents at beginning of period	47,534			28,653			18,881			26,409			47,534			(21,125		)
Cash and cash equivalents at end of period	$	69,777		$	66,206		$	3,571		$	54,750		$	44,624		$	10,126

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 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~~three months ended ~~June 30,~~December 31, 2017, we generated cash flow of ~~$745.6~~$173.2 million from operating activities compared with ~~$629.9~~$117.0 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2016. The ~~$115.6~~$56.2 million increase in operating cash flows reflects the positive cash effects of successful rate case outcomes achieved in fiscal ~~2016~~2017 and changes in working capital, primarily ~~the recovery~~as a result of higher recoveries of deferred ~~purchased~~ gas ~~costs.~~cost due to higher distribution sales volumes in the current quarter compared to the prior-year quarter.

Cash flows from investing activities

In executing our regulatory strategy, we target our capital spending on regulatory mechanisms that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Substantially all of our regulated jurisdictions 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.

In recent years, ~~a substantial portion of~~we have incurred capital expenditures to support our ~~cash resources has been used to fund our ongoing construction program, which enables us to enhance the safety~~distribution and ~~reliability of the systems used to provide natural gas distribution services to our existing customer base,~~transmission system modernization and integrity enhancement efforts, expand our natural gas distribution services ~~into new markets, enhance the integrity of our pipelines~~ and ~~more recently,~~ expand our intrastate pipeline network. Over the last three fiscal years, approximately 80 percent of our capital spending has been committed to improving the safety and reliability of our system. ~~We anticipate our annual capital spending will be in the range of $1 billion to $1.4 billion through fiscal 2020.~~

For the ~~nine~~three months ended ~~June 30,~~December 31, 2017, cash used for investing activities was ~~$747.4~~$381.4 million compared to ~~$783.4~~$392.1 million in the prior-year period. Capital spending increased by ~~$22.5~~$85.3 million, or ~~2.8~~29 percent, as a result of planned increases in our distribution segment to repair and replace vintage pipe, ~~partially offset by a decrease~~and increases in spending in our pipeline and storage segment ~~as a result of the substantial completion of an APT project~~ to improve the reliability of gas service to ~~its~~our local distribution company customers. ~~Cash flows~~These increases were offset by cash outflows from investing activities ~~also include proceeds of $140.3 million received from~~in the ~~sale of AEM, a portion~~three months ended December 31, 2016, for the purchase of the ~~proceeds received from~~North Texas Pipeline for $85.7 million and $10.3 million related to the ~~completion~~purchase of ~~a State of Texas use tax audit and the $86.1 million used to purchase Enlink Pipeline in the first fiscal quarter of 2017.~~available-for-sale securities.

Cash flows from financing activities

For the ~~nine~~three months ended ~~June 30,~~December 31, 2017, our financing activities ~~generated $24.0~~provided $236.5 million of cash compared with ~~$191.0~~$272.3 million ~~generated~~ in the prior-year period. The ~~$167.0~~$35.8 million decrease in cash provided by financing activities is primarily due to increased operating cash flow and lower cash used in investing activities.

During the ~~reduction~~first quarter, we used $395.1 million in net proceeds from equity financing to reduce short-term debt, to support our capital spending and for other general corporate purposes. Cash dividends increased due to a 7.8% increase in our ~~short-term debt, partially offset by~~dividend rate and an increase in shares outstanding.

During the first three months of fiscal 2017, we issued $125 million of long-term debt under our ~~long-term debt.~~three year, $200 million term loan agreement and received $49.4 million from the issuance of common stock under our ATM program. The net proceeds from these debt and equity issuances were used to support our capital expenditures program. Short-term debt increased a net $110.9 million to temporarily finance the acquisition of the North Texas pipeline in December 2016.

The following table summarizes our share issuances for the ~~nine~~three months ended ~~June 30,~~December 31, 2017 and 2016:

Nine Months Ended
June 30
2017 2016
Shares issued:
Direct Stock Purchase Plan 90,789
107,736
1998 Long-Term Incentive Plan 529,060
597,470
Retirement Savings Plan and Trust 205,972
282,578
At-the-Market (ATM) Equity Distribution Program 1,303,494
1,360,756
Total shares issued 2,129,315
2,348,540

~~The year-over-year decrease in the number of shares issued primarily reflects a decrease in shares issued under the Retirement Savings Plan and Trust and the 1998 Long-Term Incentive Plan.~~

~~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~~ ~~$1.5 billion~~ commercial paper program and three committed revolving credit facilities with third-party lenders that provide a total of approximately $1.5 billion of working capital funding. As of June 30, 2017, the amount available to us under our credit facilities, net of commercial paper and outstanding letters of credit, was $1.3 billion.



	Three Months Ended December 31
	2017	2016
Shares issued:
Direct Stock Purchase Plan	38,209	27,071
1998 Long-Term Incentive Plan	235,960	365,471
Retirement Savings Plan and Trust	24,905	95,991
At-the-Market (ATM) Equity Distribution Program	—	690,812
Equity Issuance	4,558,404	—
Total shares issued	4,857,478	1,179,345

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 businesses and the regulatory structures that govern our rates in the states where we operate.

Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). As of ~~June 30,~~December 31, 2017, both rating agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:



	S&P	Moody’s
Senior unsecured long-term debt	A	A2
Short-term debt	A-1	P-1

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 and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. 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,~~December 31, 2017. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the ~~nine~~three months ended ~~June 30,~~December 31, 2017.

Risk Management Activities

In our distribution and pipeline and storage segments, 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. Through December 31, 2016, we managed our exposure to the risk of natural gas price changes in our natural gas marketing segment by locking 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.

The following table shows the components of the change in fair value of our financial instruments for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2017 and 2016:


	Three Months Ended June 30						Nine Months Ended June 30						Three Months Ended December 31
	2017			2016			2017			2016			2017			2016
	(In thousands)												(In thousands)
Fair value of contracts at beginning of period	$	(114,004	)	$	(203,949	)	$	(279,543	)	$	(153,981	)	$	(109,159	)	$	(279,543	)
Contracts realized/settled	37,172			1,196			48,928			1,185			1,160			9,963
Fair value of new contracts	557			2,377			(1,040		)	2,434			(569		)	963
Other changes in value	(29,869		)	(62,709		)	125,511			(112,723		)	(7,961		)	146,895
Fair value of contracts at end of period	(106,144		)	(263,085		)	(106,144		)	(263,085		)	(116,529		)	(121,722		)
Netting of cash collateral	—			39,067			—			39,067			—			13,697
Cash collateral and fair value of contracts at period end	$	(106,144	)	$	(224,018	)	$	(106,144	)	$	(224,018	)	$	(116,529	)	$	(108,025	)

The fair value of our financial instruments at ~~June 30,~~December 31, 2017 is presented below by time period and fair value source:


	Fair Value of Contracts at June 30, 2017												Fair Value of Contracts at December 31, 2017
	Maturity in Years												Maturity in Years
Source of Fair Value	Less Than 1		1-3			4-5		Greater Than 5		Total Fair Value			Less Than 1			1-3			4-5		Greater Than 5		Total Fair Value
	(In thousands)												(In thousands)
Prices actively quoted	$	2,730	$	(108,874	)	$	—	$	—	$	(106,144	)	$	(2,282	)	$	(114,247	)	$	—	$	—	$	(116,529	)
Prices based on models and other valuation methods	—		—			—		—		—			—			—			—		—		—
Total Fair Value	$	2,730	$	(108,874	)	$	—	$	—	$	(106,144	)	$	(2,282	)	$	(114,247	)	$	—	$	—	$	(116,529	)

Pension and Postretirement Benefits Obligations

For the ~~nine~~three months ended ~~June 30,~~December 31, 2017 and 2016, our total net periodic pension and other benefits costs were ~~$34.7~~$9.2 million and ~~$34.5~~$11.6 million. A substantial portion of those costs ~~relating to our natural gas distribution operations are~~is 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 ~~2017~~2018 costs were determined using a September 30, ~~2016~~2017 measurement date. As of September 30, ~~2016,~~2017, interest and corporate bond rates were ~~lower~~higher than the rates as of September 30, ~~2015.~~2016. Therefore, we ~~decreased~~increased the discount rate used to measure our fiscal ~~2017~~2018 net periodic cost from ~~4.55~~3.73 percent to ~~3.73~~3.89 percent. We ~~maintained~~lowered the expected return on plan assets ~~of 7.00~~to 6.75 percent in the determination of our fiscal ~~2017~~2018 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 ~~2017~~2018 net periodic pension cost to be ~~generally consistent with~~approximately 25 percent lower than fiscal ~~2016.~~2017.

The amount ~~with which we fund~~of funding required for our defined benefit plan is determined in accordance with the Pension Protection Act of 2006 (PPA) and is influenced by the funded position of the plan when the funding requirements are determined on January 1 of each year. Based upon the determination as of January 1, 2017, we ~~are~~were not required to make a minimum contribution to our defined benefit plan during the first quarter of fiscal ~~2017.~~2018. However, ~~in June 2017,~~ we ~~made~~will consider whether a voluntary contribution ~~of $5.0 million.~~is prudent to maintain certain funding levels.

For the ~~nine~~three months ended ~~June 30,~~December 31, 2017 we contributed ~~$9.9~~$3.9 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal ~~2017.~~

2018.

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 distribution and pipeline and storage segments for the ~~three and nine-month~~three-month periods ended ~~June 30,~~December 31, 2017 and 2016.

Distribution Sales and Statistical Data


	Three Months Ended June 30				Nine Months Ended June 30				Three Months Ended December 31
	2017		2016		2017		2016		2017		2016
METERS IN SERVICE, end of period
Residential	2,935,136		2,903,099		2,935,136		2,903,099		2,956,247		2,923,480
Commercial	268,734		266,435		268,734		266,435		270,184		268,574
Industrial	1,682		1,815		1,682		1,815		1,675		1,693
Public authority and other	8,301		8,377		8,301		8,377		8,418		8,359
Total meters	3,213,853		3,179,726		3,213,853		3,179,726		3,236,524		3,202,106

INVENTORY STORAGE BALANCE — Bcf	50.4		51.3		50.4		51.3		55.6		56.7
SALES VOLUMES — MMcf⁽¹⁾
Gas sales volumes
Residential	17,137		16,407		115,568		125,334		48,948		41,500
Commercial	15,960		14,718		71,435		73,990		26,949		23,736
Industrial	8,719		6,728		22,859		22,618		8,458		7,432
Public authority and other	1,158		1,187		5,296		5,722		1,952		1,762
Total gas sales volumes	42,974		39,040		215,158		227,664		86,307		74,430
Transportation volumes	35,020		33,367		116,227		112,477		39,859		39,065
Total throughput	77,994		72,407		331,385		340,141		126,166		113,495
OPERATING REVENUES (000’s)⁽¹⁾
Gas sales revenues
Residential	$	294,000	$	260,634	$	1,385,444	$	1,240,184	$	556,520	$	481,673
Commercial	136,611		113,075		588,273		507,580		223,580		200,488
Industrial	28,150		19,766		106,167		74,167		33,413		30,031
Public authority and other	8,591		7,309		38,307		34,402		13,561		12,109
Total gas sales revenues	467,352		400,784		2,118,191		1,856,333		827,074		724,301
Transportation revenues	20,439		18,097		67,227		60,202		25,362		22,481
Other gas revenues	6,269		6,024		25,839		19,940		8,356		7,874
Total operating revenues	$	494,060	$	424,905	$	2,211,257	$	1,936,475	$	860,792	$	754,656
Average cost of gas per Mcf sold	$	4.60	$	3.78	$	5.14	$	4.01	$	5.37	$	5.31

See footnote following these tables.

Pipeline and Storage Operations Sales and Statistical Data


	Three Months Ended June 30				Nine Months Ended June 30				Three Months Ended December 31
	2017		2016		2017		2016		2017		2016
CUSTOMERS, end of period
Industrial	92		90		92		90		93		90
Other	239		214		239		214		240		222
Total	331		304		331		304		333		312

INVENTORY STORAGE BALANCE — Bcf	1.1		2.4		1.1		2.4		1.1		1.7
PIPELINE TRANSPORTATION VOLUMES — MMcf⁽¹⁾	192,543		158,758		574,556		526,532		213,137		186,780
OPERATING REVENUES (000’s)⁽¹⁾	$	117,283	$	113,855	$	339,207	$	314,424	$	126,463	$	109,952

Note to preceding tables:


⁽¹⁾	Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.

RECENT ACCOUNTING DEVELOPMENTS

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



Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A ~~of Exhibit 99.1 to~~in our ~~Current~~Annual Report on Form ~~8-K dated April 12,~~10-K for the fiscal year ended September 30, 2017. During the ~~nine~~three months ended ~~June 30,~~December 31, 2017, ~~except for the effects of the sale of AEM on our market risk,~~ 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,~~December 31, 2017 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~~first quarter of the fiscal year ended September 30, ~~2017~~2018 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~~three months ended ~~June 30,~~December 31, 2017,, there were no material changes in the status of the litigation and other matters that were disclosed in Note 11 ofto our ~~Fiscal 2016 Financial Statements.~~Annual Report on Form 10-K for the fiscal year ended September 30, 2017. 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/ CHRISTOPHER T. FORSYTHE
			Christopher T. Forsythe Senior Vice President and Chief Financial Officer (Duly authorized signatory)

Date: ~~August 2, 2017~~February 6, 2018

EXHIBITS INDEX

Item 6



Exhibit Number	Description	Page Number or Incorporation by Reference to
2.1	Membership Interest Purchase Agreement by and between Atmos Energy Holdings, Inc. as Seller and CenterPoint Energy Services, Inc. as Buyer, dated as of October 29, 2016	Exhibit 2.1 to Form 8-K dated October 29, 2016 (File No. 1-10042)
10	Equity Distribution Agreement, dated as of ~~March 28, 2016,~~November 14, 2017, among Atmos Energy Corporation, Goldman Sachs & Co., LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, ~~and~~ Morgan Stanley & Co. ~~LLC.~~LLC, and J.P. Morgan Securities LLC	Exhibit 1.1 to Form 8-K dated ~~March 28, 2016~~November 14, 2017 (File No. 1-10042)
12	Computation of ratio of earnings to fixed charges
15	Letter regarding unaudited interim financial information
31	Rule 13a-14(a)/15d-14(a) Certifications
32	Section 1350 Certifications*
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.

5542




	Nine Months Ended June 30, 2017
	Distribution		Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	2,210,221	$	84,634		$	—	$	—		$	2,294,855
Intersegment revenues	1,036		254,573			—		(255,609		)	—
Total operating revenues	2,211,257		339,207			—		(255,609		)	2,294,855
Purchased gas cost	1,106,209		2,331			—		(255,565		)	852,975
Operation and maintenance expense	296,048		89,863			—		(44		)	385,867
Depreciation and amortization expense	185,219		49,429			—		—			234,648
Taxes, other than income	165,032		20,579			—		—			185,611
Operating income	458,749		177,005			—		—			635,754
Miscellaneous income (expense)	334		(784		)	—		—			(450		)
Interest charges	56,437		30,035			—		—			86,472
Income from continuing operations before income taxes	402,646		146,186			—		—			548,832
Income tax expense	149,623		52,351			—		—			201,974
Income from continuing operations	253,023		93,835			—		—			346,858
Income from discontinued operations, net of tax	—		—			10,994		—			10,994
Gain on sale of discontinued operations, net of tax	—		—			2,716		—			2,716
Net income	$	253,023	$	93,835		$	13,710	$	—		$	360,568
Capital expenditures	$	636,449	$	175,699		$	—	$	—		$	812,148




	Nine Months Ended June 30, 2016
	Distribution		Pipeline and Storage			Natural Gas Marketing		Eliminations			Consolidated
	(In thousands)
Operating revenues from external parties	$	1,935,421	$	85,584		$	—	$	—		$	2,021,005
Intersegment revenues	1,054		228,840			—		(229,894		)	—
Total operating revenues	1,936,475		314,424			—		(229,894		)	2,021,005
Purchased gas cost	912,231		(72		)	—		(229,894		)	682,265
Operation and maintenance expense	294,154		84,919			—		—			379,073
Depreciation and amortization expense	174,748		40,179			—		—			214,927
Taxes, other than income	153,198		18,761			—		—			171,959
Operating income	402,144		170,637			—		—			572,781
Miscellaneous income (expense)	804		(894		)	—		—			(90		)
Interest charges	57,481		27,294			—		—			84,775
Income from continuing operations before income taxes	345,467		142,449			—		—			487,916
Income tax expense	126,090		51,134			—		—			177,224
Income from continuing operations	219,377		91,315			—		—			310,692
Income from discontinued operations, net of tax	—		—			5,172		—			5,172
Net income	$	219,377	$	91,315		$	5,172	$	—		$	315,864
Capital expenditures	$	528,063	$	261,446		$	179	$	—		$	789,688





Division	State	Increase in Annual Operating Income		Effective Date
	(In thousands)
2017 Rate Case Filings:
Kentucky/Mid-States ⁽¹⁾	Virginia	$	6	12/27/2016
Total 2017 Rate Case Filings		$	6




Division	Jurisdiction	Rate Activity	Additional Annual Operating Income		Effective Date
		(In thousands)
2017 Other Rate Activity:
Colorado-Kansas	Kansas	Ad-Valorem⁽¹⁾	$	784	2/1/2017
Total 2017 Other Rate Activity			$	784